Annual General MeetingMay 7, 2015

Future Oriented Information(See additional advisories at the end of this document)

• In the interest of providing information regarding Paramount Resources Ltd. ("Paramount" or the "Company"), including management's assessment of the Company's future plans and operations, this presentation contains certain forward-looking information and forward-looking statements.

• The projections, estimates and beliefs contained in such forward-looking information and statements necessarily involve a number of assumptions and are subject to known and unknown risks and uncertainties which may cause the Company's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. The material assumptions, risks and uncertainties are referred to in the advisories contained in the Advisories Appendix.

• Accordingly, shareholders and potential investors are cautioned that events or circumstances could cause actual results to differ materially from those predicted.

• Any use of information contained within this presentation is expressly forbidden.

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• Founded in 1974; IPO in 1978• TSX: POU • Market Cap: 106.2 MM shares @ $33.00/share ~ $3.5 Billion• ~50% insider ownership• Net Debt (March 31, 2015): $1.7 Billion • 2015 Capital Guidance: $400 MM

Low Risk/Repeatable Growth

Operations focused on large-scale Deep Basin development• Large contiguous acreage• Multi-zone potential• High condensate/gas ratios• Owned and firm service access to infrastructure

Significant near-term growth in production and cash flow• Surpass 70,000 Boe/d in 2015 following startup of

condensate stabilizer expansion • Average 55,000 to 65,000 Boe/d for 2015• Production mix evolving to ~50% liquids

Exposure to emerging plays and Strategic Investments• Duvernay• Oil sands• Liard Basin shale gas

Corporate Profile

(1) Average sales volumes for the first quarter of 2015

Corporate Profile

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Deep Basin Resource

*Graphic courtesy of www.canadianoilstocks.ca

• Deep Basin liquids-rich gas resources in multiple stacked horizons

• 40-160 Bcf/section DGIIP (1)

• ~5+ Bcf EUR/Hz well (1)

• >10 Tcf DGIIP + NGLs net to POU (1)

Paramount Acreage (gross):• 544 Sections Cretaceous Rights• 364 Sections Montney Rights• 249 Sections Duvernay Rights

• Liquids-rich Montney gas play• ~70+ Bcf/section DGIIP (1)

• ~ 22 Tcf DGIIP + NGLs net to POU (1)

• Potential conventional Devonian exploration• Potential Duvernay Shale rock play

(1) Internal estimates: EUR denotes Estimated Ultimate Recovery, DGIIP denotes Discovered Gas Initially In Place. Please refer to "Oil and Gas Measures and Definitions" in the Advisories section of this presentation for further information. 4

Cretaceous Gas Resource

• Hz Falher well at Musreau• Tested 16.4 MMcf/d(1) at

20.8 MPa• IP: 12.0 MMcf/d• Currently producing

~2.0 MMcf/d • Cost: $8.6 MM d/c/t

• Hz Dunvegan well at Resthaven

• Tested 11.3 MMcf/d(1) at 6.2 MPa

• IP: 8.3 MMcf/d• Currently producing

~1.1 MMcf/d • Cost: $8.3 MM d/c/t

(1) Please refer to the heading "Test Results" in the Advisories section of this presentation for further information 5

Cretaceous Economics

AssumptionsCapital: $7.0 MM horizontal wellIP: 9.0 MMcf/dNatural Gas (raw): 4.9 Bcf Raw Condensate Gas Ratio: 17 Bbl/MMcfC2-C4 NGLs: 61 Bbl/MMcf Deep Cut Facility

Economics : $2.75 AECO, US$55.00 WTI (Deep-Cut)NPV 10%: $2.5 MMIRR: 31%Payout (Months): 30P/I: 1.7

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Montney Gas Resource

Liquids-rich Montney gas playParamount holds ~315 net sections of Montney rights2011/2012 program included 16 Hz Montney wells: tested 5.5-15.4 MMcf/d(1)

Montney 2013 program: Drilled 15 wells; commenced drilling 25 additional wells off 3 pads in Musreau; participated in 5 non-op Montney wells in Karr34 Montney wells rig released in 2014 including 23 pad wells at Musreau; participated in 2 non-op Montney wells in Karr3-20 10-well pad at Musreau completed in Q3 2014 with combined test rates of 108 MMcf/d + NGLs(1)

8-22 10-well pad at Musreau completed in Q4 2014 with combined test rates of 130 MMcf/d + NGLs(1)

Two new 6-well pads at Musreau rig released in March 2015

(1) Please refer to the heading "Test Results" in the Advisories section of this presentation for further information 7

Montney Economics

AssumptionsCapital: $10.0 MM horizontal wellIP: 5.8 MMcf/dNatural Gas (raw): 3.0 Bcf Raw Condensate Gas Ratio (CGR): 150 Bbl/MMcf (50 Bbl/MMcf - 400 Bbl/MMcf) C2-C4 NGLs: 90 Bbl/MMcf Deep Cut Facility

Economics @ $2.75 AECO, US$55.00 WTI (Deep Cut)NPV 10%: $7.7 MMIRR: 56%Payout (Years): 1.8P/I: 1.8

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Montney Drilling/Completion Improvements

• Pad drilling/pad layout• Bits/muds/motors• Well design:

monobores/orientation/reservoir placement• Toe up/toe down: effects on production• Natural gas fueled rigs• Plug and perf/sliding sleeves• Cemented liners/open-hole packers (ECP’s)• Frac sizing/spacing/clusters• Frac fluid selection/fluid handling• Pumping techniques• Frac fluid recycling• Proppants• Flow back/production practices• Working with material and service providers

to reduce costs

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Deep Basin Processing Capacity (1)

10(1) Please refer to the heading “Deep Basin Processing Capacity” in the Advisories section for further information.

Musreau 8-13 Complex

October 13, 2014

200 MMcf/d x 23% Shrinkage = 154 MMcf/d Sales Gas (25,667 Boe/d) + 22,000 Bbl/d condensate + 18,000 Bbl/d NGLs

Price

Deep-Cut Sales Gas $2.75/McfYield Bbl/MMcf

154 MMcf/d $423,500

Condensate $65.00/Bbl 110 22,000 Bbl/d $1,430,000

Butane $35.00/Bbl 12.5 2,500 Bbl/d $87,500

Propane $10.00/Bbl 25 5,000 Bbl/d $50,000

Ethane $10.00/Bbl 52.5 10,500 Bbl/d $105,000

Total: 65,667 Boe/d $2,096,000/day

Royalty 5% ($104,800/day)

Operating Cost ($3.00/Boe) ($197,000/day)

Total: 24.0 MMBoe/year$1,794,200/day$655 MM/year

$27.29/Boe

Illustrative Deep-Cut - Montney Wells

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Resource Needed:200 MMcf/d x 365 ~ 73 Bcf/year x 10 year RLI = 730 Bcf

70 Bcf/section @ ~ 50% recovery = ~ 20 Sections

Cost60 (5 MMcf/d wells) x $10 MM/well = $600 MM

Gas Plant = $250 MM

Total: $850 MM

Annual Deep - Cut Cash Flow $655 MM/year

Annual Capital = 25 (3.0 Bcf) wells x $10 MM/well $250 MM/year

Free Cash Flow $405 MM/year

Paramount Deep-Cut Montney - Illustrative Project Economics

• Paramount’s shallow rights will add substantially to the RLI

• Paramount has de-risked a substantial amount of its land base and thus could have the potential to add a series of refrigeration or deep cut plants

• Simple Payout from free cash flow after start up is less than two years

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Willesden Green

Duvernay Shale Play 64,452 (34,305 net) acres of land

when earning complete Drilled and completed 2 (1.5 net)

Hz Duvernay wells to date:Well #1: > 1,000 Bbl/MMcfWell #2: > 200 Bbl/MMcf

Drilled 1 (0.5 net) additional Hz Duvernay well in Q1 2015; completion Q2 2015

(1) Includes Duvernay lands to be earned

Paramount has explored for ideal combinations of rock quality/liquids ratio/pressure gradient

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Montney

• Montney shale play (50% WI)

• Seven Hz Montney wells

• Production has been processed through pilot facility limited to 3 MMcf/d

• NGL yields average 60 Bbl/MMcf

• Montney/Doig Play

• 16 wells tied in at restricted rates (midstream constraints)

• Montney wells tested 3.0 - 12.5 MMcf/d + NGLs/Condensate(1)

• Doig wells tested 2.5 - 15 MMcf/d + NGLs/Condensate(1)

• Evaluating long term production/economics to determine future investment levels

Valhalla: ~65 sections (~49 net) Montney/~67 sections (~34 net) Doig rights

Birch: ~67 sections (~34 net) Montney rights

(1) Please refer to the heading "Test Results" in the Advisories section of this presentation for further information(2) Based on results from Paramount's wells and publicly disclosed results of competitor wells.

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Paramount Investments

Paramount Investments

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Cavalier Energy Inc.

Cavalier Energy Inc.

• Approximately 345 (net) sections • Prospective primarily for conventional

oilsands, bitumen in carbonates, and cold-flow heavy oil

• Hoole Project: 100% WI

(1) Resource estimates are Best Estimates based on McDaniel independent engineering reports dated as of October 31, 2011 for Saleski, House, Granor and Orchid; April 30, 2010 for Eagles Nest; and December 31, 2014 for Hoole. Please refer to "Oil Sands Measures and Definitions" in the Advisories section of this presentation for oil sands reserves, resources and related definitions (including NPV).

• Created in December 2011; experienced team led by CEO Dr. Will Roach

• Paramount contributed its oilsands assets and seed capital to Cavalier

• Funding at the Cavalier level will be via a combination of equity and debt

• Assets retained as 100% WI within Cavalier Energy

• Regulatory approval for the development of the first 10,000 Bbl/d SAGD project at Hoole received June 2014

Corporate Profile

Corporate Resources

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250

275

Kgrand_rp

Kjoli_fou

Hoole Grand Rapids - 1st Project

Grand Rapids Reservoir• Φ = 30 %, k = 1 to 4 D• d = 250m, h ~ 20m, p = 1,500 kPa• Viscosity = 200,000 to 2,000,000 cp• McDaniel Best Estimate: DEBIP = 2.5 Billion Bbl(1)

• 80 wells drilled to date; 42 cored• 93 Million Bbl Probable Undeveloped Reserves

and 1,157 Million Bbl Best Estimate Contingent Resource(1)

• Probable Reserves NPV BT 10%: $363 Million(1)

• Contingent Resource Best Estimate NPV BT 10%: $2.4 Billion(1)

(1) Independent evaluation by McDaniel & Associates Consultants Ltd. effective December 31, 2014Please refer to "Oil Sands Measures and Definitions" in the Advisories section of this presentation for oil sands reserves, resources and related definitions

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Liard BasinShale Gas

(1) As publicly disclosed by a large U.S. public E&P company with significant landholdings in the Liard Basin. The resource evaluation disclosed by such E&P company was not noted as having been prepared independently or by a qualified reserves evaluator or auditor (as such terms are defined in NI 51-101) or in accordance with the COGE Handbook. This information is relevant to Paramount’s landholdings in the Liard Basin as the information is in respect of landholdings in the Liard Basin that are close to Paramount’s lands and are, accordingly, likely to have similar geology.

Liard Basin

Besa River Shale Play• Drilled and completed b-40-I • Completion of d-57-D horizontal

deferred as land earning completed• Completed drilling d-71-G• Spud c-37-D at La Biche• Liard Basin industry estimates(1):

• 170-500 Bcf/section OGIP• ~20% expected recovery• ~34-100 Bcf sales gas/section

• Paramount holds ~133 net sections with production potential from the Besa River shale gas formation

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Mackenzie Delta• Land holdings ~ 300,000 (155,000 net) acres• Contingent Resources 473 Bcf (1)

Central Mackenzie• Land holdings ~1,300,000 (725,000 net) acres• Nogha Contingent Resources 92 Bcf (1)

Canol Resource Summary• Discovered Oil Initially-In-Place ("DOIIP") 625 MMBbl (2)

• Undiscovered Oil Initially-In-Place ("UOIIP") 4,800 MMBbl (2)

MGM Energy

(1) Contingent resource estimates are Best Estimates based on internal engineering studies completed by qualified reserves evaluators and audited by a qualified reserves auditor as of December 31, 2007 for Olivier, Langley, Ellice, Nogha and Umiak and as of March 16, 2009 for Qavvik. Refer to "Oil and Gas Measures and Definitions" in the advisories section of this presentation for further information. (2) Estimates of DOIIP and UOIIP are based on internal engineering studies completed by qualified reserves evaluators as of December 31, 2013. These estimates include adjustments for working interest, but not for royalties or other encumbrances and reflect the mean volume of OIIP from the probabilistic assessment of oil that is in place. Refer to "Oil and Gas Measures and Definitions" in the advisories section of this presentation for further information.

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Quarterly Operating Results

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Conventional Reserves

Columns may not add due to rounding. Conventional reserves only. Includes nominal amounts of estimated reserves in respect of Paramount's initial shale gas well at Patry, B.C. Reserves evaluated by McDaniel &Associates Consultants Ltd. in accordance with National Instrument 51-101 definitions, standards and procedures.

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Summary

Exposure to significant reserve opportunities Deep Basin: Cretaceous, Montney Valhalla: Montney, Doig Birch: Montney Willesden Green: Duvernay

Significant asset value Trilogy MEG Energy Cavalier Energy Liard Shale Gas

Paramount continues to provide long-term value creation for shareholders

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ADVISORIES APPENDIX

AdvisoriesForward-Looking InformationCertain statements in this presentation constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward looking information in this presentation includes, but is not limited to:

projected production and sales volumes including the liquids component thereof; forecast capital expenditures; exploration, development and associated operational plans and strategies (including planned drilling and completion programs, well tie ins and potential facility expansions and additions and the anticipated timing of such activities); projected timelines for, constructing, commissioning and/or starting-up new and expanded natural gas processing and associated facilities, and the Company's Deep Basin processing capacity following the completion of these facilities; reserves and resources estimates (including internal estimates of DGIIP, EUR , DOIIP, UOIIP and contingent resources related to Paramount's properties and estimated net present values of reserves and resources); illustrative deep-cut project economics (including the commodity price, royalty rate, capital and operating cost, production volume, NGLs yield, well reserves, reserve life index, cash flow and payout assumptions used therein); Paramount’s potential ability to build and utilize additional processing facilities; projected type well production profiles and associated net present value, internal rate of return and payout estimates (and the initial production rate, reserves, capital and operating cost, shrinkage, NGLs yield and NGLs pricing assumptions used to generate such profiles and estimates); and general business strategies and objectives.

Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this presentation or Paramount’s continuous disclosure documents:

future natural gas, natural gas liquids (including condensate), oil and bitumen prices; royalty rates, taxes and capital, operating, general & administrative and other costs; foreign currency exchange rates and interest rates; general economic and business conditions; the ability of Paramount to obtain the required capital to finance its exploration, development and other operations; the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities; the ability of Paramount to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; the ability of Paramount to market its natural gas, natural gas liquids, oil and bitumen successfully to current and new customers; the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions and liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations; the timely receipt of required governmental and regulatory approvals; and anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins and the construction, commissioning and start-up of new and expanded facilities).

Although Paramount believes that the expectations reflected in such forward looking information are reasonable, undue reliance should not be placed on them as Paramount can give no assurance that such expectations will prove to be correct. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information. These risks and uncertainties include and/or relate (but are not limited) to:

fluctuations in natural gas, natural gas liquids, oil and bitumen prices; changes in foreign currency exchange rates and interest rates; the uncertainty of estimates and projections relating tofuture revenue, future production, reserve additions, liquids (including condensate and natural gas ratios), resources recoveries, yields, royalty rates, taxes and costs and expenses; the ability to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; operational risks in exploring for, developing and producing natural gas, natural gas liquids, oil and bitumen; the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost; potential disruptions or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third party facilities); industry wide processing, pipeline, de-ethanization, and fractionation infrastructure outages, disruptions and constraints; risks and uncertainties involving the geology of oil and gas deposits; the uncertainty of reserves and resources estimates (including internal estimates of DGIIP, EUR, DOIIP, UOIIP and contingent resources); the ability to generate sufficient cash flow from operations and obtain financing at an acceptable cost to fund planned exploration, development and operational activities and meet current and future obligations (including costs of anticipated new and expanded facilities and other projects and product processing, transportation, de-ethanization, fractionation and similar commitments); changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); the ability to obtain required governmental or regulatory approvals in a timely manner and to enter into and maintain leases and licenses; general business, economic and market conditions; the effects of weather; the timing and costs of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders; theoutcome of existing and potential lawsuits, regulatory actions, audits and assessments; and other risks and uncertainties described elsewhere in this presentation and in Paramount’s filings with Canadian securities authorities, including its Annual Information Form.

The foregoing list of risks is not exhaustive. Additional information concerning these and other factors which could impact Paramount are included in Paramount’s most recent Annual Information Form. The forward-looking information contained in this presentation is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.

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Advisories cont’d

Oil and Gas Measures and DefinitionsThis presentation contains disclosure expressed as "Boe" and "Boe/d". All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2015, the value ratio between condensate and oil and natural gas was approximately 16:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.This presentation contains internal estimates of DGIIP and EUR in respect of the Company’s Deep Basin area lands and DOIIP and UOIIP in respect of the Company’s Mackenzie Valley lands. DGIIP means that quantity of gas that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DGIIP includes production, reserves and contingent resources; the remainder is unrecoverable. DGIIP is the most specific category that could be assigned to the applicable gas resource. There is no certainty that it will be commercially viable to produce any portion of this DGIIP. EUR means those quantities of oil or gas which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities of oil or gas already produced therefrom. DOIIP and UOIIP mean that quantity of oil that is estimated, as of a given date, to be contained in known accumulations prior to production. There is no certainty that it will be commercially viable to produce any portion of the resources. DOIIP is the most assignable category for the resources assigned to EL 466 as a well specifically targeting the Canol shale oil play has been drilled, however, there is insufficient data to determine an expected recovery factor and therefore a contingent or prospective resource or reserve amount cannot be estimated. UOIIP is the most assignable category to the remaining Mackenzie Valley Canol oil leases as no wells specifically targeting the Canol shale oil play have been drilled on these exploration licenses. Also, there is insufficient data to determine an expected recovery factor and therefore a contingent or prospective resource or reserve amount cannot be estimated. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Paramount has provided information with respect to certain of its plays and emerging opportunities which is “analogous information” as defined in NI 51-101. This analogous information includes Paramount's internal estimates of DGIIP, DOIIP, UOIIP or EUR, all as defined in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) or by the Society of Petroleum Engineers -Petroleum Resources Management System (“SPE-PRMS”), and/or production type curves in respect of proved plus probable reserves. This analogous information is presented on a basin, sub-basin or area basis utilizing data derived from Paramount's internal sources, as well as from a variety of publicly available information sources which are predominantly independent in nature. These internal estimates are subject to the specific assumptions identified by Paramount in respect of such estimates plus other assumptions contained herein and are not determinative of the actual resources or production rates associated with Paramount's properties and wells.“Contingent Resources” in respect of the Company’s Mackenzie Delta lands the means those quantities of natural gas estimated on a given date to be potentially recoverable from known accumulations but are not currently economic due to: (i) lack of pipeline infrastructure, making the project uneconomic on a stand-alone basis; (ii) potential regulatory issues with respect to the construction of the pipeline and facility infrastructure; (iii) lack of demonstrated intent to bring the volumes to market within a specific time frame; and (iv) insufficient drilling or technical data to accurately estimate total pool productivity.Conventional reserve estimates include nominal amounts of volumes related to Paramount’s completed shale gas well. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

Non-GAAP MeasuresIn this presentation “Net Debt”, a non-GAAP measure, is used and does not have any standardized meaning as prescribed by GAAP. Net Debt is a measure of a Company's overall debt position after adjusting for certain working capital amounts and is used by management to assess the Company’s overall leverage position. Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.

Test ResultsThe test rates disclosed in this document represent the average rate of gas-flow during post clean-up production testing at the largest choke setting. The flow tests typically range from 4 to 55 hours in duration.

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Advisories cont’d

Pressure transient analyses and well-test interpretations have not been carried out for any of these wells and, as such, all data should be considered preliminary until such analyses or interpretations have been done. Liquids yields have not been included in the Musreau, Resthaven, and Valhalla test results as the bulk of the tested wells were fracture stimulated using frac oil with the result that substantially all liquids recovered during the test period were load fluid. Test results are not necessarily indicative of long-term performance or of ultimate recovery.

Deep Basin Processing Capacity"Deep Basin Processing Capacity" means the aggregate capacity of the Company's owned and firm service natural gas and condensate processing facilities in the Deep Basin. These capacity estimates are subject to a number of assumptions and risks and should not be construed as projections of Paramount's Deep Basin area production volumes at or by any particular date or dates. The Company's net sales volumes will be lower than the capacity shown because of a number of factors including, but not limited to: a) some unavoidably commingled third-party volumes will be processed using Paramount capacity; b) the liquids content of wells will vary; c) production volumes sufficient to fill capacity will not be available in all periods and under certain conditions; and d) during maintenance periods and at other times, the facilities will not operate at design capacity. Capacity increases are shown at the mid-point of the period in which new facilities and facilities expansions are scheduled to be completed. However, the completion of such facilities may occur at any point during such period or may occur in a different period and the actual ramp-up will be different than depicted.

Oil Sands Measures and DefinitionsThis presentation contains disclosure of certain results of (i) an updated independent evaluation by McDaniel of the bitumen reserves and resources of Cavalier Energy Inc.’s (Cavalier) in the Grand Rapids formation in Cavalier’s Hoole oil sands property as of December 31, 2014; (ii) an independent evaluation by McDaniel of Cavalier’s bitumen resources in its Saleski and other carbonate bitumen properties (House, Orchid and Granor) as of October 31, 2011; and (iii) an independent evaluation by McDaniel of Cavalier's bitumen resources in its Eagle Nest oil sands property as of April 30, 2010 (collectively, the McDaniel Evaluations). Specifically, this presentation includes McDaniel’s assessment as of December 31, 2014 of Cavalier’s probable undeveloped reserves, best estimate economic contingent resources and discovered exploitable bitumen in place in the Grand Rapids formation at Hoole (and the estimated net present value of these probable undeveloped reserves and economic contingent resources); McDaniel’s best estimate as of October 31, 2011 of Cavalier’s contingent resources (technology under development) in its Saleski carbonate bitumen property and of the discovered and undiscovered exploitable bitumen in place at Saleski and Cavalier’s other carbonate bitumen properties; and McDaniel's best estimate as of April 30, 2010 of Cavalier's discovered and undiscovered bitumen in place in its Eagle's Nest property. These terms, as used in the McDaniel Evaluations, have the following meanings:“Probable reserves” are reserves that are less certain to be recoverable than proved reserves. Specifically, whereas proved reserves are reserves that can be estimated with a high degree of certainty to be recoverable (i.e. it is likely that the actual remaining quantities recovered will exceed the estimated proved reserves), in the case of probable reserves it is equally likely that the actual quantities recovered will be greater or less than the estimated probable reserves (or where there are both proved and probable reserves the sum of the estimated proved plus probable reserves). "Contingent resources" are those quantities of bitumen resources estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are classified as resources rather than reserves due to one or more contingencies, such as the absence of regulatory applications, detailed design estimates or near term development plans. "Economic contingent resources" are a sub-category of contingent bitumen resources that are considered to be currently economically recoverable based on the reserves evaluator’s then current forecasts of commodity prices and costs. At Hoole, a portion of Cavalier’s economic contingent resources were re-classified by McDaniel as probable reserves in McDaniel's evaluation effective as of December 31, 2012 by virtue of Cavalier having finalized its plans for a pilot project and submitted a regulatory application for this pilot project. Cavalier will need to finalize plans for the commercial development of the balance of the Hoole oil sands properties and submit regulatory applications for their development before the balance of Cavalier's contingent resources at Hoole can be re-classified as probable reserves. These same contingencies will also have to be overcome in the case of the Saleski carbonate bitumen property in order for Cavalier’s contingent resources in this property to be re-classified as probable reserves. In addition, as sustained commercial production has not yet been obtained from any carbonate bitumen reservoirs, it will also be necessary in the case of the Saleski property to demonstrate the successful application of SAGD or other production technology to the Saleski reservoir (or a reasonable analog thereof). It is for this reason that Cavalier’s bitumen resources at Saleski are referred to as “contingent resources (technology under development)”. There is no certainty that it will be commercially viable to produce any portion of Cavalier’s contingent resources at either Hoole or Saleski.

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Advisories cont’d"Discovered bitumen in place" or "DBIP" (equivalent to discovered resources) is the aggregate quantity of bitumen that is estimated, as of a given date, to be contained in a known accumulation prior to production. To qualify as “discovered exploitable bitumen in place" or "DEBIP" these volumes must be contained in a reservoir that meets or exceeds certain characteristics, such as minimum continuous net pay, porosity and mass bitumen content. DBIP or DEBIP volumes that are considered to be recoverable as of a given date are classified as reserves or contingent resources (with the remaining DBIP or DEBIP volumes being those that are considered to be unrecoverable as of that date).

"Undiscovered bitumen in place" or "UDBIP" (equivalent to undiscovered resources) is the aggregate quantity of bitumen that is estimated, as of a given date, to be contained in accumulations that have yet to be discovered. To qualify as “undiscovered exploitable bitumen in place” or "UDEBIP" these volumes must have been mapped using known data points penetrating the applicable subsurface stratigraphic intervals and possess definitive geophysical log data along with seismic data and regional mapping.

At Hoole, DEBIP volumes have been ascribed by McDaniel to those portions of the Grand Rapids formation where they felt minimum continuous net pay, porosity, mass bitumen content and other reservoir characteristics allowed for the commercial application of known recovery technologies.

For Saleski and the other carbonate bitumen properties, DEBIP volumes have been restricted to those portions of the reservoirs that have a minimum thickness of 10 meters of substantially clean, continuous predominantly bitumen-saturated carbonate with log porosity of at least 10 percent and bitumen saturation greater than 50 percent, and with competent top and lateral reservoir containment. In addition, DEBIP volumes have generally been limited to areas within one mile of known data points that penetrate the applicable stratigraphic intervals and possess definitive geophysical log data. However, in certain circumstances DEBIP volumes have been assigned to areas outside these one mile limits were it was felt that reservoir continuity existed between offsetting data points.

There is no certainty that it will ever be commercially viable to produce any portion of: (i) the DEBIP at Hoole or at Saleski or any of the other carbonate bitumen properties; or (ii) the DBIP at Eagles Nest. There is also no certainty that any of the UDEBIP at Saleski and the other carbonate bitumen properties, or the UDBIP at Eagles Nest, will ever be discovered, or if it is discovered that it will ever be commercially viable to produce any portion of it.

"Best estimate" is considered to be the best estimate of the quantity of contingent resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate (or stated another way, there is a 50 percent confidence level that the actual quantities recovered will equal or exceed the best estimate amount).

“Net present value” or “NPV” of Cavalier’s probable undeveloped reserves and economic contingent resources at Hoole represents McDaniel’s estimates of Cavalier’s share of future net revenues, before the deduction of income taxes, from these reserves and resources discounted at 10%. In calculating these NPVs McDaniel considered items such as revenues, royalties, operating costs, abandonment costs and capital expenditures (but excluded financing and general and administrative costs). Their calculations assume natural gas is used as a fuel for steam generation, and are based on their forecast commodity prices as of January 1, 2015 and forecast costs as of December 31, 2014. Royalties were calculated based on Alberta’s Royalty Framework applicable to oil sands projects. McDaniel’s estimated NPVs do not represent fair market value.

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