CORPORATE PRESENTATIONSeptember 2019

The Leucrotta Montney Project is a development-ready large-scale project focused predominantly in the High GOR Light Oil window of the Montney. The Project includes over 1,000 locations (Upper and Lower Montney) across 140 contiguous sections of land with an estimated:

• 4.5 billion barrels of oil and 7.3 trillion cubic feet of gas in place• Project life of over 50 years with a 25-year average production of 92,000 boepd (35% oil and ngls)• Recovery of over 1.1 billion boes including:

• 111 million barrels of light oil (only 2.5% of oil in place)• 267 million barrels of ngls including 46 million barrels of C5+• 735 million boes of natural gas (4.4 trillion cubic feet)

• $4.6 billion of capital invested with an average internal rate of return of 86%• $32 billion of free cash flow(1) generated• Maximum cash deficit of Project of $235 million• Annual free cash flow of $800 million for 25 years during the peak of the 50-year Project life

The Project also has the following favourable characteristics:• Excellent access to takeaway with multiple options (NGTL, Westcoast, Alliance)• Year-round surface access (farming and ranchlands)• Access to services in close proximity (Fort St. John, Dawson Creek, Grand Prairie)

LeucrottaSmall Company - Big Project

2

(1) Free Cash Flow is defined as revenues less royalties, operating expenses, transportation and marketing expenses and capital expenditures and does not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. The Company uses this measure to help evaluate its performance and return on capital expenditures. All dollar figures presented above are undiscounted.

Montney Oil Window

LXE

AlbertaBC• Leucrotta is one of the few companies with a significant contiguous land position within the Montney over-pressured light oil window

3

Lower Montney Turbidite Play

LegendLeucrotta Land

Cum Lower Montney Production

Leucrotta Status• 8 Hz light oil wells at Mica on

production

• 4 Hz liquids rich gas wells at Doe on production

• 434 vertical wells petro-physically analyzed

• Over 650 locations delineated

P. Coupe

Sunrise

Doe

AB.

BC

Mica

Two Rivers

Parkland

Gordondale

4

10

100

1000

10000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Boe

Rate

(boe

/d)

Months on Production

Mica GLJ Type CurvesGLJ YE 2018 (41 Stg)LXE Type (52 Stg)8-22 Actual (26stg)9-33 Actual (52stg)A8-22 Actual (41 Stg)13-7 Actual (30 stg)

Lower Montney High GOR Light Oil Type Curve

28 Stage

52 Stage

41 Stage

5

Highlights:• Well progression from 28 to 52 frac stages per well has yielded material increases in production and estimated recoveries• GLJ has used 41 stage curve for average booking in 2018 reserve report

Lower Montney High GOR Light Oil Metrics

Economics based on a Jan 2019 start date using GLJ Q1 2019 price forecast ($US 56.25/bbl WTI; $1.75/GJ AECO; FX 1.33 for 2019). (1) Economics are half-cycle assuming LXE interim development with current commercial arrangement (25 bbl/mmscf C3+ liquid recovery).(2) Economics are half-cycle assuming large scale development through a deep cut gas plant (58 bbl/mmscf C3+ liquid recovery).

6

Highlights:• Light oil and C5+ recoveries estimated at 208,000 bbls per well (2)• Additional 740,000 boes of gas and ngls (C3 and C4) recoverable per well (2)• Internal rate of return of 97% (2)

Drill & Case ($K) 1,700 Year 1 Average boe/d % bbl/mmcf Drill & Case ($K) 1,500 Year 1 Average boe/d % bbl/mmcfComplete ($K) 2,400 Sales Gas 360 67% Complete ($K) 2,100 Sales Gas 344 59%Tie-in ($K) 500 Oil 124 23% 58 Tie-in ($K) 500 Oil 124 21% 60Total ($K) 4,600 Free Condensate 18 3% 8 Total ($K) 4,100 Free Condensate 0 0% 0

C3 25 5% 11 C3 66 11% 32C4 11 2% 5 C4 33 6% 16C5+ 1 0% 1 C5+ 20 3% 10

NPV10 ($K) 6,620 Total 540 100% 84 NPV10 ($K) 8,306 Total 586 100% 117PV10 ($K) 11,220 PV10 ($K) 12,406IRR (%) 67 IRR (%) 97Payout (yrs) 1.7 EUR mboe % bbl/mmcf Payout (yrs) 1.3 EUR mboe % bbl/mmcfF&D ($/boe) 5.29 Sales Gas 601 69% F&D ($/boe) 4.33 Sales Gas 574 61%Cap. Eff. Q-12mo. 8,519 Oil 175 20% 49 Cap. Eff. Q-12mo. 6,984 Oil 175 18% 51($/boe/d) Free Condensate 30 3% 8 ($/boe/d) Free Condensate 0 0% 0

C3 41 5% 11 C3 110 12% 32C4 19 2% 5 C4 55 6% 16C5+ 2 0% 1 C5+ 33 3% 10Total 870 100% 74 Total 947 100% 108

GLJ (1) YE2018 (41 stg) GLJ (1) YE2018 (41 stg) Deep Cut (2) Long Term (41 Stg) Deep Cut (2) Long Term (41 Stg)

Economic Metrics Production Metrics Economic Metrics Production Metrics

Sheet1

Performance IndicatorGLJ (1)LXE (1)Deep Cut (2)Deep Cut (2)

YE2018Interim Long Term Long Term

(41 Stg)(52 Stg)(41 Stg)(52 Stg)

Drill & Case ($K)1,7001,8001,5001,600

Complete ($K)2,4002,9002,1002,600

Tie-in ($K)500500500500

Total ($K)4,6005,2004,1004,700

Year 1 Avg Q (boe/d)

Liquids*180 (33%)264 (32%)243 (41%)360 (41%)

Gas360553344528

Total540817587888

EUR (mboe)

Liquids*268 (31%)312 (30%)373 (39%)437 (39%)

Gas601716574684

Total86910289471121

NPV10 ($K) 6,6209,8568,30611,896

PV10 ($K) 11,22015,05612,40616,596

IRR (%) 6711897170

Payout (yrs)1.71.21.31

F&D ($/boe)5.295.064.334.19

Cap. Eff. Q-12mo. ($/boe/d)8,5196,3656,9845,293

Sheet1 (2)

GLJ (1) YE2018 (41 stg)Deep Cut (2) Long Term (41 Stg)

Economic MetricsProduction MetricsEconomic MetricsProduction Metrics

Drill & Case ($K)1,700Year 1 Averageboe/d%bbl/mmcfDrill & Case ($K)1,500Year 1 Averageboe/d%bbl/mmcf

Complete ($K)2,400Sales Gas36067%Complete ($K)2,100Sales Gas34459%

Tie-in ($K)500Oil12423%58Tie-in ($K)500Oil12421%60

Total ($K)4,600Free Condensate183%8Total ($K)4,100Free Condensate00%0

C3255%11C36611%32

C4112%5C4336%16

C5+10%1C5+203%10

NPV10 ($K) 6,620Total540100%84NPV10 ($K) 8,306Total586100%117

PV10 ($K) 11,220PV10 ($K) 12,406

IRR (%) 67IRR (%) 97

Payout (yrs)1.7EURmboe%bbl/mmcfPayout (yrs)1.3EURmboe%bbl/mmcf

F&D ($/boe)5.29Sales Gas60169%F&D ($/boe)4.33Sales Gas57461%

Cap. Eff. Q-12mo. ($/boe/d)8,519Oil17520%49Cap. Eff. Q-12mo. ($/boe/d)6,984Oil17518%51

Free Condensate303%8Free Condensate00%0

C3415%11C311012%32

C4192%5C4556%16

C5+20%1C5+333%10

Total870100%74Total947100%108

Sheet1 (3)

Economic MetricsProduction MetricsEconomic MetricsProduction Metrics

GLJ (1) YE2018 (41 stg)GLJ (1) YE2018 (41 stg)Deep Cut (2) Long Term (41 Stg)Deep Cut (2) Long Term (41 Stg)

Drill & Case ($K)1,700Year 1 Averageboe/d%bbl/mmcfDrill & Case ($K)1,500Year 1 Averageboe/d%bbl/mmcf

Complete ($K)2,400Sales Gas36067%Complete ($K)2,100Sales Gas34459%

Tie-in ($K)500Oil12423%58Tie-in ($K)500Oil12421%60

Total ($K)4,600Free Condensate183%8Total ($K)4,100Free Condensate00%0

C3255%11C36611%32

C4112%5C4336%16

C5+10%1C5+203%10

NPV10 ($K) 6,620Total540100%84NPV10 ($K) 8,306Total586100%117

PV10 ($K) 11,220PV10 ($K) 12,406

IRR (%) 67IRR (%) 97

Payout (yrs)1.7EURmboe%bbl/mmcfPayout (yrs)1.3EURmboe%bbl/mmcf

F&D ($/boe)5.29Sales Gas60169%F&D ($/boe)4.33Sales Gas57461%

Cap. Eff. Q-12mo. ($/boe/d)8,519Oil17520%49Cap. Eff. Q-12mo. ($/boe/d)6,984Oil17518%51

($/boe/d)Free Condensate303%8($/boe/d)Free Condensate00%0

C3415%11C311012%32

C4192%5C4556%16

C5+20%1C5+333%10

Total870100%74Total947100%108

Upper Montney Play(Initial rates materially above expectations)

Two Rivers

Doe

Mica

Dawson

Tower

Parkland

Pouce Coupe

Sunrise

ABBCA10-8

Leucrotta Activity to Date• 1 Hz light oil well at Two Rivers tested at

1,842 boe/d (37% oil and liquids)

• 1 Hz liquids-rich gas well at Mica tested at 2,700 boe/d (15% oil & liquids)

• 2 Hz liquids-rich gas wells at Doe on production

• 1,157 vertical wells petrophysicallyanalyzed

• Over 350 locations delineated

LegendLeucrotta Land

Cum Upper Montney Production

7

B8-22

Gas Takeaway• Alliance firm transportation to ATP

• 33.3 mmcf/d (2019 to Oct 2020)• Annual renewal rights

• Westcoast pipeline directly offsetting the 13-24 gas plant with available connection to Coastal GasLink

• NGTL mainlines in proximity to Leucrotta land

Liquids Takeaway• Oil and Condensate currently trucked

• Pembina HVP and LVP pipelines directly offsetting the 13-24 gas plant

Legend

Leucrotta 13-24 Gas Plant

Leucrotta Land

BC AB

Takeaway & Marketing(Significant Optionality and Proximity)

8

Leucrotta Infrastructure(development-ready for material production growth)

Infrastructure• 25 mmcf/d sweet gas plant (licensed to

85 mmcf/d)

• 63 mmcf/d Alliance meter station

• Salt water disposal well

• Acid gas injection well

• Two major 8” trunk lines for gathering and future high pressure transportation to the 13-24 gas plant

• 100% ownership/operatorship in all infrastructure

Leucrotta 13-24 Gas Plant

Leucrotta Land

Leucrotta Pipelines

9

Leucrotta Future Pipelines

• Production (Q2 2019) 3,119 boe/d

• Current Oil & Liquid % 28%

• Cash and working capital as of June 30, 2019 $1.6 million

• Debt $nil

• Undrawn bank line $20.0 million

• Shares outstanding (diluted) 200.5 (227.1)

• Officers, directors & 10% insider shareholdings (diluted) 35.4% (40.0%)

Corporate Information

10

Scale – Large contiguous land base with > 1,000 locations

Resource – In excess of 4.5 billion bbls of oil and 7.3 TCF of liquids rich gas in place over 140 section project

High Liquids % – Estimated oil and liquids from Lower Montney are 40% of production (>100 bbl/mmscf) on a development basis

Development Ready - Major field infrastructure in place or licensed, water sources in progress

Egress - Variety of major gas transmission and liquid takeaway options

Why Leucrotta?

11

Management & Directors

Page 12

Directors Management

Robert J. Zakresky, CA Robert J. Zakresky, CA - President and CEO

John A. Brussa, B.A., LL.B. Terry L. Trudeau, P. Eng. - VP Operations and COO

Donald Cowie Nolan Chicoine, MPAcc, CA - VP Finance & CFO

Daryl H. Gilbert, P. Eng. R.D. (Rick) Sereda, M.Sc., P. Geol. - Sr. VP Exploration

Kelvin B. Johnston, P. Geol. Helmut R. Eckert, P. Land - VP Land

Brian Krausert, B.Sc. Peter Cochrane, P. Eng. - VP Engineering

Tom J. Medvedic, CA

Advisories

Page 13

Forward Looking Information

This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, “intends”, “forecast”, “plans”, “guidance” and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this document contains forward looking statements and information relating to the Company’s risk management program, oil, NGLs and natural gas production, capital programs, oil, NGLs, and natural gas commodity prices, and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labour and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company 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, unless so required by applicable securities laws.

Oil and Gas Metrics

OGIP - Original Gas in Place and OOIP - Original Oil in Place are equivalent to Total Petroleum Initially In Place (“TPIIP”) - see definition below. The OGIP and OOIP estimates quoted in this presentation are internal estimates performed by a Qualified Reserves Evaluator (“QRE”) in accordance with the Canadian Oil and Gas Evaluations Handbook (“COGEH”). The effective date of the estimates is December 31 2018.

TPIIP - as defined in the Canadian Oil and Gas Evaluations Handbook (“COGEH”), is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”). 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.

EUR - Estimated Ultimate Recovery is defined as “those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom.”

Boe - Barrel of Oil Equivalent. All boe conversions in the report are derived by converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 Boe: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Readers are cautioned that Boe may be misleading, particularly if used in isolation.

Advisories

Page 14

This presentation contains metrics commonly used in the oil and gas industry, such as “NPV”, “PV”, “IRR”, “Payout”, “F&D” and “Capital Efficiency”. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation should not be unduly relied upon. The following oil and gas metrics have the following meanings as used in this presentation:

NPV - Net Present Value is defined as “the present value of future cash flows minus the initial capital.” PV - Present Value is defined as “the present value of future cash flows.” IRR - Internal Rate of Return. IRR is the discount rate required to arrive at a NPV equal to zero. Rates of return set forth in this presentation are for illustrative purposes. There is no guarantee that such rates of return will be achieved in the future.

Montney Project

The “Leucrotta Montney Project” referenced on page 2 of this presentation is a conceptual development study of Leucrotta’s resources (Prospective and Contingent Resources) of tight oil and shale gas in the Upper and Lower Montney formations on 140 net sections (146 gross) of land in the Doe / Mica Area. Leucrotta’s average working interest in the lands is 95%. The evaluation is an unrisked full development of the resource with multi-stage frac’ed horizontal wells using best-estimate type curves scheduled over a 28 year time period, effective January 2020. A total of $4.6 billion of capital (undiscounted) is required for the project with an initial cash outlay of $235 million before payout is anticipated (4 years). The assumed commodity price is GLJ’s Q1 2019 forecast. There is no assurance that the forecast price and cost assumptions used in the evaluation will be attained and variances could be material. The actual scope of the project will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained, and other factors. There is uncertainty that it will be commercially viable to produce any portion of the resources. For the prospective resources there is no certainty that any portion of the resources will be discovered and if discovered, there is no certainty that it will be commercially viable to produce any of those resources. The evaluation is an internal estimate prepared in accordance with the COGE handbook by a qualified reserves evaluator.

Potential Drilling Locations

This presentation discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii).

Of the 1,000 total potential/possible locations referenced in pages 2, 4, 7 and 11 of this presentation, only the following have been assigned reserves at December 31, 2018 as independently evaluated by GLJ, in accordance with National Instrument 51-101 (“NI 51-101”): 19 Proved Undeveloped34 Probable UndevelopedThe remaining 947 potential/possible locations are unbooked.

Unbooked locations are based on the Company's prospective acreage and internal estimates as to the number of wells that can be drilled per section. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Advisories

Page 15

Type Curves

This Presentation contains references to type well, or “type curve”, production and economics, which are derived, at least in part, from available information respecting the well performance of other companies and , as such, may be considered “analogous information” as defined in NI 51-101. Production type curves are based on a methodology of analog, empirical and theoretical assessments and workflow with consideration of the specific asset, and as depicted in this presentation, is representative of The Company’s current program, including relative to current performance. Some of this data may not have been prepared by qualified reserves evaluators, may have been prepared based on internal estimates, and the preparation of any estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. The Company believes that the provision of this analogous information is relevant to the Company’s oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas in question, and such information has been updated as of the date hereof unless otherwise specified.The Montney Type Curves presented on page 5 of this presentation are an internal estimate prepared by a Qualified Reserves Evaluator (“QRE”) and are based on an average of the proved plus probable type curves used by GLJ for booked undeveloped horizontal wells in the Lower Montney formation as per the year-end 2018 corporate reserves evaluation effective December 31 2018. The curves represent an internal “best-estimate” expectation. Any references to peak rates, test rates, IP30 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or ultimate recovery. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Corporation.

Test Rates

The oil well referenced on page 7 was production tested for 6 days after the original cleanup and produced at an average rate of 1,100 boe/d (48% gas, 52% Oil and Condensate) over that period, excluding load fluid and energizing fluid. At the end of the test, flowing wellhead pressure and production rates were stable.

The liquids-rich gas well noted on page 7 was production tested for an additional 4 days after the initial cleanup and produced at an average rate of 907 boe/d (81% gas, 19% Oil and Condensate) over that period, excluding load fluid and energizing fluid. This average flow rate includes periods where the well was significantly restricted due to operational constraints. The well was continuing to increase in flow rate with a stable flowing pressure at the end of the test.

A pressure transient analysis or well-test interpretation has not been carried out on these wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.

Corporate PresentationSlide Number 2Slide Number 3Slide Number 4�Lower Montney High GOR Light Oil Type Curve ��Lower Montney �High GOR Light Oil Metrics�Slide Number 7Slide Number 8Slide Number 9Slide Number 10Slide Number 11Slide Number 12Slide Number 13Slide Number 14Slide Number 15Blank Page