Corporate Presentation October 2018 - Gear Energy Ltd. · Gear has drilled six 1 mile horizontal wells, one 1.5 mile well and one 1.75 mile well all targeting Basal Belly River regional

Corporate PresentationOctober 2018

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TSX Listed GXE

Shares Outstanding (end of Q3) 219 million

Average Daily Trading 2018 Q3 520k (GXE:CC)

Insider Ownership 13% Basic / 16% FD

2018 Q2 Production 7,025 boe/d, 89% liquids

Estimated 2018 Production 7,500 boe/d

2018 Q2 Net Debt $39 million

2018 Q2 Net Debt to FFO 0.7 x

Current Debt Capacity $128.4 million

*On September 18, 2018 Gear closed the corporate acquisition of Steppe Resources Inc.

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Gear closed the acquisition of Steppe Resources on September 18, 2018

New core area in Saskatchewan producing approximately 1,000 boe/d of 99% light oil (Q4 2018 estimate)

Inventory of approximately 100 future drilling locations in multiple light oil formations dominated by the Torquay

2019 Forecast to begin delivering many years of self-funded growth

2019 estimate of 6 drilling locations growing production to 1,400 – 1,500 bbl/d

Stable oil pricing, 2019 estimates of 8% royalties and $13/bbl operating costs driving high field netbacks

Acquisition cost (on close) $66 MM (21.8MM GXE shares @$1.13 & ~$41.5MM in net debt)

Net debt assumptions on Sept 18, 2018 $31.4MM corporate net debt(estimates subject to audit) $7.5MM estimated hedging liability

$2.6MM transaction costs

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In 2016 Gear was essentially a pure play heavy oil producerTwo years later, production is forecast to include approximately 30% higher revenue light oil and NGL’s

Diversified inventory of drilling opportunities provides further optionality to focus investment to maximize short and long term returns on capital

Future growth focused on horizontal development of low-risk, light, medium and heavy oil opportunities

690 Management identified potential drilling locations

150 booked in P+P (Jan 2018)RLI = 8.1 yrs

80 booked in TP (Jan 2018)RLI = 5.3 yrs

PDP RLI = 3.4 years

Booked locations exclude the Steppe acquisition

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Central Alberta Light/Medium Oil/Gas

2,000 boe/d50 locations

Heavy Oil

5,000 boe/d540 locations

TablelandLight Oil

1,000 bbl/d100 locations

Current estimated field production

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Estimates assume commodity prices at October 2, 2018. Share count is debt adjusted

in 2018 using an estimated share price based on 4 times forecasted funds from

operations (“FFO”)

Gear is forecasting strong growth in production and funds from operations through 2018

FFO w/o

hedging

Capital Budget

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2011$34,500/boe/d$58MM capital

29% base decline

2012$24,800/boe/d$47MM capital

35% base decline

2013$25,800/boe/d$54MM capital

40% base decline

2014$35,900/boe/d$164MM capital

37% base decline

2015 $13,500/boe/d$15MM capital

35% base decline (42% including

shut-ins)

2016 $13,500/boe/d$14.4MM (Dev)

$24,000/boe/d$72MM (w/ A&D)32% base decline

(bo

e/d

)

Development capital efficiencies of $15,000/boe/d estimated for 2018Record low base decline estimate of 27% for 2018

2017$16,500/boe/d

$49.5MM capital28% base decline

2018 Estimates$15,000/boe/d

$50MM (Development)

$27,000/boe/d$116MM (w/ A&D)

27% base decline

Q1 2018 base production was

temporarily restricted by

takeaway limitations

Upon close of the Steppe Acquisition bank line was increased to $115 million

Current estimate of 1.2x net debt to funds from operations ratio for Q4 2018, as a result of discounted Canadian liquids pricing

Maintaining a low debt structure provides strategic optionality for potential acquisitions and insurance against price volatility

In addition to the $115 million syndicated facilities, Gear has $13.4 million of convertible debentures, $0.87 per share conversion and 4% coupon. Expire November 2020

*Estimates include Steppe Acquisition on September 18, 2018 and

assume commodity prices at October 2, 2018

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2018 total costs per unit are forecast to be $15/boe lower than 2013 (~40% lower)Continued development of low-cost horizontal wells should keep downward pressure on costs

2018 Guidance H1 2018 Actuals 2017 Actuals

Production 7,500 boe/d 6,775 boe/d 6,511 boe/d

Heavy oil weighting 64% Annual (58% Q4) 66% 63%

Light/Medium & NGL weighting 25% Annual (32% Q4) 21% 23%

Royalty rate 11% 10.5% 10%

Operating costs (including transport) $15.85/boe $16.52/boe $16.66/boe

G&A costs $2.25/boe $2.69/boe $2.25/boe

Interest $0.80/boe $0.92/boe $0.84/boe

Capital (Development) $50 million 16 million $48 million

Funds from operations 22 million $44 million

Net debt (incl. convertible debentures) 39 million $43 million

Net debt to funds from operations 0.9 x 1.0 x

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$50 million development budget targeting a balance between light, medium and heavy oil production growth

Capital

Light/Medium Oil Drilling $18 million

Heavy Oil Drilling $19 million

Land & Seismic $4 million

Waterfloods, Recompletions & Corporate $5 million

Abandonment and Reclamation $4 million

Total $50 million

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Approximately 200 potential multi-lateral unlined horizontal oil drilling opportunities across Alberta and Saskatchewan

Conventional drill to the target formation, cement intermediate casing and then drill multiple horizontal legs

Technology is being applied in thin tight conventional oil reservoirs that were previously deemed uneconomic

Low Capital Costs: $800,000 – $1,500,000 to bring a new well on production

Low Operating Costs: $5 - $7/boe due to high production to a single surface location

Low Royalties: Ab. 5% holiday from 18 months to 12 years, Sk. 2.5% first 38mstb

High productivity: 2.5 – 3 times the production from a single leg Hz well

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Approximately 200 future multi-lateral drills in inventory (management recognized)

Cummings, Lloydminster, Sparky & GP successfully drilled to date, future plans include Ratcliffe and Bakken

Successfully drilled 11 wells in 2017 with peak IP30 rates averaging 140 boe/d

2018 plan includes 10 wells in Wildmere, Lindbergh and Maidstone. Seven successfully drilled to date including step-out wells, re-entries, and multi-lateral wells with up to six legs

Only 36 undeveloped locations booked by GLJ at YE 2017 (P+P)

Wildmere Cummings

Wildmere Cummings

West Wildmere Cummings

Wildmere GP/Sparky

2017 Multi-laterals Drilled2018 Multi-laterals Drilled

Peak IP30 (boe/d)

Lindbergh 159

Maidstone 215

Re-entry 85

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Risked Estimates Unrisked Estimates

Capital $970k $970k

IP 365 70 bbl/d 80 bbl/d

Reserves 75 mbbls 90 mbbls

Economics ROR Payout ROR Payout

@US$65 WTI 115% 1.1 yrs 150% 0.9 yrs

See Appendix for summary of economic assumptions

Since 2014, 21 multi-lateral Gear wells have successfully been brought on production. Yielding long life predictable oil production from multiple producing horizons with results materially outperforming risked type curve

The two original 2014 drills have produced over 70 mbblsand are still producing stable at approximately 30 bbl/d/well

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See Appendix for summary of economic assumptions

Successful horizontal McLaren drilling since 2014, growing area production from zero to approximately 1,800 bbl/d 15 drilled in 2017, 10 more recently drilled in 2018

Management recognizes over 100 horizontal wells in inventory, 48 booked YE 2017 (P+P)

2017 Wells Drilled2018 Wells Drilled

Paradise Hill

Paradise South

Celtic Risked Estimates Unrisked Estimates

Capital $730k $730k

IP 365 68 bbl/d 72 bbl/d

Reserves 56 mbbls 62 mbbls

Economics ROR Payout ROR Payout

@US$65 WTI 150% 1.0 yrs 200% 0.9 yrs

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2017 Wells Drilled2018 Drills3rd Party Drills

Gear has a large new core area where historical drilling has been successful in producing heavy oil from the Success and the Bakken formations

There have been 14 new Success wells licensed or drilled in the area since the beginning of 2017 with peak IP30 oil rates ranging between 25 and 159 bbl/d

Gear’s first well was drilled as a 650m frac’d horizontal with a peak IP30 of 71 bbl/d , The follow-up was an un-frac’d open-hole quad-lateral well with an initial peak IP30 of 25 bbl/d (now shut-in)

Two multi-stage frac’d horizontal wells have been drilled in Q3 by Gear, proximal to the best results in the area, estimated cost of $1.5MM per well. Wells are completed and just coming on production

GXE Peak IP30 (bbl/d)3rd Party Peak IP30 (bbl/d)

71

90

111

93134

102

25

88

48

159

142

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Gear has drilled six 1 mile horizontal wells, one 1.5 mile well and one 1.75 mile well all targeting Basal Belly River regional light oil

All three 2018 wells to date have been successfully drilled and frac’d with the last two just coming on production now

Management recognizes 24 future drills in inventoryGLJ booked 10 at YE 2017

2016/17 Wells Drilled2018 Wells Drilled

Risked Estimates Unrisked Estimates

Capital $2,500k $2,500k

IP 365 150 boe/d 170 boe/d

Reserves 135 mboe 150 mboe

Economics ROR Payout ROR Payout

@US$65 WTI 91% 1.0 yrs 120% 0.9 yrs

Economics represent blend of 1 & 1.5 mile wellsSee Appendix for summary of economic assumptions

250

Peak IP30 to date(boe/d)

200

200

195

155 270

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Gear recognizes 100 potential drilling locations in the Tableland area. 20 locations are considered Tier 1 Torquay wells, 60 are Tier 2 Extended Reach Torquay wells and the remaining are multi-lateral unlined horizontal wells in the Ratcliffe. This area is forecast to deliver low cost, high netback light oil productionGear currently plans to drill 6 wells starting in 2019 Tier 1 One Mile

RiskedTier 2 Two Mile

ERH Risked

Capital $2,750k $3,420k

IP 365 100 bbl/d 110 bbl/d

Reserves 135 mbbls 150 mbbls

Economics ROR Payout ROR Payout

@US$65 WTI 74% 1.4 yrs 63% 1.6 yrs

Actual results to date are all 1-mile wells, See Appendix for summary of economic assumptions

Tier 1

Tier 2

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Diversified oil production provides access to multiple opportunities to maximize revenue despite current volatile liquids differentials

Recently acquired Southeast Saskatchewan production is significantly less impacted by forward estimated pricing discounts

Key oil pricing assumptions

Heavy WCS minus ~$6.50/bbl

Light (Ab) 98% of Edmonton Par

Light (SE Sk) 98% of Cromer LSB

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Year-to-date 2018, approximately 45% of Gears heavy oil volumes were shipped via rail, with the remaining volumes via pipe or sold locally to pavers

The railed volumes are up from a historical average of approximately 34%. Gear has yet to enter into any long term contracts, but continues to evaluate

Gear strives to maximize all revenue streams by ensuring diversification of both purchasers and transportation

Gear supplied heavy oil to approximately 10 different purchasers so far through 2018

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Risk management strategy is to target up to 50% protection for up to two years, (net of royalties)

*Upon close of the Steppe acquisition on September 18, 2018 a fair value of the acquired hedges of $7.5MM was included in the assumed net debt. This was based on Canadian WTI prices of $90.28/bbl in Q4 2018 and $88.17/bbl in 2019. Future reported funds from operations will include hedging losses or gains that are determined based on variations from those September 18th values

Financial WTI Crude Oil ContractsTerm Contract Volume Sold Swap Sold Call Bought Put Sold Put Steppe

bbl/d Currency $/bbl $/bbl $/bbl $/bbl Hedges

1-Oct-18 31-Dec-18 Collar 300 USD 52.50 47.501-Oct-18 31-Dec-18 Collar 600 USD 57.00 50.001-Oct-18 31-Dec-18 Collar 1,500 USD 56.00 46.001-Oct-18 31-Dec-18 Collar 400 CAD 82.00 62.501-Jan-19 31-Dec-19 3-way collar 600 USD/CAD U66.00 C62.00 C52.001-Jan-19 31-Dec-19 3-way collar 600 USD/CAD U72.00 C65.00 C55.001-Jan-19 31-Dec-19 3-way collar 1,200 CAD 100.00 65.00 55.00

1-Jan-19 31-Dec-19 Collar 100 CAD 103.00 65.001-Jan-20 31-Dec-20 Collar 700 CAD 94.00 65.001-Oct-18 31-Oct-18 Fixed Price Swap 500 CAD 61.20 *1-Nov-18 31-Dec-18 Fixed Price Swap 450 CAD 61.20 *1-Jan-19 28-Feb-19 Fixed Price Swap 450 CAD 61.20 *1-Mar-19 31-Jul-19 Fixed Price Swap 400 CAD 61.20 *1-Oct-18 31-Dec-18 Fixed Price Swap 300 CAD 71.20 *1-Jan-19 30-Jun-19 Fixed Price Swap 250 CAD 68.90 *1-Jul-19 31-Jul-19 Fixed Price Swap 200 CAD 67.30 *1-Aug-19 31-Dec-19 Fixed Price Swap 400 CAD 67.30 *

Financial AECO Gas ContractsTerm Contract Volume Sold Swap Sold Call Bought Put Sold Put Steppe

GJ/d Currency $/GJ $/GJ $/GJ $/GJ Hedges

1-Oct-18 31-Dec-18 Fixed Price Swap 1,700 CAD 2.651-Oct-18 31-Dec-18 Collar 1,700 CAD 2.60 2.40

Executive Prior Experience

Ingram Gillmore President & CEO, Director VP Engineering - ARC Resources, Talisman

Yvan Chretien VP Land VP Land - ARC Resources, CNRL

Bryan Dozzi VP Engineering Engineering Manager - Gear Energy, Rock Energy

David Hwang VP Finance & CFO Controller - ARC Resources, EnCana

Jason Kaluski VP Operations Manager Operations - Questerre, ARC Resources

Dustin Ressler VP Exploration Manager Geology - Gear Energy, CNRL

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Independent Directors Prior or Current Experience

Don T. Gray Chairman Prior Founder, President & CEO, Peyto Energy Trust

Raymond Cej Prior President, Teine Energy Ltd., Shell Canada Ltd.

Harry English Prior Senior Partner, Deloitte LLP

John O’Connell Current Chairman & CEO, Davis-Rea Ltd.

Kevin Olson Current President, Kyklopes Capital Management Ltd.

Bindu Wyma Prior VP Business Development NA, Talisman Energy

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Analysts

AltaCorp Thomas Matthews

Beacon Securities Lyndon Dunkley

Canaccord Genuity TBD

Cormark Garett Ursu

GMP FirstEnergy Bob Fitzmartyn

Haywood Christopher Jones

National Bank John Hunt

Peters & Co Dan Grager

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Paradise Hill

Capital $730k

IP 365 (bbl/d) 68 Risked / 72 Unrisked

Reserves (mbbls)

56 Risked / 62 Unrisked

- Production forecast is management internal estimates for half section single laterals

- Reserves are based off average GLJ assessed reserves

- Saskatchewan Crown royalty holiday of 2.5% for the first 38 mbbls of oil

Multi-laterals

Capital $970k

IP 365 (boe/d) 70 Risked / 80 Unrisked

Reserves (mboe)

75 Risked/ 90 Unrisked

- Production forecast is management internal average estimates for short and long quad-lateral, tri-lateral and dual-lateral unlined wells

- Reserves are based off average GLJ assessed reserves

- Alberta Crown royalty holiday of 5% for between 18 months and 12 years, pending the ultimate cumulative length of the well

- Saskatchewan Crown royalty holiday of 2.5% for the first 38,000 bbls of oil

Wilson Creek

Capital $2,500k

IP 365 (boe/d) 150 Risked / 170 Unrisked

Reserves (mboe)

135 Risked / 150 Unrisked

- Capital, production and reserves are management internal estimates for average of 1 mile and 1.5 mile horizontal multi-frac wells

- Economics are based on a 70% Crown 30% Freehold royalty model

- Alberta Crown royalty holiday of 5% for approximately the first 2 years

- Average Freehold royalty of 17%

Economics were run using a flat price forecast of US$65 WTI with 0.80 CAD/US foreign exchange, heavy oil differential of 30% off WTI with an additional heavy oil quality discount of CAD$5.00, and a light oil realized

price estimate of WTI minus CAD$6.00

Tableland

Capital ($k) 2,750 / 3,420

IP 365 (bbl/d) 100 / 110

Reserves (mbbls)

135 / 150

- Capital, production and reserves are management internal risked average estimates for 1 mile Tier 1 and 2 mile Tier 2 horizontal Torquay wells

- Saskatchewan Crown royalty holiday of 2.5% for the first 100 mbbls of oil, plus an average GORR of approximately 0.75%

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The information contained in this presentation does not purport to be all-inclusive or to contain all information that prospective investors may require. Additional information relating to Gear Energy

Ltd. ("Gear" or the "Corporation") is available on Gear's profile on SEDAR at www.sedar.com and readers should read such information prior to making an investment decision. Prospective

investors are also encouraged to conduct their own analysis and reviews of the Corporation and of the information contained in this presentation. Without limitation, prospective investors should

consider the advice of their financial, legal, accounting, tax and other advisors and such other factors they consider appropriate in investigating and analyzing the Corporation.

Certain statements included in this presentation constitute forward looking statements or forward looking information under applicable securities legislation. Such forward looking statements or

information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such

information may not be appropriate for other purposes. Forward looking information in this presentation includes, but is not limited to, information with respect to: forecast production growth

through 2018; forecast full year and fourth quarter 2018 average production; expected future drilling locations, inventory and reserves life including with respect to the Steppe assets; forecast

2018 net debt to funds from operations; forecast 2018 funds from operations and funds from operations per debt adjusted share; expectations of improving costs; expectations of 2018 debt

adjusted funds from operations; the proposed Steppe Acquisition including the impact of the Steppe Acquisition on Gear and Gear's plans; the anticipated approval of the Steppe Acquisition by

the shareholders of Steppe; the anticipated receipt of all Court and regulatory approvals in respect of the Steppe Acquisition; the satisfaction of all parties to the conditions to closing of the Steppe

Acquisition; the anticipated closing time of the Steppe Acquisition; anticipated effect and benefits of the Steppe Acquisition including the anticipated 2019 drilling program with respect to Steppe's

inventory, including estimated production, royalty rates, operating costs, net operating income, capital expenditures and the number of planned wells; estimated annual funds from operations in

respect of the Steppe assets; expected terms and availability of increased credit facilities upon closing of the Steppe Acquisition; expectations of 2018 operating costs, general and administrative

costs, royalties and interest costs; estimated 2018 development capital efficiencies; estimated base decline for 2018; estimated 2018 capital budget and details of such budget; expected details of

Gear's 2018 multi-lateral well drilling program; expected economics associated with certain drilling programs; expectations of commodity prices and differentials; expectations of how Gear will

transport and market its production; and expectations of 2018 and 2019 hedging program and amount of production expected to be hedged. Forward looking statements or information are based

on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although Gear believes that the expectations

reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Gear can give no assurance that such

expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the

timing of receipt of regulatory and Steppe shareholder approvals for the Steppe Acquisition; the ability of Gear to execute and realize on the anticipated benefits of the Steppe Acquisition; that the

increased credit facilities will be entered into in the amounts and terms anticipated which shall be satisfactory to Gear or at all; the impact of increasing competition; the general stability of the

economic and political environments in which Gear operates; the timely receipt of any required regulatory approvals; the ability of Gear to obtain qualified staff, equipment and services in a timely

and cost efficient manner; the ability of the operator of the projects which Gear has an interest in to operate the field in a safe, efficient and effective manner; field production rates and decline

rates; the ability to replace and expand oil reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability

of Gear to secure adequate product transportation; future oil prices; the differentials between heavy and light oil pricing; currency, exchange and interest rates; the regulatory framework regarding

royalties, taxes and environmental matters in the jurisdictions in which Gear operates; the ability to secure financing on terms acceptable to Gear; the performance of existing and future wells to

be as expected, the ability of Gear to successfully market its oil and natural gas products, and the expected continued availability of credit under Gear's credit facilities. In addition, to the extent

that any forward-looking information presented herein constitutes future-oriented financial information or a financial outlook such information has been approved by management on March 28

2018 and has been presented to provide management's expectations used for budgeting and planning purposes based on the assumptions presented herein and such information may not be

appropriate for other purposes. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Since forward-looking statements address

future events and conditions, by their very nature they involve inherent risks and uncertainties.

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Completion of the Steppe Acquisition could be delayed if parties are unable to obtain the necessary regulatory, stock exchange, shareholder and court approvals on the timeline planned. The

Steppe Acquisition will not be completed if all of these approvals are not obtained or some other condition of closing is not satisfied. Accordingly, there is a risk that the Steppe Acquisition will not

be completed within the anticipated time or at all. Any increases to Gear's credit facilities will be subject to a number of conditions, including the closing of the Steppe Acquisition. If an increased

credit agreement is not entered into it may impact Gear's ability to continue to fund its operations and may prevent the closing of the Steppe Acquisition. In this presentation, Gear has disclosed

certain expected details relating to the Gear's 2019 capital program on the Steppe assets if the Steppe Acquisition closes; however, the board of directors of Gear has not approved a budget for

2019 and as such the details relating to the 2019 capital program are intended only to illustrate Gear’s management's current expectations based on information and conditions known as of the

date hereof. Gear's actual 2019 capital budget once approved may differ from the details disclosed herein for a variety of reasons including as a result of any change in conditions and information

known to Gear prior to the date the 2019 budget is approved and/or as a result of Gear's management and board of directors allocating capital differently than currently expected. The actual 2019

capital program on the Steppe assets may also differ from the expectations as set out herein due to the other risk factors identified herein. Other risks include risks associated with oil and gas

exploration, development, exploitation, production, marketing and transportation, loss of markets and other economic and industry conditions, volatility of commodity prices, currency fluctuations,

imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling services, incorrect assessment of value of acquisitions and failure to realize the

benefits therefrom, delays resulting from or inability to obtain required regulatory approvals, the lack of availability of qualified personnel or management, stock market volatility and ability to

access sufficient capital from internal and external sources and economic or industry condition changes. Actual results, performance or achievements could differ materially from those expressed

in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur, or if any of

them do so, what benefits that Gear will derive therefrom. Additional information on these and other factors that could affect Gear are included in reports on file with Canadian securities regulatory

authorities that may be accessed through the SEDAR website (www.sedar.com) or at Gear's website www.gearenergy.com. The forward-looking statements contained in this presentation are

made as of the date hereof and Gear undertakes no obligations 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.

In this presentation, management uses certain key performance indicators and industry benchmarks such as funds from operations, funds from operations per debt adjusted share, production per

million debt adjusted shares, operating netbacks, and net debt to analyze financial and operating performance. Management feels that these performance indicators and benchmarks are key

measures of profitability for Gear and provide investors with information that is commonly used by other oil and gas companies. These performance indicators and benchmarks as presented do

not have any standardized meaning prescribed by Canadian generally accepted accounting principles and therefore may not be comparable with the calculation of similar measures for other

entities. For additional information on the use of these measures please see Gear's most recent Management's Discussion and Analysis on Gear's profile at www.sedar.com.

This presentation discloses booked and unbooked drilling locations. Booked locations associated with Gear’s existing assets are derived from the most recent independent reserves evaluations

of the Corporation’s properties as prepared by GLJ Petroleum Consultants Ltd. ("GLJ") as of December 31, 2017 and account for drilling locations that have associated proved and/or probable

reserves, as applicable. Unbooked locations are internal estimates based on Gear's prospective acreage and an assumption as to the number of wells that can be drilled per section based on

industry practice and internal review. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic,

seismic, engineering, production, pricing assumptions and reserves information. This presentation also discloses drilling locations associated with Steppe's assets. These locations are Gear

management’s internal estimates based on a review of Steppe's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and

internal review. While certain of these internally estimated drilling locations may be consistent with drilling locations identified in Steppe's most recent independent reserves report as having

associated proved and/or probable reserves, for the purpose of this presentation management has considered them as unbooked locations. These locations have been identified by management

of Gear as an estimation of Steppe's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production, pricing assumptions and reserves information.

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There is no certainty that Gear will drill all drilling locations identified herein 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 Gear actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices,

costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of Gear's unbooked locations are extensions or infills of the drilling patterns

already recognized by the independent evaluator, 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.

This presentation contains a number of oil and gas metrics, including capital efficiency, peak IP 30, IP 30, IP 365, rate of return or "ROR", reserves life index or “RLI”, and payout, which do not

have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been

included herein to provide readers with additional measures to evaluate the Corporation's performance; however, such measures are not reliable indicators of the future performance of the

Corporation and future performance may not compare to the performance in previous periods. Capital efficiency is based on the total capital invested in a period divided by the average daily

production additions (over the period indicated) resulting from such activity. IP 30 and IP 365 is the expected or actual initial production rate for the first 30 or 365 days of production of a well.

Peak IP 30 is the average initial 30 day expected or actual production rates of a well after it has been optimized. Rate of return is calculated by taking the expected capital costs to drill,

complete and equip wells and balancing them against the future net revenue expected using various commodity price forecasts and management estimates of operating costs, royalties,

production rates and reserves. The production and reserves estimates are based on a combination of actual area average results and independently assessed values from GLJ, those amounts

are then risked with a chance of success between 60 to 90 per cent. Reserves life index is calculated by dividing the year end 2017 reserves balance by the estimated 2018 production amount

for the same category. Payout is calculated by determining the number of years it will take the Corporation to earn back the capital invested in such well based on expected production and

various price and cost inputs. The capital efficiencies, initial rates of production, rates of return and payouts associated with the wells or assets have been provided herein to give an indication

of management's assumptions used for budgeting, planning and forecasting purposes. The capital efficiencies, initial rates of production, rates of return and payouts associated with the wells

or assets will most likely be different than projected. Any references in this presentation to capital efficiencies, initial rates of production, rates of return and payouts associated with the wells or

assets are useful in confirming the presence of hydrocarbons, and for understanding assumptions used for budgeting and planning purposes, however, such rates are not determinative of the

rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long term performance or long term economics of the relevant well or fields or of

ultimate recovery of hydrocarbons. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production or performance for Gear.

In this presentation, management has presented certain advantages of multi-lateral drilling. While such advantages are based on management's historic experience of multi-lateral drilling such

previous experience is not necessarily determinative of the results of future multi-lateral drilling and is not necessarily indicative of long term performance or long term economics. While

encouraging, readers are cautioned not to place reliance on such historic advantages of multi-lateral drilling in determining the future performance for Gear.

Certain natural gas volumes have been converted to barrels of oil equivalent ("boe") based on a conversion ratio of one bbl to six mcf is based on an energy equivalency conversion method

primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head. Given that the value ratio based on the current price of oil as compared to natural

gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Definitions: Boe = barrel of oil equivalent (6:1), Boe/d = Boe per day, Mmcf/d = MM cubic feet per day, WI = working interest, MM = million, CAGR = compound annual growth rate, DA = debt

adjusted, EV = enterprise value