April 2017

BUILDING A PREMIER

OIL COMPANY

Corporate Presentation

April 2017

April 2017

Advisory This presentation should be read in conjunction with the Company’s Annual Information Form and the Consolidated Financial Statements and Management’s Discussion and Analysis as filed on SEDAR.

FORWARD LOOKING STATEMENTS: This presentation includes projections that are derived from certain assumptions with respect to (i) wells drilled and drilling success; (ii)production; (iii) future capital expenditures; (iv) future reserves and (v) cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect.

Certain information regarding the Company set forth in this document, including management’s assessment of the Company’s future plans and operations, the planning and development of certain prospects, production estimates, reserve estimates, undeveloped land holdings, capital expenditures and the timing thereof and the total future capital required to bring undeveloped proved and probable reserves onto production, and expanded production growth may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. These forward-looking statements are subject to numerous risks and uncertainties, many of which are beyond the Company’s control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, increasing capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition and fluctuations in foreign exchange or interest rates. Readers are cautioned that the foregoing list of factors is not exhaustive. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. The foregoing and all subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information of these and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or the Company’s website (www.sogoil.com).

The forward-looking statements contained in this document are made as of the date on the front page and the Company assumes no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

TEST AND INITIAL PRODUCTION RESULTS: Any references in this presentation to initial or test production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will continue production. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production. Initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons. Test volumes are quoted on a raw basis before shrinkage on natural gas volumes. Total corporate production volumes include natural gas shrinkage.

DRILLING LOCATIONS: This presentation discloses drilling locations in three categories: (i) locations assigned proved reserves, (ii) locations assigned probable reserves and (iii) unbooked locations. Locations assigned reserves are derived from the Company’s independent reserves evaluation as of December 31, 2016. Unbooked locations are internal estimates based on the Company’s existing prospective acreage, current well lengths and an estimated number of wells drilled per section. Unbooked locations do not have reserves assigned. Of the 600 locations identified in the Company’s growth plan, 28 were assigned proved reserves, 26 were assigned probable reserves, and the remainder are unbooked locations. Unbooked locations have been identified by management based on application of industry standard geological, geophysical, engineering, production and reservoir information. There is no certainty that all unbooked locations will be drilled or that, if drilled, these locations will result in additional production and reserves for the Company. While certain unbooked locations are in close proximity to existing production, the majority are not in close proximity to existing producing wells and there is uncertainty as to the quality of the potential reserves and production to be obtained by drilling these locations.

GROWTH PLANS: Growth plans presented in this presentation are based on an internal conceptual development plan. The actual number of wells drilled and development undertaken in future periods will depend on capital availability, regulatory issues, seasonal restrictions, commodity prices, actual drilling results, cash flows, accessibility of equipment and qualified personnel and other factors.

BOE MEASUREMENT: "Boe“ means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil . Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ORIGINAL OIL IN PLACE: Original Oil in Place(“OOIP”) are the equivalent to Total Petroleum Initially In Place(“TPIIP") as defined by the COGEH Guidelines and are not reserves. There is no certainty that it will be commercially viable to produce any portion of OOIP except to the extent they are subsequently classified as proved or probable reserves.

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April 2017

Corporate Snapshot

Trading Symbol TSX-V: SOG

Shares (basic) 1 46.4MM

Working capital 2 $45MM

Convertible debt 3 $102MM

Share price (March 3, 2017) 1 $2.80 / share

Enterprise value 4 $183MM

Insider ownership (basic) 67.1%

Net acreage 443,000 acres

Reserves (P+P, Dec 31/16) 19.6 MMBoe

Current production 5 2,800 boe/d

3

Marlowe: 100% Owned Northern Alberta Oil Play

• Multi-zone light oil play with over two billion barrels of OOIP

• Play is profitable at $40 WTI

• Production growth to 30,000 BOED in the next 5-7 years

1. After giving effect to 20:1 share consolidation 2. Estimated at January 31, 2017 3. 8% coupon, convertible at $1.80/share, see Appendix 4. Calculated based on basic shares outstanding plus net

debt @ Jan. 31/17 5. Average Feb. 2017

April 2017

Marlowe: Multi-Horizon Potential for Oil Development

Zone OOIP/Sec (MMbbl)

Slave Pt. 20

Sulphur Pt. 7

Muskeg 10

Keg River 20

April 2017 5

Muskeg Zone – High Quality Conventional Reservoir 14-18-122-23W5 03-35-124-22W5

970m TVD / -590mSS Net Pay:6.5m, Por: 9.9% 6.5 MMbbl/section OOIP

7-02-119-23W5

0% 20%

11-35-121-23W5

10-29-122-21W5

12-21-120-23W5

0% 20%

0%

M = 1.8, Sw = 25%, Por cut off = 3%, Boi = 1.15

1315mTVD / -720mSS Net Pay: 9m, Por: 12.5% 11.5 MMbbl/section OOIP

1185m TVD / -780mSS Net Pay: 12.5m Por: 9.9% 13 MMbbl/section OOIP

Well Cored

1300mTVD/-670mSS Net Pay: 10m, Por: 12%

12.5MMbbl/section OOIP

Well Cored

1370m TVD / -705mSS Net Pay: 6.2m, Por: 9.3%

6 MMbbl/section OOIP

0%

20%

1135m TVD / -780mSS Net Pay: 9m, Por:9.8%

9 MMbbl/section OOIP

20%

0% 20%

0% 20%

Extensive and Continuous

April 2017

Muskeg Zone: Excellent Well Results

6

Muskeg Wells

Future Drills

Key Wells

Legend

Well 14-35 1060 BOED

Well 14-12 810 BOED

Well 02-13 1263 BOED

Well 06-24 545 BOED

Well 09-24 737 BOED

Well 04-33 503 BOED

#### Phase 4 Well Test Rate

#### Phase 3 Well Test Rate

#### Phase 2 Well Test Rate

April 2017

Four Well Pad Development

9-17 Facility Details • Sour Processing Facility • Gas Facility Startup: 1999 • Oil Facility 2008; Expansion

in 2013 • Oil Sales Pipeline

Connected in 2014 • Acid Gas Injection / Water

Disposal

Sales Compressors

Inlet Compressor

Power Generation

Oil Tank Farm

Shop / Hangar

Ware-house Control

Room

Process Flare

ESD

Heat Medium Reverse

Osmosis Bldg Acid Gas

Compressor

Inlet Sep

Helipad

Refridge Plant Treaters

Master Control Center

Amine Sweetening Skim Tanks &

Water Tanks

Utility Bldg

VRU FWKO

Sales Oil

Pumps

Gas Filter Bldg

1-28 Pad Drilling & Completions Marlowe Road Multi-Well Pad

Development Details • Horizontal Multi-Stage Wells • Year-Round Operations • Full High-Grade Road Access

April 2017

Continued Drilling & Completion Cost Improvements

8

April 2017

PRODUCTION COSTS 2014 2015 2016

Total OPEX ( $MM) 21 15 12

Total Production (BOED) 2,562 2,372 1,740

OPEX + Trans Costs ($/BOE) $22.47 $17.29 $18.18

Production Costs - IMPROVEMENT WITH GROWTH

BOED OPEX + Trans

( $/boe)

1,750 18

4,500 9

Operating Cost Improvements at Marlowe

* At US$55/Bbl WTI & $3.00/GJ AECO

NETBACKS AT MARLOWE IMPROVE TO $30*/BOE WITH PRODUCTION GROWTH

Costs at Marlowe have been reduced by 45%

9

April 2017

Evolution of Muskeg Development

10

• Drilled NE-SW: Direction of minimum stress

• Proved Oil & Gas Production from the Muskeg Zone

• Drilled NW-SE • Tested Various Drilling and

Completion Techniques • Frac. Fluid Optimization • Tested Various Artificial Lift

Techniques

• Executed with a Consistent Approach

• 1400 m HZ; 15 Stages • Run Dissolvable Frac. Balls • Simplified Wellbore by

Fracturing Down Casing • Geosteering: Target Specific

Dolomites

• 4-Well Pads • Longer Wells, More Stages

• 1900 m HZ • 20 Stages

• Continued Frac Fluid Optimization

• Continued Reduction to Drilling Days

Phase 2: 2013 Trials & Assessment

Phase 3: 2014/15 Repeatable & Reliable

Phase 4: 2016 Increased Productivity Per Stage

Phase 1: 2012 Proof of Concept

Field Reported Volumes – Before Shrinkage

April 2017

* Gross reserves are the estimated working interest reserves before the deduction of any royalties. Gross reserve estimates are based on Strategic’s internal evaluation and were prepared by a member of Strategic’s management who is a qualified reserves evaluator in accordance with National Instrument 51-101.

Type Curve Phase 4

Total Capital Cost $3.25 MM

IP30 BOPD/BOED Sales 330 / 475

IP 365 BOPD/BOED Sales 170 / 244

Reserves* (MBBL/MBOE) 260 / 375

F&D ($/BOE) $8.67

WTI Oil Price $US $55

Payout (yrs) 0.9

Rate Of Return (%) 137%

PV 10 Profit to Investment Ratio 2.5

BTAX NPV10 $4.9MM

Marlowe Economics: Profitable at $40 WTI

0%

50%

100%

150%

200%

40 45 50 55 60

WTI Oil Price ($US/BBL)

Rate of Return

0

1

2

40 45 50 55 60

WTI Oil Price ($US/BBL)

Payout (Years)

2

4

6

40 45 50 55 60

WTI Oil Price ($US/BBL)

BTAX NPV 10 ($MM CDN)

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April 2017

Marlowe: Key Property Highlights

12

Building a Premier Oil Company

Land 414 Sections; 100% Working Interest

Resource Two Billion Barrels OOIP mapped on company lands in the Muskeg Zone

Well Performance 2017 Type Curve: IP30 = 475 BOE/d sales; EUR = 375 MBOE

Reserves P+P Reserves = 19.6 MMBOE; P+P NPV10 = $194MM

Infrastructure 2 Connected Oil Batteries & Sour Gas Plants

Sales Oil Pipeline, >50km High Grade Roads

Drilling Inventory 600 Identified Locations in the Primary Muskeg Zone

Upside Proven Production Capability from 5 Other Zones

April 2017

-

10,000

20,000

30,000

Pro

du

ctio

n (

bo

e/d

)

ESTIMATED PRODUCTION

YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7+

Wells Drilled 17 30 45 70 70 45 ~35

BOE/D 4,250 7,250 12,000 19,000 26,000 30,000 30,000

Maintain 30,000 boe/d for over 10 years @ 35 wells/year

Conceptual Development Profile

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April 2017

APPENDIX

April 2017

Corporate Information

MANAGEMENT TEAM

Gurpreet Sawhney President & CEO

Cody Smith COO

Aaron Thompson CFO

Doug Wright VP Engineering & Corp Development

Barbara Joy VP Land

RESERVE ENGINEERS McDaniel & Associates Consultants Ltd.

AUDITORS Deloitte LLP

LEGAL Norton Rose Fulbright Canada LLP

BANKING Royal Bank of Canada

HEAD OFFICE 1100, 645 7th

Ave SW Calgary, Alberta, T2P 4G8 Phone: 403-767-9000 Fax: 403-767-9122 Email: contactus@sogoil.com Website: www.sogoil.com

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BOARD

Thomas Claugus, Chairman Chairman

Jim Riddell CEO, Paramount Resources & Trilogy Energy

Richard Skeith Partner, Norton Rose Fulbright

Michael Graham Chairman, Saguaro Resources

John Harkins CEO, Greenfields Petroleum

Rodger Hawkins Independent businessman

Michael Watzky Partner, BP Energy Partners

Gurpreet Sawhney President & CEO

FOR MORE INFORMATION PLEASE CONTACT

Gurpreet Sawhney President & Chief Executive Officer Phone: (403) 767-9000 Email: gsawhney@sogoil.com

April 2017

Reserves Growth at Marlowe

16

Reserves Dec 31/16

Gross MMboe

NPV10 ($MM)

Muskeg locations

PDP 3.4 38.7

TP 9.3 93.9 28

TP+P 19.6 194.4 54

0

5

10

15

20

2013 2014 2015 2016

Re

serv

es

(MM

Bo

e)

Probable

PDNP+PUD

PDP

Only 15% of the Muskeg Land Base is Booked as of YE-2016

April 2017

Convertible Debentures

17

• Principal amount outstanding: $102.2 Million • Annual coupon: 8.0% • Maturity date: February 28, 2021

Conversion Option • Can be converted into common shares of Strategic at the option of the holder:

• $94.9MM convertible at $1.80 per common share • $3.6MM convertible at $3.30 per common share • $3.7MM convertible at $2.70 per common share

• Can be called by the Company up to one year before the maturity date • Can force conversion if VWAP of SOG shares is above $7.20 for 90 days