Corporate Presentation - Building a Premier Oil ?· Corporate Presentation September 2017 . September…

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<ul><li><p>September 2017 </p><p>Corporate Presentation </p><p>September 2017 </p></li><li><p>September 2017 </p><p>Advisory This presentation should be read in conjunction with the Companys Annual Information Form and the Consolidated Financial Statements and Managements Discussion and Analysis as filed on SEDAR. </p><p> 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 ; (v) cash flow and (vi) operating costs. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. </p><p> Certain information regarding the Company set forth in this document, including managements assessment of the Companys 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 Companys 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 Companys 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 Companys operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website ( or the Companys website ( </p><p> 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. </p><p> 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. </p><p> 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 Companys independent reserves evaluation as of December 31, 2016. Unbooked locations are internal estimates based on the Companys 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 Companys 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. </p><p> 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. </p><p> 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. </p><p> 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. </p><p>2 </p></li><li><p>September 2017 </p><p>MULTI-ZONE LIGHT OIL RESOURCE PLAY </p><p> Over 4 Billion barrels of light oil in stacked zones </p><p> High quality conventional reservoir </p><p> Profitable drilling at $50 WTI </p><p> ~400,000 acres of land </p><p>2 BILLION BARRELS OF LIGHT OIL UNDER DEVELOPMENT IN MUSKEG ZONE </p><p>GROWTH TO 30,000 BOE/DAY WITH MUSKEG OIL DEVELOPMENT </p><p>Crains Petrophysical Handbook </p><p>3 </p></li><li><p>September 2017 </p><p>MARLOWE: UNIQUE ASSET WITH STACKED PAY </p><p> Large structural trap created by the impact of an Asteroid ~100 million years ago that is charged with light oil and gas in six stacked horizons </p><p> Muskeg zone is currently the key focus </p><p>Zone Prospective </p><p>Sections Net Pay </p><p>(feet) OOIP/Sec </p><p>(MMBBL)* OOIP </p><p>(MMBBL) </p><p>Muskwa 120 90 8 960 </p><p>Slave 140 100 12 1,680 </p><p>Sulphur 130 30 8 1,040 Muskeg 200 30 10 2,000 Zama 130 20 5 650 Keg Plat 140 90 8 1,120 </p><p>* Companys Internal Estimates </p><p>OVER 4 BILLION BARRELS OF LIGHT OIL IN STACKED ZONES </p><p>Slave </p><p>Sulphur </p><p>Muskeg </p><p>Keg </p><p>Single Pad Multi-Formation Development </p><p>4 </p></li><li><p>September 2017 </p><p>MUSKEG - HIGH QUALITY CONVENTIONAL RESERVOIR </p><p>5 </p><p>14-18-122-23W5 </p><p>1300mTVD/-670mSS Net Pay: 10m, Por: 12% </p><p>12.5MMbbl/section OOIP Well Cored </p><p>0% 20% </p><p>2014 Muskeg well - 09-24 </p><p>2016 Muskeg well - 14-35 </p><p>EXTENSIVE AND CONTINUOUS </p><p>Porosity </p></li><li><p>September 2017 </p><p>2017 MUSKEG WELL RESULTS </p><p>6 </p><p>TOP TIER OIL PLAY IN CANADA </p><p>SIX OF THE LAST EIGHT WELLS MADE TOP WELL LIST IN ALBERTA </p></li><li><p>September 2017 </p><p>Gross reserves are the estimated working interest reserves before the deduction of any royalties. Gross reserve estimates are based on Strategics internal evaluation and were prepared by a member of Strategics management who is a qualified reserves evaluator in accordance with National Instrument 51-101. </p><p>WELL TYPE CURVE &amp; ECONOMICS </p><p>Total Capital Cost ($ MM) 3.5 </p><p>IP30 BOED Sales 440 </p><p>IP 365 BOED Sales 240 </p><p>Reserves (MBOE) 400 </p><p>F&amp;D ($/BOE) 8.75 </p><p>WTI Oil Price $US 50 </p><p>Payout (years) 1.4 </p><p>Rate Of Return (%) 73 </p><p>Profit to Investment Ratio 2.2 </p><p>BTAX NPV10 ($ MM) 4.1 </p><p>7 </p><p>RATE OF RETURN OVER 70% AT $50 WTI </p><p>MUSKEG TYPE CURVE </p><p>NETBACK Oil price =$50 US flat; Gas:US$2.25/mmbtu Henry Hub Oil ($CAD/bbl): 42.77 (until payout); 38.41 ( post payout) Gas ($CAD/mscf): 0.87 (until payout); 0.67 (post payout) </p></li><li><p>September 2017 </p><p>EVOLUTION OF MUSKEG DEVELOPMENT </p><p>8 </p><p> Proved Oil &amp; Gas Production from the Muskeg Zone </p><p> Tested Various Drilling and Completion Techniques </p><p> Frac. Fluid Optimization </p><p> 1400 m HZ; 15 Stages Dissolvable Frac. Balls Geosteering: Target Specific </p><p>Dolomites </p><p> Longer Wells, More Stages 1900 m HZ 20 to 40 Stages </p><p> Frac Fluid Optimization Optimizing Artificial lift </p><p> HEAL/Rod Pump/ ESP </p><p>Phase 2: 2013 Trials &amp; Assessment </p><p>Phase 3: 2014/15 Repeatable &amp; Reliable </p><p>Phase 4: 2016/17 Increased Productivity </p><p>Phase 1: 2012 Proof of Concept </p></li><li><p>September 2017 </p><p>CONTINUOUS IMPROVEMENT IN MUSKEG WELL PERFORMANCE </p><p>9 </p><p>0</p><p>30</p><p>60</p><p>90</p><p>120</p><p>0</p><p>200</p><p>400</p><p>600</p><p>800</p><p>1 2 3 4 5</p><p>Cu</p><p>m 1</p><p> yr </p><p>Pro</p><p>d (</p><p>MB</p><p>OE)</p><p>IP 3</p><p>0 (</p><p>BO</p><p>ED) </p><p>Stage of Development </p><p>Cum 1 year IP30</p><p>0</p><p>10</p><p>20</p><p>30</p><p>40</p><p>0</p><p>1000</p><p>2000</p><p>1 2 3 4 5</p><p>Stag</p><p>es </p><p>HZ </p><p>Len</p><p>gth</p><p> (m</p><p>) </p><p>Stage of Development </p><p>Stages Hz Length</p></li><li><p>September 2017 10 </p><p>DOMINANT LAND POSITION &amp; INFRASTRUCTURE CONTROL </p><p> 100% working interest All petroleum &amp; natural gas rights Connected via pipeline, highway &amp; rail </p><p>~400,000 ACRES OF LAND </p><p>Canada &amp; US </p><p>HIGHWAY &amp; RAIL </p><p>Strategic Lands </p></li><li><p>September 2017 </p><p>OWNERSHIP &amp; OPERATORSHIP OF FACILITIES INFRASTRUCTURE WITH REPLACEMENT VALUE &gt;$500 MILLION </p><p> 100% owned and operated Underutilized oil &amp; gas plant capacity for future growth Sour gas and water handling on site </p><p> BISTCHO PLANT </p><p>5o MMscf/day STEEN PLANT 4o MMscf/day </p><p>11 </p></li><li><p>September 2017 12 </p><p>Spring Summer </p><p>Fall Winter </p><p>YEAR ROUND OPERATIONS </p></li><li><p>September 2017 </p><p>SCALABLE GROWTH PLAN </p><p>13 </p><p>EXISTING LAND BASE CAN KEEP PRODUCTION FLAT AT 30,000 BOED FOR 10+ YEARS </p><p> Drill with one rig and grow to a two rig program 250 wells drilled over 7 years (1/3rd of Muskeg Drilling Inventory) Outspend Cash Flow for first four years at $50 WTI Grow to 30,000 BOED in 7 years &amp; keep production flat for additional 10 years Generate significant free cash flow for over 10 years </p><p>PRODUCTION GROWTH TO 30,000 BOED OVER 7 YEARS </p></li><li><p>September 2017 </p><p>CORPORATE SNAPSHOT </p><p>Trading Symbol TSX-V: SOG </p><p>Shares (basic) 1 46.4MM </p><p>Working capital 1 $26MM </p><p>Convertible debt 2 $102MM </p><p>Share price (August 8, 2017) $2.05 / share </p><p>Enterprise value $171MM </p><p>Insider ownership (basic) 67.1% </p><p>Corporate production 3 2,700 boe/d </p><p>Reserves (P+P, Dec 31/16) 19.6 MMBoe </p><p>14 </p><p> No bank debt Tightly held ownership group Reserves booked on only 15% of Muskeg acreage $485 million in tax pools </p><p>1. As at June 30, 2017 2. 8% coupon, convertible at $1.80/share 3. Average for Q2 2017 </p><p>ENTERPRISE VALUE IS A SMALL FRACTION OF RESOURCE POTENTIAL </p></li><li><p>September 2017 </p><p>CORPORATE INFORMATION </p><p>MANAGEMENT TEAM </p><p>Cody Smith COO &amp; Interim CEO </p><p>Aaron Thompson CFO </p><p>Doug Wright VP Engineering &amp; Corp Development </p><p>Barbara Joy VP Land </p><p>RESERVE ENGINEERS McDaniel &amp; Associates Consultants </p><p>AUDITORS Deloitte LLP </p><p>LEGAL Norton Rose Fulbright Canada LLP </p><p>BANKING Royal Bank of Canada </p><p>HEAD OFFICE 1100, 645 7th</p><p> Ave SW Calgary, Alberta, T2P 4G8 Phone: 403-767-9000 Fax: 403-767-9122 Email: Website: </p><p>15 </p><p>BOARD </p><p>Thomas Claugus, Chairman Chairman </p><p>Jim Riddell CEO, Paramount Resources </p><p>Richard Skeith Partner, Norton Rose Fulbright </p><p>Michael Graham Chairman, Saguaro Resources </p><p>John Harkins CEO, Greenfields Petroleum </p><p>Rodger Hawkins Independent businessman </p><p>Michael Watzky Partner, BP Energy Partners </p></li></ul>