Building A Premier Oil Company. Corporate Presentation December 2016

Transcription

1 Building A Premier Oil Company Corporate Presentation December 2016

2 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 ( or the Company s website ( 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 forwardlooking 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, 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 300 locations identifed in the Company s growth plan, 19 were assigned proved reserves, 19 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. 2

3 50 km Marlowe Asset: Significant Resource Play THE PRIZE 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 >$350 million invested to date Marlowe Asset 3

4 Muskeg Zone High Quality Conventional Reservoir 1300mTVD/-670mSS Net Pay: 10m, Por: 12% 12.5MMbbl/section OOIP Well Cored W5 1370m TVD / -705mSS Net Pay: 6.2m, Por: 9.3% 6 MMbbl/section OOIP W W W5 20% 0% 20% 1315mTVD / -720mSS Net Pay: 9m, Por: 12.5% 11.5 MMbbl/section OOIP 0% 970m TVD / -590mSS Net Pay:6.5m, Por: 9.9% 6.5 MMbbl/section OOIP W W5 20% 0% 20% 0% 1185m TVD / -780mSS Net Pay: 12.5m Por: 9.9% 13 MMbbl/section OOIP Well Cored Extensive and Continuous 1135m TVD / -780mSS Net Pay: 9m, Por:9.8% 9 MMbbl/section OOIP 20% 0% M = 1.8, Sw = 25%, Por cut off = 3%, Boi = % 0%

5 Muskeg Zone: Excellent Well Results Well BOED Well BOED Well BOED Legend Muskeg Wells Future Drills Key Wells #### Phase 4 Well Test Rate #### Phase 3 Well Test Rate #### Phase 2 Well Test Rate Well BOED Well BOED Well BOED 5

6 Evolution of Muskeg Development Phase 1: 2012 Proof of Concept Phase 2: 2013 Trials & Assessment Phase 3: 2014/15 Repeatable & Reliable Phase 4: 2016 Increased Productivity Per Stage 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 6

7 Costs/Stage Reduced by 70% Significant improvements in drilling & completions Drilling longer wells faster Drill & Completion per stage costs reduced by 70% Picture of Pad Drilling Operation: Well: 3550 TMD ; Spud to TD in 10.5 days 7 7

8 Operating Cost Improvements HISTORICAL PRODUCTION COST E Total OPEX ( $MM) Total Production (BOED) 2,562 2,372 1,750 OPEX + Trans Costs ($/BOE) $22.47 $17.29 $19.00 Costs at Marlowe have been reduced by 45% Marlowe Netback* = $17/BOE; Cash Flow Netback* = $7/BOE Production Cost (OPEX + G&A) IMPROVEMENT WITH GROWTH BOED OPEX + Trans G&A Prod. Cost ( $/boe) ( $/boe) ($/boe) 1, , NETBACKS AT MARLOWE IMPROVE FROM $17/BOE TO $27/BOE WITH GROWTH CASH FLOW NETBACKS IMPROVE FROM $7/BOE TO $21/BOE WITH GROWTH 8 * Assumes US$50/Bbl WTI & $3.00/GJ AECO 8

9 West Marlowe: Predictable Well Performance * BOE include Raw Gas 6:1 ratio 9 9

10 Marlowe Economics: Profitable at $40 WTI 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) $ % 150% 100% 50% 0% 2 1 Rate of Return WTI Oil Price ($US/BBL) Payout (Years) WTI Oil Price $US $50 Payout (yrs) 1.0 Rate Of Return (%) 112% PV 10 Profit to Investment Ratio WTI Oil Price ($US/BBL) 6 4 BTAX NPV 10 ($MM CDN) BTAX NPV10 $ WTI Oil Price ($US/BBL) * 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

11 Production (boe/d) Conceptual Development Profile 30,000 Maintain 30,000 boe/d for over wells/year 20,000 10,000 ESTIMATED PRODUCTION - YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7+ Wells Drilled ~35 BOE/D 4,250 7,250 13,000 19,000 26,500 30,000 30,

12 Appendix 12 TSX: SOG

13 Marlowe Infrastructure: 9-17 & 1-28 Plant Sites Fuel Tanks 13 Oil Tank Farm Sales Oil Pumps Process Flare Reverse Osmosis Bldg Shop & Storage Acid Gas Flare Stack Shop / Hangar Skim Tanks & Water Tanks Utility Bldg Warehouse Control Room Power Amine Generation Sweetening Treaters VRU FWKO Heat Medium Acid Gas Compressor Amine Process Acid Gas Compressor Tank Farm Oil Pump Re-fridge 3-stage Plant Compressor Water Pump Inlet Sep ESD Master Control Center Inlet Compressor Office MCC FWKO Effluent Treater TSX: SOG Heater Refridge Plant Site for Second Compressor (Future) Helipad Gas Filter Bldg Sales Compressors Inlet Separator Generator Flare Stack 9-17 Facility Details Sour Processing Facility Gas Facility Startup: 1999 Oil Facility 2008; Expansion 2013 Oil Sales Pipeline Connected Acid Gas Injection / Water Disposal 1-Foreman + 2-Plant + 2 Field Operators 12-hr Shift 1-28 Facility Details Sour Processing Facility Facility Startup: 1999 Gas Plant De-Activated in 2008 Gas Currently Processed at 9-17 Plant License Remains Active Oil Sales Pipeline Connected Acid Gas Injection / Water Disposal 1 Plant + 1 Field Operators 12-hr shift

14 DEVONIAN Marlowe: Multi-Horizon Potential for Oil Development Steen River Slave Pt. 115ft Keg River 90 ft Sulphur Pt. 30 ft Muskeg 60 ft * ERCB Stratigraphic Chart LEGEND HC Zones Clastics Shales Evaporites Carbonates 14