ADVISORY G R A N I T E O I L C O R P. T S X : G X O 2

Transcription

1 218 AGM

2 ADVISORY Certain statements contained in this Presentation constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities legislation. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as seek, anticipate, plan, continue, estimate, expect, may, will, project, predict, potential, targeting, intend, could, might, should, believe, and similar expressions. These statements involve known and unknown risks, uncertainties and other factors facing the Corporation. Risks, uncertainties and other factors may bebeyond the Corporation s control and may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this Presentation should not be unduly relied upon by investors. These statements speak only as at the date of this Presentation and are expressly qualified, in their entirety, by this cautionary statement. In particular, this Presentation contains forwardlooking statements pertaining to the following: future and alternative plans and operations; expectations of future production, costs and cash flow. With respect to forward-looking statements contained in this Presentation, the Company has made assumptions regarding, among other things, results of future operations, commodity prices, costs of operations, the legislative and regulatory environments of the jurisdictions where the Company carries on business or has operations, the impact of increasing competition and the Company s ability to obtain additional financing on satisfactory terms. The Company s actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors included in this Presentation such as: the impact of general economic conditions; industry conditions; volatility in the market prices for natural gas and crude oil; currency fluctuations; uncertainties associated with estimating reserves; geological, technical, drilling and processing problems; liabilities and risks, including environmental liabilities and risks inherent in natural gas and crude oil operations; stock market volatility; the ability to access sufficient capital; and, competition for, among other things, capital, undeveloped lands and skilled personnel. This forward-looking information represents the Company s views as at the date of this Presentation and such information should not be relied upon as representing its views as of any date subsequent to the date of this Presentation. The Company has attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. The forward-looking statements contained in this Presentation speak only as of the date of this Presentation. The Company does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. Test Rates. Test rates are not necessarily indicative of long-term performance or of ultimate recovery. Neither a pressure transient analysis nor a well-test interpretation has been carried out and the data should be considered to be preliminary until such analysis or interpretation has been done. G R A N I T E O I L C O R P. T S X : G X O 2

3 WHOLLY OWNED, PURE PLAY, CONCENTRATED, LARGE OIL RESOURCE Bakken Oil Pool in a 3 mile, 8 section oil fairway 1/ W4 1% ownership and no competitive drainage 228 MMbbls OOIP (1) under an approved Gas Injection EOR Scheme Bakken Exshaw GXO Upper Bakken Sand Middle Bakken Silt (Typical Exploration Target) Up To: 14 m Thick 18% Porosity 2 md Permeability T1 T9 Early life cycle with only 2.2% recovered (2) T8 Over 8 potential Bakken infill well locations Delineation and exploration upside T7 Liability Management Ratio (LMR) of 8.62 T6 Only 23 miles to Canada-U.S. Border providing more options for direct-to-refinery sales T5 PRODUCTIVE AREA COMPARISON Elm Coulee Viewfield T4 Ferguson LEGEND T3 Company Land Company Wells Area Wells T2 Company Gas Pipelines Market Oil Pipelines 3 Mile, 8 Section Alberta Bakken Oil Fairway Market Gas Pipelines Company Oil Battery Gas Facility T1 R22 R2 R19 R18 R17 R16 R15 R14W4 G R A N I T E O I L C O R P. T S X : G X O 3 R21

4 PDP Reserves (MBOE) Recycle Ratio PDP F&D ($/BOE) Oil Production (bbl/d) HISTORICAL DRILLING AND RESERVE RESULTS WELL PERFORMANCE SINCE 215 TESTING SPACING AND BUILDING A FORMULA Well - 4 m spacing Well - 2 m spacing Days On Production 4 m (215) 2 m (216) 11 m (217) IMPROVING RESERVE METRICS YEAR OVER YEAR SINCE 215 8, 6, 5,566 31% Growth in PDP Reserves 67% Reduction in PDP F&D Top Tier Recycle Ratios 6,178 7, , 2 2 2, PDP Reserves PDP Recycle Ratio PDP F & D G R A N I T E O I L C O R P. T S X : G X O 4

5 SIGNIFICANT DRILLING INVENTORY DEVELOPMENT PLAN MAP 85 potential Bakken well locations on 2 m offset spacing (3) LEGEND Company Land Company Gas Inj Company Wells Future Locations DEVELOPMENT OPTIONALITY SLOW GROWTH Drilling 5 wells per year allows for ~16 years of future development with production estimated to average 235 boe/d and providing estimated average free cash flow of ~$18.4 mm* per year over the first 1 years ACCELERATED GROWTH Drilling 8 wells per year allows for ~1 years of future development with production estimated to average 31 boe/d and providing estimated average free cash flow of ~$21.5 mm* per year over 1 years * As per July 12, 218 strip pricing - (218E: WTI US$67.8/bbl, AECO C$1.63/mcf, UDS/CAD 1.3) G R A N I T E O I L C O R P. T S X : G X O 5

6 Oil Production (bbl/d) OUTPUT INPUT Oil Production (bbl/d) Oil Production (bbl/d) TOP TIER WELL ECONOMICS TYPE CURVE ECONOMICS SUMMARY (4) 4 35 Average Payout.7 years Average NPV 1% BT $3.96 m Average Recycle 6.5x Internal GXO 25-3m Historical Performance 25-3m (27 Wells) 1 GXO TYPE CURVE ECONOMICS BY MEASURED DEPTH CATEGORY (4) Measured Depth Category * 25-3m 3-4m 4m Cumulative Oil Production (Mbbl) EUR Oil mbbl IP 9 Oil bbl/d Well Cost $m $1,45 $1,575 $1,7 Operating Costs - Fixed $/w/m $4,5 $4,5 $4,5 Operating Costs - Variable $/bbl $1.95 $1.95 $1.95 NPV 1% BT $m $3,42 $3,725 $4,727 IRR % 159% 197% 36% Payout years F&D $/bbl Recycle x 6.4x 6.3x 6.9x Netback (Year 1) $/boe $5.96 $51.18 $51.38 GXO Internal Curves Length Category 25-3 m 3-4 m >4 m Total Number of Potential Locations Internal GXO 3-4m Historical Performance 3-4m (26 Wells) Cumulative Oil Production (Mbbl) Internal GXO 4m+ Historical Performance 4m+ (22 Wells) Cumulative Oil Production (Mbbl) * As per July 12, 218 strip pricing - (218E: WTI US$67.8/bbl, AECO C$1.63/mcf, UDS/CAD 1.3) using Sproule offsets G R A N I T E O I L C O R P. T S X : G X O 6

7 GAS INJECTION EOR PROCESS GRANITE BAKKEN EOR BASICS Injecting gas in the top of the reservoir Increases/maintains reservoir pressure Adding gas to undersaturated oil Decreases viscosity and increases oil mobility Keeping the CO2 in the reservoir/oil Swells the oil and maintains oil mobility G R A N I T E O I L C O R P. T S X : G X O 7

8 CHIGWELL - VIKING E SUFFIELD - LOWER MANNVILLE J SUFFIELD - UPPER MANNVILLE N TURNER VALLEY - RUNDLE CHIGWELL - VIKING I ZAMA - MUSKEG L ZAMA - KEG RIVER G2G CAROLINE - CARDIUM E ZAMA - KEG RIVER RRR RAINBOW SOUTH - KEG RIVER G ZAMA - KEG RIVER NNN RAINBOW - KEG RIVER FF RAINBOW SOUTH - KEG RIVER E ANTE CREEK - BEAVERHILL LAKE ZAMA - KEG RIVER F ENCHANT - ARCS F,G KAYBOB SOUTH - TRIASSIC A VIRGINIA HILLS - BEAVERHILL LAKE SWAN HILLS SOUTH - BEAVERHILL LAKE A,B GOOSE RIVER - BEAVERHILL LAKE A KAYBOB - BEAVERHILL LAKE A ENCHANT - CMG POOL 17 - ARCS A,B JUDY CREEK - BEAVERHILL LAKE B RAINBOW - KEG RIVER E JUDY CREEK - BEAVERHILL LAKE A SWAN HILLS - BEAVERHILL LAKE A,B NIPISI - GILWOOD A JOFFRE - LEDUC B LEDUC - D-2A JOFFRE - VIKING MITSUE - GILWOOD A PEMBINA - NISKU G2G RAINBOW - KEG RIVER Z BIGORAY - NISKU B PEMBINA - NISKU D PEMBINA - NISKU F PEMBINA - NISKU P PEMBINA - NISKU L Recovery Factor (%) Oct-1958 Oct-1959 Oct-196 Oct-1961 Oct-1962 Oct-1963 Oct-1964 Oct-1965 Oct-1966 Oct-1967 Oct-1968 Oct-1969 Oct-197 Oct-1971 Oct-1972 Oct-1973 Oct-1974 Oct-1975 Oct-1976 Oct-1977 Oct-1978 Oct-1979 Oct-198 Oct-1981 Oct-1982 Oct-1983 Oct-1984 Oct-1985 Oct-1986 Oct-1987 Oct-1988 Oct-1989 Oct-199 Oct-1991 Oct-1992 Oct-1993 Oct-1994 Oct-1995 Oct-1996 Oct-1997 Oct-1998 Oct-1999 Oct-2 Oct-21 Oct-22 Oct-23 Oct-24 Oil Production (mbbl/d) Oil (mbbl/d) Gas Production Gas Production (mmcf/d) (mmcf/d) Injected Gas (mmcf/d) Producing Well Count Injecting Well Count Producing Well Count Injecting Well Count GAS INJECTION POTENTIAL FULL CYCLE DEVELOPMENT OF THE SWANSON RIVER POOL, ALASKA, AND HISTORICAL ALBERTA GAS FLOOD RECOVERY FACTORS ALASKA SWANSON RIVER STAGES OF GAS INJECTION EOR DEVELOPMENT Testing EOR Responding to reservoir behavior; setting up for long-term pool performance Early primary development Initial drilling, primary production 1, Full-scale EOR Maintaining pressure; managing production with reduced drilling and improved, long-term base decline Terminal Pool Decline and Blow Down Maximizing value from an end-of life pool % recovery in 47 years in an Undersaturated Reservoir HISTORICAL ALBERTA GAS FLOODS* 1% 8% Total Primary GXO Current Recovery Factor Sproule Study Average Recovery Factor 6% 4% 2% % Average Recovery Factor Current Ferguson Pool Recovery Factor 2.2% Ferguson Pool Target Recovery Factor G R A N I T E O I L C O R P. T S X : G X O 8 *Sproule 212 Resource Study: Solvent Floods

9 Oil Production (bbl/d) 18,112 $21, 11,89 $18, 11,217 $9,5 5,132 34,95 4,529 37,679 $39, Total Capital Investment ($M) Total Lateral Meters Drilled $ 91, $84, $11, DEVELOPING AN EARLY LIFE CYCLE POOL TO MAXIMIZE RETURNS HISTORICAL PRODUCTION AND CAPITAL EFFICIENCY SUCCESS 6 12, 5 1, 4 3 Commenced EOR-Focused Development 8, 6, 2 4, Oil Production Total Capital Investment Total Lateral Meters Drilled 2, 218 To Date SINCE MOVING TO EOR-FOCUSED DEVELOPMENT POST % Reduction in annual capital 7% Reduction in lateral meters drilled per year 45% Increase in PDP reserves Conversion of 13 producing wells to gas injectors G R A N I T E O I L C O R P. T S X : G X O 9

10 SUMMARY Large Oil-in-Place 33 section delineated oil pool in a 3 mile, 8 section oil fairway Early Life Cycle Only recovered 2.2% to date (2) Efficient Recovery Formula 228 MMbbls of OOIP (1) under an effective gas injection EOR scheme Economic Inventory Inventory of 85 potential Bakken well locations with robust economics at >115% IRR and less than 1 year payouts (4) 1% Ownership 1% ownership of land and facilities with plenty of capacity for additional production and a favorable LMR of 8.62 Delineation and Exploration Upside Opportunities Significant upside to the existing producing pool with additional delineation and exploratory opportunities in the Bakken, Sunburst, Big Valley G R A N I T E O I L C O R P. T S X : G X O 1

11 ENDNOTES 1. This estimate of Original Oil-in-Place (OOIP) was internally generated by management for the area currently approved by the Alberta Energy Regulator for Enhanced Oil Recovery by Gas Injection as well as the areas defined as PODs for EOR-focused development and represent management s best estimate of the OOIP given available data at the time of estimation (December, 217). Original Oil-in-Place (OOIP) is an estimate of the total volume of oil stored in a reservoir prior to production. It is not an estimate of, nor is it equivalent to, Total Proved Plus Probable (TPP) reserves, which is an estimate of the volume of hydrocarbons that can be economically extracted from a reservoir via existing technology with designated commodity price assumptions. 2. The estimated recovery factor of 2.2% is based on cumulative oil production of 5.1 million from wells within the current AER-approved EOR area which is estimated to contain 228 million barrels of Original Oil-in-Place as at December, 217. See Note 1 above. 3. Granite currently has 33 Bakken locations that have been assigned Proven Undeveloped (PUD) reserves and three Bakken locations that have been assigned Probable Undeveloped (PAUD) reserves. Due to differences in the surface hole and/or bottom hole locations of the Bakken well locations identified relative to the surface and / or bottom hole locations of the PUD and PAUD reserves currently booked, none have been assigned Reserves or Resources Other than Reserves in their current form. 4. The type curves presented were internally generated by management and are what management sees as representative of estimated Total Proved Plus Probable (TPP) Reserves for wells within the Ferguson Pool Area. This type curve does not apply to one well location or specific group of wells that have been assigned Reserves by Sproule and no Reserves or Resources Other than Reserves have been assigned to this type curve. G R A N I T E O I L C O R P. T S X : G X O 11