CALGARY – GRANITE OIL CORP. (“Granite” or the “Company”) (TSX:GXO)(OTCQX:GXOCF) is pleased to present the summary results of the independent reserves report (the “Sproule Report”) prepared by Sproule Associates Limited (“Sproule”) with an effective date of December 31, 2019.
In 2019, Granite invested approximately $6.4 million of capital expenditures (unaudited) into its 100%-owned Bakken oil property, representing approximately 45% of its Corporate funds from operations (unaudited), and replaced its Proved Developed Producing (‘PDP’) oil reserves. During the year, Granite drilled and completed one 100% working-interest horizontal development well, and conducted one recompletion in which additional frac stages were added to an existing producing well. Associated PDP finding and development costs for oil were approximately $11.55 per barrel, generating a recycle ratio of 3.0 times. Additionally, a significant portion of the Company’s capital expenditures for the year were invested in projects intended to reduce future operating costs and further enhance the Company’s early-life-cycle gas injection EOR scheme. Over the last three years, Granite has had an average PDP recycle ratio of 2.8, and has dropped its year-over year-capital spending by 66%, demonstrating the efficiency of its long-term Bakken development plan in converting barrels in the ground to developed producing reserves.
Granite increased its Total Proved (‘TP’) oil reserves to 13.5 mmbbls, representing an increase of 1.3 mmbbls when compared to 2018. Total Proved finding and development costs for oil, including the change in future development capital (‘FDC’) of $14.22 million, were $10.88 per barrel, generating a recycle ratio of 3.2 times. A significant contributor to this were positive technical revisions made to undeveloped Bakken locations which reflects the performance of the Company’s four most recent development wells. In keeping with Granite’s focus on increasing well performance and overall recovery, these wells were completed with higher frac sand densities than historically utilized by the Company and have outperformed type-curves. No additional undeveloped drilling locations were booked in the 2019 Sproule Report, thus maintaining a significant inventory of potential infill drilling locations in excess of current bookings. Additionally, following up on Granite’s successful recompletion test, 15 future recompletion candidates were included in the 2019 Sproule Report. Granite had five wells shut-in throughout majority of 2019 in an area being actively re-pressurized by the EOR scheme which are scheduled for a recompletion program in 2020.
Granite increased its Total Proved plus Probable (‘TPP’) oil reserves to 17.5 mmbbls, representing an increase of 1.4 mmbbls from the previous year. Total Proved plus Probable finding and development costs for oil, including the change in FDC of $15.15 million, were $10.97 per barrel, generating a recycle ratio of 3.1 times.
Granite’s properties produced an average of approximately 1,539 bbls of oil per day during 2019. Granite’s average realized all-in operating netback (prior to hedging) for the period is estimated to be $34.21 per barrel of oil equivalent (‘BOE’). All finding and development costs and recycle ratios set out in this news release have been calculated for Company Gross Reserves for oil and NGL volumes using an adjusted operating netback for oil (prior to hedging) for the period estimated to be $34.38 per barrel of oil.
2019 Year End Reserves
The evaluation of Granite’s petroleum and natural gas reserves was prepared by independent reserves evaluator, Sproule, in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). The reserves evaluation is based on forecast prices and costs, and applies Sproule’s forecast escalated commodity price deck, foreign exchange rate, and inflation rate assumptions as at December 31, 2019, as outlined in the table below entitled “Pricing Assumptions”. Financial information presented above is based on management-prepared estimates for the year ended December 31, 2019, which have yet to be audited by Granite’s independent auditors and, accordingly, such financial information is subject to change based on the results of the audit. See “Reader Advisory – Unaudited Financial Information” below.
Summary of Reserves
The following table is a summary of the Company’s estimated reserves as of December 31, 2019, based on the Sproule Report.
Summary of Company Gross Oil and Gas Reserves as at December 31, 2019 (1)(2)(3)(4)(5)(6)(7)
Reserves Category | Oil and NGLs (Mbbl) |
Gas (MMcf) |
Oil Equivalent (MBOE) |
BTAX PV 10% ($000’s) |
Future Development Capital ($000’s) |
Oil Recycle Ratio |
Net Undeveloped Wells Booked |
Proved Developed Producing | 7,008 | 113 | 7,027 | 139,902 | 200 | 3.0 | |
Proved Developed Non-Producing | 418 | 10,185 | 2,115 | 8,268 | 400 | ||
Proved Undeveloped | 6,226 | – | 6,226 | 97,649 | 76,617 | 38 | |
Total Proved | 13,651 | 10,298 | 15,368 | 245,819 | 77,217 | 3.2 | 38 |
Probable Developed Producing | 2,234 | 39 | 2,240 | 28,393 | – | ||
Probable Developed Non-Producing | 147 | 4,427 | 885 | 1,993 | – | ||
Probable Undeveloped | 1,737 | – | 1,737 | 28,860 | 6,722 | 4 | |
Total Probable | 4,118 | 4,466 | 4,862 | 59,246 | 6,722 | 4 | |
Total Proved + Probable | 17,769 | 14,764 | 20,230 | 305,065 | 83,939 | 3.1 | 42 |
Notes:
- The tables summarize data set out in the Sproule Report and may not add due to rounding.
- Reserves have been presented on a gross basis which are the Company’s total working interest share without including any royalty interests of the Company.
- Based on Sproule’s December 31, 2019 escalated price forecast. See “Pricing Assumptions” below.
- The net present value of future net revenues attributable to the Company’s reserves are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis. It should not be assumed that the present worth of estimated future net revenue presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of Granite’s crude oil and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
- The Company’s Bakken and Sunburst reserves are developed with horizontal wells and completed with multi-stage fracturing in the case of the Bakken.
- “Oil” volumes include all Light, Medium, and Heavy crude oil volumes.
- The recycle ratios presented are applicable to oil and NGL volumes using an adjusted 2019 operating netback for oil and NGLs of $34.38 per barrel.
Net Present Values (“NPV”) of Future Net Revenue
The following table is a summary of the estimated net present values of future net revenue (before income taxes) associated with the Company’s reserves as at December 31, 2019, based on the Sproule Report. The calculated NPVs include a deduction for estimated future well abandonment and reclamation but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimates represent the fair market value of the reserves.
Summary of NPV of Future Net Revenue as at December 31, 2019 (1)(2)(3)
Reserves Category | Net Present Value Before Income Taxes Discounted at (%/Year) | ||||
0% $M |
5% $M |
10% $M |
15% $M |
20% $M |
|
Proved | |||||
Proved Developed Producing | 260,258 | 188,732 | 139,902 | 110,598 | 91,793 |
Proved Developed Non-Producing | 65,762 | 15,530 | 8,268 | 6,257 | 5,209 |
Proved Undeveloped | 250,759 | 148,974 | 97,649 | 68,352 | 50,001 |
Total Proved | 576,779 | 353,236 | 245,819 | 185,207 | 147,004 |
Total Probable | 286,339 | 108,016 | 59,246 | 39,311 | 28,805 |
Total Proved + Probable | 863,118 | 461,252 | 305,065 | 224,518 | 175,809 |
Notes:
- The tables summarize data set out in the Sproule Report and may not add due to rounding.
- Based on Sproule’s December 31, 2019 escalated price forecast. See “Pricing Assumptions” below.
- The net present value of future net revenues attributable to the Company’s reserves are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis. It should not be assumed that the present worth of estimated future net revenue presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of Granite’s crude oil and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
Reconciliation of Changes in Reserves and Future Net Revenue
The following table sets forth a reconciliation of Sproule’s estimate of the changes in gross total Company working-interest reserve volumes as at December 31, 2019 against such gross reserves as at December 31, 2018 based on forecast prices and cost assumptions in effect at the time of the respective evaluations.
Reconciliation of Corporate Gross Reserves (1)(2)(3)(4)(5)(6)
Oil and NGL | Conventional Natural Gas | Total | ||||||||||||||||||||
Gross Proved (Mbbl) |
Gross Proved Plus Probable (Mbbl) |
Gross Proved (MMcf) |
Gross Proved Plus Probable (MMcf) |
Gross Proved (MBOE) |
Gross Proved Plus Probable (MBOE) |
|||||||||||||||||
Opening Balance 31-Dec-18 | 12,314.1 | 16,363.4 | 12,073.0 | 16,987.1 | 14,326.3 | 19,194.5 | ||||||||||||||||
Product Type Transfer | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Extensions | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Infill Drilling | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Improved Recovery | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Technical Revisions | 1,906.4 | 1,976.9 | (1,673.9 | ) | (2,105.0 | ) | 1,627.4 | 1,626.0 | ||||||||||||||
Discoveries | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Acquisitions | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Dispositions | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||
Economic Factors | (7.6 | ) | (9.5 | ) | (85.8 | ) | (103.0 | ) | (21.9 | ) | (26.7 | ) | ||||||||||
Production | (561.6 | ) | (561.6 | ) | (15.0 | ) | (15.0 | ) | (564.1 | ) | (564.1 | ) | ||||||||||
Closing Balance 31-Dec-19 | 13,651.3 | 17,769.1 | 10,298.3 | 14,764.1 | 15,367.7 | 20,229.8 | ||||||||||||||||
Total Adds | 1,337.2 | 1,405.8 | (1,774.7 | ) | (2,223.0 | ) | 1,041.4 | 1,035.3 | ||||||||||||||
Capital Summary (M$) | Proved | Proved+ Probable | ||||||||||||||||||||
Future Development Capital | 77,217.38 | 83,938.93 | ||||||||||||||||||||
Change in FDC v. 2018 Sproule Report | 14,224.88 | 15,151.93 |
Notes:
- The tables summarize data set out in the Sproule Report and may not add due to rounding.
- “Technical Revisions” are a result of changes in performance of new and existing wells and economic parameters.
- Changes related to “Economic Factors” are a result of the differences in Sproule’s Forecast Prices used in the 2019 Sproule Report and Sproule’s Forecast Prices used in the 2018 Sproule Report.
- “Production” represents the Corporation’s actual production for the year ended December 31, 2019.
- “Oil” volumes include all Light, Medium, and Heavy Crude Oil volumes.
- “Conventional Natural Gas” volumes include solution gas, associated and non-associated gas.
Future Development Capital (“FDC”)
The following table provides a summary of the estimated FDC required to bring the Company’s undeveloped reserves to production, which have been deducted in the estimation of future net revenue attributable to such reserves. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities, and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved undeveloped and probable reserves on production using forecast prices and costs.
Future Development Costs of Undeveloped Reserves (1)
Future Development Capital | ($M) | ($M) | ||
Year | Total Proved | Total Proved + Probable | ||
2020 | 7,350 | 7,350 | ||
2021 | 15,163 | 15,163 | ||
2022 | 21,883 | 21,883 | ||
2023 | 20,079 | 20,702 | ||
2024 and remaining | 12,742 | 18,841 | ||
Total Undiscounted FDC | 77,217 | 83,939 | ||
Total Discounted FDC at 10%/Year | 60,062 | 64,482 |
Note:
- Numbers may not add due to rounding.
Pricing Assumptions
The following table summarizes Sproule’s commodity price forecast and foreign exchange rate and inflation rate assumptions as at December 31, 2019, as applied in the Sproule Report. Forecast pricing for the year 2020 decreased by 4% for oil and decreased by 16% for gas when comparing Sproule’s pricing assumptions included in the December 31, 2019 Sproule Report versus Sproule’s December 31, 2018 reserves report. The longer-term price forecast decreased on average by 9% over the following 10 years for oil, and decreased on average by 12% for the following 10 years for gas when comparing Sproule’s pricing assumptions in the December 31, 2019 report versus the December 31, 2018 report.
Forecast Pricing and Foreign Exchange Rates (1)(2)(3)(4)(5)
Western Canada Select 20.5° API ($Cdn/bbl)(4) |
Alberta AECO-C Spot ($Cdn/Mmbtu)(5) |
Exchange Rate (2) ($US/$Cdn) |
Edmonton Propane ($Cdn/bbl) |
Edmonton Butane ($Cdn/bbl) |
Edmonton Pentanes Plus ($Cdn/bbl) |
||
Forecast(3) | |||||||
2020 | 59.81 | 2.04 | 0.76 | 25.07 | 37.72 | 76.32 | |
2021 | 63.98 | 2.27 | 0.77 | 31.84 | 43.90 | 80.52 | |
2022 | 63.77 | 2.81 | 0.80 | 32.43 | 47.74 | 80.00 | |
2023 | 65.04 | 2.89 | 0.80 | 33.26 | 48.69 | 81.68 | |
2024 | 66.34 | 2.98 | 0.80 | 34.12 | 49.67 | 83.38 | |
2025 | 67.67 | 3.06 | 0.80 | 34.99 | 50.66 | 85.13 | |
Thereafter Escalation Rate of 2.0% |
Notes:
- This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
- The exchange rate used to generate the benchmark reference prices in this table.
- As at December 31, 2019.
- The price received for the Company’s oil, which is considered to be Medium crude oil, has historically corresponded closely to Western Canada Select 20.5° API ($Cdn/Bbl), plus associated quality adjustments.
- The price received for the Company’s natural gas has historically corresponded to AECO-C Spot pricing ($Cdn/MMBtu), adjusted for heat value and transportation.