NOTE 6 – PROPERTY AND EQUIPMENT
| Canadian Oil | United States | |||||||||||
| and Gas | Oil and Gas | Corporate and | ||||||||||
| Properties | Properties | Other Assets | Total | |||||||||
| $ | $ | $ | $ | |||||||||
| Cost: | ||||||||||||
| Balance at January 1, 2016 | 33,376 | 16,653 | 179 | 50,208 | ||||||||
| Additions | 300 | 225 | 3 | 528 | ||||||||
| Change in decommissioning provision | (48 | ) | (4 | ) | - | (52 | ) | |||||
| Foreign currency translation and other | - | (502 | ) | - | (502 | ) | ||||||
| Balance at December 31, 2016 | 33,628 | 16,372 | 182 | 50,182 | ||||||||
| Additions | 405 | 39 | 5 | 449 | ||||||||
| Change in decommissioning provision | 94 | (3 | ) | - | 91 | |||||||
| Disposals | - | - | (29 | ) | (29 | ) | ||||||
| Foreign currency translation and other | - | (1,060 | ) | - | (1,060 | ) | ||||||
| Balance at December 31, 2017 | 34,127 | 15,348 | 158 | 49,633 |
| Canadian Oil | United States | |||||||||||
| and Gas | Oil and Gas | Corporate and | ||||||||||
| Properties | Properties | Other Assets | Total | |||||||||
| $ | $ | $ | $ | |||||||||
| Accumulated amortization, depletion and impairment | ||||||||||||
| losses: | ||||||||||||
| Balance at January 1, 2016 | (26,774 | ) | (1,375 | ) | (160 | ) | (28,309 | ) | ||||
| Amortization and depletion | (1,248 | ) | (380 | ) | (5 | ) | (1,633 | ) | ||||
| Impairment losses | (1,070 | ) | - | - | (1,070 | ) | ||||||
| Foreign currency translation and other | - | 41 | 1 | 42 | ||||||||
| Balance at December 31, 2016 | (29,092 | ) | (1,714 | ) | (164 | ) | (30,970 | ) | ||||
| Amortization and depletion (Note 7) | (561 | ) | (223 | ) | (3 | ) | (787 | ) | ||||
| Impairment losses (Note 7) | (870 | ) | - | - | (870 | ) | ||||||
| Disposals | - | - | 25 | 25 | ||||||||
| Foreign currency translation and other | - | 131 | - | 131 | ||||||||
| Balance at December 31, 2017 | (30,523 | ) | (1,806 | ) | (142 | ) | (32,471 | ) |
| Canadian Oil | United States | |||||||||||
| and Gas | Oil and Gas | Corporate and | ||||||||||
| Properties | Properties | Other Assets | Total | |||||||||
| $ | $ | $ | $ | |||||||||
| Carrying amounts: | ||||||||||||
| At December 31, 2016 | 4,536 | 14,658 | 18 | 19,212 | ||||||||
| At December 31, 2017 | 3,604 | 13,542 | 16 | 17,162 |
Canadian Oil and Gas Properties
Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $Nil (December 31, 2016 - nil; December 31, 2015 - $nil) as estimated by the Company’s external reserves evaluator.
During the year ended December 31, 2017, the Company capitalized $7,000 (December 31, 2016 – $104,000) of general and administrative costs related to its Canadian oil and gas interests.
In accordance with IFRS, impairment tests were conducted at December 31, 2017 on each of the Company’s CGUs. The estimated recoverable amounts were determined using fair value less cost to sell. In determining the recoverability of oil and gas interests and making these evaluations, the Company used the net present value of the cash flows from proved plus probable oil and gas reserves of each CGU as estimated by the Company’s independent reserve evaluator.
Key input estimates used in the determination of cash flows from oil and gas reserves include the following:
| a) |
Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated. |
| b) |
Crude oil and natural gas prices – Forward price estimates of the crude oil and natural gas prices are used in the cash flow model. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors. |
| c) |
Discount rate – The discount rate used to calculate the net present value of cash flows is 14.4% post tax. |
Below are the following forward commodity price estimates used in the December 31, 2017 impairment test:
| Natural gas | NGL | Crude oil | |||||||
| (AECO) | (Edmonton Pentanes Plus) | (Edmonton Par) | |||||||
| Cdn $ / mmbtu | Cdn $ / bbl | Cdn $ / bbl | |||||||
| 2018 | 2.20 | 76.42 | 70.25 | ||||||
| 2019 | 2.54 | 74.68 | 70.25 | ||||||
| 2020 | 2.88 | 74.38 | 70.31 | ||||||
| 2021 | 3.24 | 77.16 | 72.84 | ||||||
| 2022 | 3.47 | 79.88 | 75.61 | ||||||
| 2023 | 3.58 | 82.53 | 78.31 | ||||||
| 2024 | 3.66 | 86.14 | 81.93 | ||||||
| 2025 | 3.73 | 89.76 | 85.54 | ||||||
| 2026 | 3.80 | 92.57 | 88.35 | ||||||
| 2027 | 3.88 | 94.43 | 90.22 | ||||||
| Each benchmark price increased on average approximately 2% thereafter | |||||||||
For the year ended December 31, 2017, the Company recorded an impairment of $870,000 (December 31, 2016 - $940,000) on its Drake/Woodrush CGU. The impairment was recognized because the carrying value exceeded the recoverable amount. The fair value less cost to sell values used to determine the recoverable amounts of the impaired PP&E assets are classified as Level 3 fair value measurements.
On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at Woodrush, currently scheduled to commence in the first quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total cost of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”).
The investment firm has the right to elect to participate in the drilling and completion of a 2 nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.
United States Oil and Gas Properties
Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $83.7 million (December 31, 2016 - $84.0 million; December 31, 2015 - $86.4 million) as estimated by the Company’s external reserves evaluator.
During the year ended December 31, 2017, the Company capitalized $12,000 (December 31, 2016 – $14,000) of general and administrative costs related to its US oil and gas interests.
At December 31, 2017 and December 31, 2016, the Company evaluated its oil and gas interests for indicators of any impairment or related recovery. The Company determined the recoverable amount of the CGU based on the cash flows from oil and gas reserves, using a discount rate of 14.3% (post tax) and determined there was no impairment at December 31, 2017 and December 31, 2016. The key inputs used included forward prices from NYMEX futures (adjusted for an inflationary factor), a discount rate of 14.3% (post tax) which was applied to the discounted cash flows and the reserves that were estimated.