Canacol Energy Ltd. Achieves 122% 2P Gas Reserve Replacement Ratio Increasing 2P Reserves to 637 BCF With a BTAX Value of US$1.7 Billion
Canacol Energy Ltd. reported its conventional natural gas reserves for the fiscal year ending December 31, 2020. Key highlights include:
- Total Proved + Probable Reserves (2P) increased by 2.2% to 637 Bcf.
- Before tax NPV-10 for 2P reserves is estimated at US$ 1.7 billion.
- Reserves life index (RLI) is at 10.3 years, indicating strong production sustainability.
- The company achieved a reserve replacement rate of 122%.
- 2020 Finding and Development Cost (F&D) was US$ 0.84/Mcf.
These metrics reflect Canacol's robust drilling success in Colombia despite pandemic-related challenges.
- Total Proved + Probable Reserves (2P) increased by 2.2% to 637 Bcf, indicating growth in reserves.
- Before tax NPV-10 for 2P reserves estimated at US$ 1.7 billion reflects solid asset value.
- Reserves Life Index (RLI) of 10.3 years suggests stable production performance.
- Reserve replacement rate of 122% indicates effective resource management.
- Finding and Development Cost (F&D) of US$ 0.84/Mcf demonstrates cost efficiency.
- Limited drilling activities in 2020 due to COVID-19 impacted exploration plans.
CALGARY, Alberta, March 03, 2021 (GLOBE NEWSWIRE) -- Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX: CNE; OTCQX: CNNEF; BVC: CNEC) is pleased to report its conventional natural gas reserves for the fiscal year end December 31, 2020. The Corporation’s conventional natural gas reserves are located in the Lower Magdalena Valley basin, Colombia.
Canacol Energy Ltd Gross Natural Gas Reserves Summary
| Gross Reserves | |||||||||
| Proved Developed | Total | Total Proved | Total Proved + Probable | ||||||
| Producing | Proved | + Probable | + Possible | ||||||
| Product Type | (“PDP”) | ("1P") | ("2P") | ("3P") | |||||
| Conventional natural gas | Bcf | 276.9 | 394.8 | 637.2 | 951.1 | ||||
| Total oil equivalent(3) | MMBOE | 48.6 | 69.3 | 111.8 | 166.9 | ||||
| Before tax NPV-10(4) | MM US$ | $ | 750.8 | $ | 1,030.6 | $ | 1,688.2 | $ | 2,407.1 |
| After tax NPV-10(4) | MM US$ | $ | 631.5 | $ | 822.6 | $ | 1,269.8 | $ | 1,758.8 |
| (1) | The numbers in this table may not add exactly due to rounding. |
| (2) | All reserves are represented at Canacol’s working interest share before royalties. |
| (3) | The term “BOE” means a barrel of oil equivalent on the basis of 5.7 Mcf of natural gas to 1 barrel of oil (“bbl”) as per Colombian regulatory practice. |
| (4) | Net Present Value (NPV) is stated in millions of USD and is discounted at 10 percent. |
Highlights
Conventional Natural Gas Proved + Probable Reserves (“2P”):
- Increased by
2.2% since December 31, 2019, totaling 637 Bcf at December 31, 2020, with a before tax value discounted at10% of US$ 1.7 billion , representing both CAD$ 11.97 per share of reserve value, and CAD$ 9.55 per share of 2P net asset value (net of US$341.8 million of net debt) - Reserve replacement of
122% based on calendar 2020 gross conventional natural gas reserve additions of 75 Bcf - 2P Finding and Development Cost (“F&D”) of US
$ 0.84 / Mcf for the three-year period ending December 31, 2020 - Recycle ratio of 2.7x for the year ended December 31, 2020 (calculated based on the natural gas netback of US
$ 3.57 / Mcf for the year ended December 30, 2020) - Recycle ratio of 4.4x for the three-year period ending December 31, 2020 (calculated based on the weighted average natural gas netback of US
$ 3.71 / Mcf for the years ended December 31, 2020, 2019 and 2018) - Reserves life index (“RLI”) of 10.3 years based on annualized fourth quarter 2020 conventional natural gas production of 170,087 Mcfpd or 29,840 BOEPD
- RLI of 9.2 years based on conventional natural gas production guidance of 190,000 Mcfpd for calendar 2021 (high end 2021 production guidance as announced December 17, 2020)
Conventional Natural Gas Proved Developed Producing Reserves (“PDP”):
- Increased by
9.9% since December 31, 2019, totaling 277 Bcf at December 31, 2020 - Reserve replacement of
140% based on calendar 2020 gross conventional natural gas reserve additions of 87 Bcf
Conventional Natural Gas Total Proved Reserves (“1P”):
- Increased by
0.2% since December 31, 2019, totaling 395 Bcf at December 31, 2020 - Reserve replacement of
101% based on calendar 2020 gross conventional natural gas reserve additions of 63 Bcf - 1P F&D of US
$ 1.18 / Mcf for the three-year period ending December 31, 2020 - Recycle ratio of 2.1x for the year ended December 31, 2020 (calculated based on the natural gas netback of US
$ 3.57 / Mcf for the year ended December 30, 2020) - Recycle ratio of 3.2x for the three-year period ending December 31, 2020 (calculated based on the weighted average natural gas netback of US
$ 3.71 / Mcf for the years ended December 31, 2020, 2019 and 2018) - RLI of 6.4 years based on annualized fourth quarter 2020 conventional natural gas production of 170,087 Mcfpd or 29,840 BOEPD
- RLI of 5.7 years based on conventional natural gas production guidance of 190,000 Mcfpd for calendar 2021 (high end 2021 production guidance as announced December 17, 2020)
Conventional Natural Gas Total Proved + Probable + Possible Reserves (“3P”):
- Increased by
7.5% since December 31, 2019, totaling 951 Bcf at December 31, 2020, with a before tax value discounted at10% of US$ 2.4 billion - Reserve replacement of
207% based on calendar 2020 gross conventional natural gas reserve additions of 128 Bcf - 3P F&D of US
$ 0.51 / Mcf for the three-year period ending December 31, 2020 - Recycle ratio of 4.4x for the year ended December 31, 2020 (calculated based on the natural gas netback of US
$ 3.57 / Mcf for the year ended December 30, 2020) - Recycle ratio of 7.3x for the three-year period ending December 31, 2020 (calculated based on the weighted average natural gas netback of US
$ 3.71 / Mcf for the years ended December 31, 2020, 2019 and 2018) - RLI of 15.3 years based on annualized fourth quarter 2020 conventional natural gas production of 170,087 Mcfpd or 29,840 BOEPD
- RLI of 13.7 years based on conventional natural gas production guidance of 190,000 Mcfpd for calendar 2021 (high end 2021 production guidance as announced December 17, 2020)
Mr. Ravi Sharma, Chief Operating Officer of Canacol, commented, “I am pleased to announce that even with a 2020 drilling program that was much reduced due to COVID-19, the Corporation managed to more than replace production, which is a direct indication of our high quality drilling portfolio. The Corporation has historically achieved significant conventional natural gas exploration and development drilling success from our assets located in the Lower Magdalena Valley. This success continued into 2020 despite the global pandemic and only drilling six of 12 planned wells, with only two being exploration wells. Since 2013, we have added 771 BCF of 2P conventional natural gas reserves from commercial success in 33 out of 37 drilled wells, representing a
Discussion of Year Ended December 31, 2020 Reserves Report
During the year ended December 31, 2020, the Corporation recorded increases in certain reserve categories as a result of the drilling and completion of locations at Nelson-14 on the Esperanza natural gas block, and Clarinete-5, Pandereta-8, Pandereta-4 and Porro Norte-1 on the VIM-5 natural gas block, and Fresa-1 on the VIM-21 natural gas block, all in the Lower Magdalena Valley basin, Colombia.
The following tables summarize information from the independent reserves report prepared by Boury Global Energy Consultants Ltd. (“BGEC”) effective December 31, 2020 (the “BGEC 2020 report”). The BGEC 2020 report covers
The BGEC 2020 report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument NI 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 is included in the Corporation’s Annual Information Form, which will be filed on SEDAR by March 31, 2021.
Canacol Gross Natural Gas Reserves for the Year Ended December 31, 2020
| Reserve Category(1) | 31-Dec-19 | 31-Dec-20 | Difference | |
| (Bcf) | (Bcf) | (%) | ||
| Proved Developed Producing (PDP) | 251,865 | 276,869 | + | |
| Total Proved (1P) | 394,148 | 394,792 | + | |
| Total Proved + Probable (2P) | 623,758 | 637,249 | +2.2% | |
| Total Proved + Probable + Possible (3P) | 884,838 | 951,069 | + | |
| (1) | All reserves are Canacol working interest before royalties. |
5-Year Gas Price Forecast – BGEC Report December 31, 2020
| Reserve | |||||||
| Report Date | 2021 | 2022 | 2023 | 2024 | 2025 | ||
| Volume weighted Total Proved + Probable (2P) average gas price | US$/Mcf | 31-Dec-20 | 4.39 | 4.93 | 5.12 | 5.29 | 5.59 |
| (1) | The gas price forecast is based on existing long term contracts net of transportation (if applicable) and adjusted for inflation, along with interruptible gas sales pricing based on forecasts from La Unidad de Planeación Minero Energética (“UPME”), a special administrative unit of the Colombian Ministry of Mines and Energy. |
Natural Gas Reserves Net Present Value Before & After Tax Summary (1)
| Before tax | After tax | ||||||||
| Net Asset | Net Asset | ||||||||
| Value | Value | ||||||||
| Reserve Category | 31-Dec-20 | 31-Dec-20 | 31-Dec-20 | 31-Dec-20 | |||||
| (M US$)(2) | (C$/share)(2) | (M US$)(2) | (C$/share)(2) | ||||||
| Proved Developed Producing (PDP) | $ | 750,849 | $ | 2.90 | $ | 631,479 | $ | 2.05 | |
| Total Proved (1P) | $ | 1,030,556 | $ | 4.88 | $ | 822,594 | $ | 3.41 | |
| Total Proved + Probable (2P) | $ | 1,688,153 | $ | 9.55 | $ | 1,269,840 | $ | 6.58 | |
| Total Proved + Probable + Possible (3P) | $ | 2,407,125 | $ | 14.65 | $ | 1,758,806 | $ | 10.05 | |
| (1) | Net present value is stated in thousands of USD and is discounted at 10 percent. The forecast prices used in the calculation of the present value of future net revenue are based on the price deck described above. The BGEC forecast for gas prices at December 31, 2020 are included in the Corporation’s Annual Information Form. |
| (2) | Net asset value ("NAV") is calculated as at December 31, 2020 NPV10 less estimated net debt of US |
Reserve Life Index (“RLI”)(3)
| Reserve Category | 31-Dec-19 | 31-Dec-20 |
| (yrs)(1) | (yrs)(2) | |
| Proved Developed Producing (PDP) | 3.8 | 4.5 |
| Total Proved (1P) | 6.0 | 6.4 |
| Total Proved + Probable (2P) | 9.4 | 10.3 |
| Total Proved + Probable + Possible (3P) | 13.4 | 15.3 |
| (1) | Calculated using average 3 month ending December 31, 2019 natural gas production of 180,986 Mcfpd or 31,752 BOEpd annualized. |
| (2) | Calculated using average 3 month ending December 31, 2020 natural gas production of 170,087 Mcfpd or 29,840 BOEpd annualized. |
| (3) | “RLI” Reserve Life Index is calculated by dividing the applicable reserves category by the annualized fourth quarter production. |
Year Ended December 31, 2020 Canacol Gross Reserves Reconciliation (1)
| Total Oil | Light/Med Crude Oil | Heavy Crude Oil | Conventional Natural Gas | NGL | TOTAL | ||||
| (MBBL) | (MBBL) | (MBBL) | (MMCF) | (MBBL) | MBOE(5) | ||||
| PROVED DEVELOPED PRODUCING | |||||||||
| Opening Balance (December 31, 2019) | - | - | - | 251,865 | - | 44,187 | |||
| Extensions(2) | - | - | - | 33,063 | - | 5,801 | |||
| Improved Recovery | - | - | - | - | - | - | |||
| Technical Revisions(3) | - | - | - | 48,312 | - | 8,476 | |||
| Discoveries(4) | - | - | - | 5,536 | - | 971 | |||
| Acquisitions | - | - | - | - | - | - | |||
| Dispositions | - | - | - | - | - | - | |||
| Economic Factors | - | - | - | - | - | - | |||
| Production | - | - | - | (61,907 | ) | - | (10,861 | ) | |
| Closing Balance (December 31, 2020) | - | - | - | 276,869 | - | 48,574 | |||
| Total Oil | Light/Med Crude Oil | Heavy Crude Oil | Conventional Natural Gas | NGL | TOTAL | ||||
| (MBBL) | (MBBL) | (MBBL) | (MMCF) | (MBBL) | MBOE(5) | ||||
| TOTAL PROVED | |||||||||
| Opening Balance (December 31, 2019) | - | - | - | 394,148 | - | 69,149 | |||
| Extensions(2) | - | - | - | 47,078 | - | 8,259 | |||
| Improved Recovery | - | - | - | - | - | - | |||
| Technical Revisions(3) | - | - | - | 4,500 | - | 789 | |||
| Discoveries(4) | - | - | - | 10,973 | - | 1,925 | |||
| Acquisitions | - | - | - | - | - | - | |||
| Dispositions | - | - | - | - | - | - | |||
| Economic Factors | - | - | - | - | - | - | |||
| Production | - | - | - | (61,907 | ) | - | (10,861 | ) | |
| Closing Balance (December 31, 2020) | - | - | - | 394,792 | - | 69,262 | |||
| Total Oil | Light/Med Crude Oil | Heavy Crude Oil | Conventional Natural Gas | NGL | TOTAL | ||||
| (MBBL) | (MBBL) | (MBBL) | (MMCF) | (MBBL) | MBOE(5) | ||||
| TOTAL PROVED + PROBABLE | |||||||||
| Opening Balance (December 31, 2019) | - | - | - | 623,758 | - | 109,431 | |||
| Extensions(2) | - | - | - | 55,375 | - | 9,715 | |||
| Improved Recovery | - | - | - | - | - | - | |||
| Technical Revisions(3) | - | - | - | 2,116 | - | 371 | |||
| Discoveries(4) | - | - | - | 17,907 | - | 3,142 | |||
| Acquisitions | - | - | - | - | - | - | |||
| Dispositions | - | - | - | - | - | - | |||
| Economic Factors | - | - | - | - | - | - | |||
| Production | - | - | - | (61,907 | ) | - | (10,861 | ) | |
| Closing Balance (December 31, 2020) | - | - | - | 637,249 | - | 111,798 | |||
| Total Oil | Light/Med Crude Oil | Heavy Crude Oil | Conventional Natural Gas | NGL | TOTAL | ||||
| (MBBL) | (MBBL) | (MBBL) | (MMCF) | (MBBL) | MBOE(5) | ||||
| TOTAL PROVED + PROBABLE + POSSIBLE | |||||||||
| Opening Balance (December 31, 2019) | - | - | - | 884,838 | - | 155,235 | |||
| Extensions(2) | - | - | - | 75,194 | - | 13,192 | |||
| Improved Recovery | - | - | - | - | - | ||||
| Technical Revisions(3) | - | - | - | 2,172 | - | 381 | |||
| Discoveries(4) | - | - | - | 50,771 | - | 8,907 | |||
| Acquisitions | - | - | - | - | - | - | |||
| Dispositions | - | - | - | - | - | - | |||
| Economic Factors | - | - | - | - | - | - | |||
| Production | - | - | - | (61,907 | ) | - | (10,861 | ) | |
| Closing Balance (December 31, 2020) | - | - | - | 951,069 | - | 166,854 | |||
| (1) | The numbers in this table may not add due to rounding. |
| (2) | Conventional natural gas extensions are associated with the Clarinete gas field on the VIM-5 block. |
| (3) | Conventional natural gas technical revisions are associated with the Palmer and Nelson gas fields on the Esperanza block, Clarinete, Oboe and Pandereta gas fields on the VIM-5 block and Arandala gas field on the VIM-21 block. |
| (4) | Conventional natural gas discoveries are associated with Nelson-14 on the Esperanza block, Pandereta-8 and Porro Norte-1 on the VIM-5 block, and Arandala-1 and Fresa-1 on the VIM-21 block, all in the Lower Magdalena Valley basin, Colombia. |
| (5) | The term “BOE” means a barrel of oil equivalent on the basis of 5.7 Mcf of natural gas to 1 barrel of oil (“bbl”) as per Colombian regulatory practice. |
1P Natural Gas Reserves Metrics Reconciliation – Canacol Working Interest before Royalty (1) (2) (3)
| Calendar 2020 | Three-Year Ending December 31, 2020 | |||
| Conventional Natural Gas | Conventional Natural Gas | |||
| Net Natural Gas Capital Expenditures (M$ US) (2) | $ | 78,216 | $ | 239,352 |
| Capital Expenditures - Change in FDC (M$ US) (4) | 27,418 | 21,027 | ||
| Total F&D (M$ US) | $ | 105,634 | $ | 260,379 |
| Net Acquisitions (M$ US) | - | - | ||
| Total FD&A (M$ US) (6)(7) | $ | 105,634 | $ | 260,379 |
| Reserve Additions (MMCF) | 62,551 | 221,349 | ||
| Reserve Additions – Net Acquisitions | - | - | ||
| Reserve Additions Including Net Acquisitions (MMCF) | 62,551 | 221,349 | ||
| 1P F&D per Mcf (US$/MCF) (5) | $ | 1.69 | $ | 1.18 |
| 1P FD&A per Mcf (US$/MCF) (6)(7) | $ | 1.69 | $ | 1.18 |
| (1) | The numbers in this table may not add due to rounding. |
| (2) | The Company excludes midstream investments from the F&D calculations, as these capital investments represent long life midstream assets that have multi decade operating life potential, coupled with residual value. 2018 capital expenditures exclude US |
| (3) | All values in this table are stated on a 1P (Total Proved) basis. |
| (4) | “Capital Expenditures – change in FDC” is rounded. FDC is the 1P (Total Proved) future development capital. |
| (5) | 1P F&D – Finding and Development Costs on a 1P (Total Proved) basis. |
| (6) | 1P FD&A - Finding, Development and Acquisition Costs on a 1P (Total Proved) basis. |
| (7) | With the finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. |
2P Natural Gas Reserves Metrics Reconciliation – Canacol Working Interest before Royalty (1) (2) (3)
| Calendar 2020 | Three-Year Ending December 31, 2020 | |||
| Conventional Natural Gas | Conventional Natural Gas | |||
| Net Natural Gas Capital Expenditures (M$ US) (2) | $ | 78,216 | $ | 239,352 |
| Capital Expenditures - Change in FDC (M$ US) (4) | 21,724 | 1,177 | ||
| Total F&D (M$ US) | $ | 99,940 | $ | 240,529 |
| Net Acquisitions (M$ US) | - | - | ||
| Total FD&A (M$ US) (6)(7) | $ | 99,940 | $ | 240,529 |
| Reserve Additions (MMCF) | 75,398 | 287,303 | ||
| Reserve Additions – Net Acquisitions | - | - | ||
| Reserve Additions Including Net Acquisitions (MMCF) | 75,398 | 287,303 | ||
| 2P F&D per Mcf (US$/MCF) (5) | $ | 1.33 | $ | 0.84 |
| 2P FD&A per Mcf (US$/MCF) (6)(7) | $ | 1.33 | $ | 0.84 |
| (1) | The numbers in this table may not add due to rounding. |
| (2) | The Company excludes midstream investments from the F&D calculations, as these capital investments represent long life midstream assets that have multi decade operating life potential, coupled with residual value. 2018 capital expenditures exclude US |
| (3) | All values in this table are stated on a 2P (Total Proved + Probable) basis. |
| (4) | “Capital Expenditures – change in FDC” is rounded. FDC is the 2P (Total Proved + Probable) future development capital. |
| (5) | 2P F&D – Finding and Development Costs on a 2P (Total Proved + Probable) basis. |
| (6) | 2P FD&A - Finding, Development and Acquisition Costs on a 2P (Total Proved + Probable) basis. |
| (7) | With the finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. |
3P Natural Gas Reserves Metrics Reconciliation – Canacol Working Interest before Royalty (1) (2) (3)
| Calendar 2020 | Three-Year Ending December 31, 2020 | ||||
| Conventional Natural Gas | Conventional Natural Gas | ||||
| Net Natural Gas Capital Expenditures (M$ US) (2) | $ | 78,216 | $ | 239,352 | |
| Capital Expenditures - Change in FDC (M$ US) (4) | 25,096 | (8,141 | ) | ||
| Total F&D (M$ US) | $ | 103,312 | $ | 231,211 | |
| Net Acquisitions (M$ US) | - | - | |||
| Total FD&A (M$ US) (6)(7) | $ | 103,312 | $ | 231,211 | |
| Reserve Additions (MMCF) | 128,137 | 453,184 | |||
| Reserve Additions – Net Acquisitions | - | - | |||
| Reserve Additions Including Net Acquisitions (MMCF) | 128,137 | 453,184 | |||
| 3P F&D per Mcf (US$/MCF) (5) | $ | 0.81 | $ | 0.51 | |
| 3P FD&A per Mcf (US$/MCF) (6)(7) | $ | 0.81 | $ | 0.51 | |
| (1) | The numbers in this table may not add due to rounding. |
| (2) | The Company excludes midstream investments from the F&D calculations, as these capital investments represent long life midstream assets that have multi decade operating life potential, coupled with residual value. 2018 capital expenditures exclude US |
| (3) | All values in this table are stated on a 3P (Total Proved + Probable + Possible) basis. |
| (4) | “Capital Expenditures – change in FDC” is rounded. FDC is the 3P (Total Proved + Probable + Possible) future development capital. |
| (5) | 3P F&D – Finding and Development Costs on a 3P (Total Proved + Probable + Possible) basis. |
| (6) | 3P FD&A - Finding, Development and Acquisition Costs on a 3P (Total Proved + Probable + Possible) basis. |
| (7) | With the finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. |
The recovery and reserve estimates of conventional natural gas are estimates only. There is no guarantee that the estimated reserves will be recovered, and actual reserves of conventional natural gas may prove to be greater than, or less than, the estimates provided.
Reserves of conventional natural gas as at December 31, 2020 are evaluated using natural gas pricing based on existing long term contracts net of transportation (if applicable) and adjusted for inflation, along with interruptible gas sales pricing based on forecasts from La Unidad de Planeación Minero Energética (“UPME”), a special administrative unit of the Colombian Ministry of Mines and Energy. Comparative volumes of conventional natural gas as at December 31, 2019 were evaluated using natural gas pricing based on existing long term contracts net of transportation (if applicable) and adjusted for inflation, along with interruptible gas sales pricing based on UPME at that effective date. Forecast prices used in the reserves reports are included in the Corporation’s Annual Information Form, which will be filed on SEDAR by March 31, 2021 under the sections “Forecast Prices Used in Estimates” and “Forward Contracts” in the “Statement of Reserves Data and Other Oil and Gas Information”.
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
About Canacol
Canacol is a natural gas exploration and production company with operations focused in Colombia. The Corporation's common stock trades on the Toronto Stock Exchange, the OTCQX in the United States of America, and the Colombia Stock Exchange under ticker symbol CNE, CNNEF, and CNE.C, respectively.
Forward-Looking Information and Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities law. Forward-looking statement are frequently characterized by words such as "anticipate," "continue," "estimate," “expect”, "objective," "ongoing," "may," "will," "project," "should," "believe," "plan," "intend," "strategy," and other similar words, or statements that certain events or conditions "may" or "will" occur, including without limitation statements relating to estimated production rates from the Corporation's properties and intended work programs and associated timelines.
Forward-looking statements are based on the opinions and estimates of management at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. The Corporation cannot assure that actual results will be consistent with these forward looking statements. They are made as of the date hereof and are subject to change and the Corporation assumes no obligation to revise or update them to reflect new circumstances, except as required by law. Prospective investors should not place undue reliance on forward looking statements. These factors include the inherent risks involved in the exploration for and development of crude oil and natural gas properties, the uncertainties involved in interpreting drilling results and other geological and geophysical data, fluctuating energy prices, the possibility of cost overruns or unanticipated costs or delays and other uncertainties associated with the oil and gas industry. Other risk factors could include risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities, and other factors, many of which are beyond the control of the Corporation.
The reserves evaluation, effective December 31, 2020, was conducted by the Corporation’s independent reserves evaluator Boury Global Energy Consultants Ltd. (“BGEC”) and are in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. The reserves are provided on a Canacol Gross basis in units of Bcf and barrels of oil equivalent using a forecast price deck in US dollars. The estimated values may or may not represent the fair market value of the reserve estimates.
The resources evaluation, effective December 31, 2019, was conducted by the Corporation’s independent reserves evaluator Gaffney, Cline & Associates (“GCA”), and are in accordance with National Instrument 51‐101 ‐ Standards of Disclosure for Oil and Gas Activities. The Corporation press released the results of the resources evaluation on April 9, 2020.
"Gross" in relation to the Corporation's interest in production or reserves is its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Corporation;
"Net" in relation to the Corporation's interest in production or reserves is its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interest in production or reserves;
“Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
“Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves;
“Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves;
“Possible reserves” means those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves;
BOE Conversion - “BOE” barrel of oil equivalent is derived by converting natural gas to oil in the ratio of 5.7 Mcf of natural gas to one bbl of oil. A BOE conversion ratio of 5.7 Mcf to 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. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 5.7:1, utilizing a conversion on a 5.7:1 basis may be misleading as an indication of value. In this news release, the Corporation has expressed BOE using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and Energy of Colombia.
“PDP” means Proved Developed Producing
“1P” means Total Proved
“2P” means Total Proved + Probable
“3P” means Total Proved + Probable + Possible
PDP Reserves replacement ratio: Ratio of reserve additions to production, as reported in financial statements during the fiscal year ended December 31, excluding acquisitions and dispositions on a Proved Developed Producing basis.
1P Reserves replacement ratio: Ratio of reserve additions to production, as reported in financial statements during the fiscal year ended December 31, excluding acquisitions and dispositions on a Total Proved basis.
2P Reserves replacement ratio: Ratio of reserve additions to production, as reported in financial statements during the fiscal year ended December 31, excluding acquisitions and dispositions on a Total Proved + Probable basis.
Finding and development costs per thousand cubic feet (Mcf) represent exploration and development costs incurred per Mcf of Total Proved + Probable reserves added during the year. The Corporation, industry analysts, and investors use such metrics to measure a Corporation’s ability to establish a long-term trend of adding reserves at a reasonable cost.
Finding, development and acquisition costs per thousand cubic feet (Mcf) represent property acquisition, exploration, and development costs incurred per Mcf of Total Proved + Probable reserves added during the year. The Corporation, industry analysts, and investors use such metrics to measure a Corporation’s ability to establish a long-term trend of adding reserves at a reasonable cost.
With the finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Natural gas recycle ratio is calculated by dividing natural gas netback by finding and development costs.
“RLI” Reserve Life Index is calculated by dividing the applicable reserves category by the annualized fourth quarter production.
Unaudited Financial Information
Certain financial and operating results included in this news release include net debt, capital expenditures, production information and operating costs based on unaudited estimated results. These estimated results are subject to change upon completion of the Corporation's audited financial statements for the year ended December 31, 2020, and changes could be material. Canacol anticipates filing its audited financial statements and related management's discussion and analysis for the year ended December 31, 2020 on SEDAR on or before March 31, 2021.
This press release contains a number of oil and gas metrics, including F&D, FD&A, reserve replacement and RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Corporation's performance; however, such measures are not reliable indicators of the future performance of the Corporation and future performance may not compare to the performance in previous periods.
FAQ
What are Canacol Energy's total proved and probable reserves as of December 31, 2020?
What is the before tax NPV-10 of Canacol Energy's 2P reserves?
What is the reserve life index (RLI) for Canacol Energy as of December 31, 2020?
How much did Canacol Energy's reserves increase in 2020?
What was the finding and development cost for Canacol Energy in 2020?
