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

Wednesday, 03. March 2021 13:00

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 DevelopedTotalTotal ProvedTotal Proved + Probable
   ProducingProved+ Probable+ Possible
Product Type (“PDP”)("1P")("2P")("3P")
Conventional natural gasBcf 276.9 394.8 637.2 951.1
Total oil equivalent(3)MMBOE48.669.3111.8166.9
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 at 10% 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 at 10% 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 31% Compound Annual Growth Rate (“CAGR”) at an industry leading three-year 2P F&D cost of US$ 0.84 / Mcf. With a portfolio of 162 identified prospects and leads containing mean unrisked prospective gas resource of 4.7 TCF according to our 2019 third party resource report, we anticipate many more years of successful exploration drilling resulting in the movement of gas resources into proven and probable reserves.”

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 100% of the Corporation’s conventional natural gas reserves.

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-1931-Dec-20Difference
 (Bcf)(Bcf)(%)
Proved Developed Producing (PDP)251,865276,869+9.9%
Total Proved (1P)394,148394,792+0.2%
Total Proved + Probable (2P)623,758637,249 +2.2%
Total Proved + Probable + Possible (3P)884,838951,069+7.5%

 

(1)All reserves are Canacol working interest before royalties.

5-Year Gas Price Forecast – BGEC Report December 31, 2020

  Reserve     
  Report Date20212022202320242025
        
Volume weighted Total Proved + Probable (2P) average gas priceUS$/Mcf31-Dec-204.394.935.125.295.59

  

(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-2031-Dec-20 31-Dec-2031-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$341.8 million (being $415.2 million of total debt less estimated working capital of $73.4 million) divided by 179.5 million basic shares outstanding as at December 31, 2020. NAV calculations are converted to $CAD at December 31, 2020 effective rate of USD:CAD =1.273.

Reserve Life Index (“RLI”)(3)

Reserve Category31-Dec-1931-Dec-20
 (yrs)(1)(yrs)(2)
Proved Developed Producing (PDP)3.84.5
Total Proved (1P)6.06.4
Total Proved + Probable (2P)9.410.3
Total Proved + Probable + Possible (3P)13.415.3


(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 OilLight/Med Crude OilHeavy Crude OilConventional Natural Gas NGLTOTAL 
  (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 OilLight/Med Crude OilHeavy Crude OilConventional Natural Gas NGLTOTAL 
  (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 OilLight/Med Crude OilHeavy Crude OilConventional Natural Gas NGLTOTAL 
  (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 OilLight/Med Crude OilHeavy Crude OilConventional Natural Gas NGLTOTAL 
 (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 2020Three-Year Ending December 31, 2020
 Conventional Natural GasConventional 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$ 8.9 million related to the second compression finance lease on the Sabanas flowline and US$ 18.4 million related to the third Jobo Station expansion. 2019 capital expenditures exclude US$ 14.5 million related to the third Jobo Station expansion, which was completed in 2019. There were no exclusions on 2020 capital expenditures.
(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 2020Three-Year Ending December 31, 2020
 Conventional Natural GasConventional 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$ 8.9 million related to the second compression finance lease on the Sabanas flowline and US$ 18.4 million related to the third Jobo Station expansion. 2019 capital expenditures exclude US$ 14.5 million related to the third Jobo Station expansion, which was completed in 2019. There were no exclusions on 2020 capital expenditures.
(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 2020Three-Year Ending December 31, 2020 
 Conventional Natural GasConventional 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$ 8.9 million related to the second compression finance lease on the Sabanas flowline and US$ 18.4 million related to the third Jobo Station expansion. 2019 capital expenditures exclude US$ 14.5 million related to the third Jobo Station expansion, which was completed in 2019. There were no exclusions on 2020 capital expenditures.
(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 51101 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. 


For more information please contact: 
Investor Relations
South America: +571.621.1747 IR-SA@canacolenergy.com
Global: +1.403.561.1648 IR-GLOBAL@canacolenergy.com
http://www.canacolenergy.com 

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