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Canacol Energy Ltd. Achieves 232% 2P Gas Reserve Replacement Ratio Increasing 2P Reserves to 559 BCF With a BTAX Value of US$1.5 Billion at a 2P F&D cost of $0.32/MCF

CALGARY, Alberta, Feb. 27, 2019 (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, 2018.  The Corporation’s conventional natural gas reserves are located in the Lower Magdalena Valley basin, Colombia. 

Canacol Energy Ltd Gross Reserves Summary

Gross Reserves
      Total Total Proved
    Total Proved + Probable
    Proved + Probable + Possible
Product Type   ("1P") ("2P") ("3P")
Conventional natural gas Bcf   380.2   558.9   739.4
Total oil equivalent(3) MMBOE   66.7   98.1   129.7
Before tax NPV-10(4) MM US$ $ 1,084.8 $ 1,523.5 $ 1,883.6
After tax NPV-10(4) MM US$ $ 784.7 $ 1,082.1 $ 1,324.5
               
  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)  are stated in millions of USD and are discounted at 10 percent

Highlights

Conventional Natural Gas Total Proved Reserves (“1P”):

  • Increased by 16% since December 31, 2017, totaling 380 Bcf at December 31, 2018
  • Reserve replacement of 226% based on calendar 2018 gross conventional natural gas reserve additions of 92 Bcf
  • 1P finding and development costs (“F&D”) of US$ 0.55/Mcf for calendar 2018
  • 1P F&D of US$ 0.84/Mcf for three year period ending December 31, 2018
  • Finding, development and acquisition costs  (“FD&A”) of US$ 0.86/Mcf for the three year period ending December 31, 2018
  • Recycle ratio of 6.9x for the year ended December 31, 2018 (calculated based on natural gas netback for the nine months ended September 30, 2018)
  • Recycle ratio of 4.8x for the three year period ending December 31, 2018 (calculated based on the weighted average natural gas netback for the years ended December 31, 2017 and 2016 and the nine months ended September 30, 2018)

Conventional Natural Gas Proved + Probable Reserves (“2P”):

  • Increased by 11% since December 31, 2017, totaling 559 Bcf at December 31, 2018, with a before tax value discounted at 10% of US$ 1.5 billion, representing both CAD$ 11.65 per share of reserve value, and CAD$ 9.37 per share of 2P net asset value (net of US$298 million of net debt)
  • Reserve replacement of 232% based on calendar 2018 gross conventional natural gas reserve additions of 95 Bcf
  • 2P F&D of US$ 0.32/Mcf for calendar 2018
  • 2P F&D of US$ 0.57/Mcf for three year period ending December 31, 2018
  • 2P FD&A of US$ 0.58/Mcf for the three year period ending December 31, 2018
  • Recycle ratio of 11.8x for the year ended December 31, 2018 (calculated based on natural gas netback for the nine months ended September 30, 2018)
  • Recycle ratio of 7.1x for the three year period ending December 31, 2018 (calculated based on the weighted average natural gas netback for the years ended December 31, 2017 and 2016 and the nine months ended September 30, 2018)
  • Reserves life index (“RLI”) of 13 years based on annualized fourth quarter 2018 conventional natural gas production of 116,618 Mcfpd or 20,459 BOEPD

Conventional Natural Gas Total Proved + Probable + Possible Reserves (“3P”):

  • Increased by 13% since December 31, 2017, totaling 739 Bcf at December 31, 2018, with a before tax value discounted at 10% of US$ 1.9 billion

Mr. Ravi Sharma, Chief Operating Officer of Canacol Energy, commented “The Corporation has achieved significant conventional natural gas exploration and development drilling success since the Shona Energy transaction in 2012 and the OGX acquisition in 2014. During this time, we have added over 481 BCF of 2P conventional natural gas reserves from commercial success in 20 out of 23 drilled wells, representing a 55% CAGR at an industry leading three year 2P F&D cost of US$ 0.57 / Mcf.  With a portfolio of 145 identified prospects and leads containing mean unrisked prospective gas resource of 2.6 TCF, 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, 2018 Reserves Report

During the year ended December 31, 2018, the Corporation recorded increases in certain reserve categories as a result of the drilling and completion of exploration locations at Cañahuate-3 on the Esperanza natural gas block, Breva-1 on the VIM-21 natural gas block, and Pandereta-3 and Chirimia-1 on the VIM-5 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, 2018 (the “BGEC 2018 report”).  The BGEC 2018 report covers 100% of the Corporation’s conventional natural gas reserves.

The BGEC 2018 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, 2019. 

Canacol Gross Reserves for the Year Ended December 31, 2018

Reserve Category(1) 31-Dec-17 31-Dec-18 Difference  
  (Bcf)(2) (Bcf) (%)  
Total Proved (1P) 328,630 380,155 16 %
Total Proved + Probable (2P) 505,133 558,886 11 %
Total Proved + Probable + Possible (3P) 653,071 739,384 13 %
         
  1. All reserves are Canacol working interest before royalties
  2. For year over year comparison purposes, conventional natural gas reserves at December 31, 2017 are stated since the Corporation disposed of its oil assets in fiscal year 2018

5-Year Gas Price Forecast – BGEC Report December 31, 2018

    Reserve          
    Report Date 2019 2020 2021 2022 2023
               
Volume weighted average gas price US$/MMbtu 31-Dec-18 4.84 5.15 5.13 5.24 5.34
               
  1. Gas price forecast is based on existing long term contracts net of transportation (if applicable) and adjusted for inflation

Reserves Net Present Value Before & After Tax Summary (1)

  Before tax   After tax
      Net Asset       Net Asset
      Value       Value
Reserve Category 31-Dec-18   31-Dec-18   31-Dec-18   31-Dec-18
  (M US$)(2)   (C$/share)(2)   (M US$)(2)   (C$/share)(2)
Total Proved (1P) $ 1,084,811   $ 6.02   $ 784,693   $ 3.72
Total Proved + Probable (2P) $ 1,523,538   $ 9.37   $ 1,082,704   $ 6.00
Total Proved + Probable + Possible (3P) $ 1,883,623   $ 12.13   $ 1,324,510   $ 7.85
                       
  1. Net present values are stated in thousands of USD and are 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, 2018 are included in the Corporation’s Annual Information Form.
  2. Net asset value (“NAV”) is calculated at December 31, 2018 NPV10 less estimated net debt of US$298.4million (being $350 million of bank debt less estimated cash of $51.6 million) divided by 177.8 million basic shares outstanding as at December 31, 2018.  NAV calculations are converted to $CAD at December 31, 2018 effective rate of USD:CAD =1.36.

Reserve Life Index (“RLI”)

Reserve Category 31-Dec-17 31-Dec-18
  (yrs.)(1) (yrs.)(2)
Total Proved (1P) 10 9
Total Proved + Probable (2P) 16 13
     
  1. Calculated using average 3 month ending December 31, 2017 production of 17,577 BOEpd annualized.  Production volumes include Ecuador incremental production contract barrels.
  2. Calculated using average 3 month ending December 31, 2018 natural gas production of 116,618 Mcfpd or 20,459 BOEpd annualized. 
  3. “RLI” Reserve Life Index is calculated by dividing a category of year end reserves by expected current production rate.

Year Ended December 31, 2018 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  
TOTAL PROVED            
Opening Balance (December 31, 2017) 7,525   5,273   2,252   328,630   - 65,179  
Extensions -   -   -   -   - -  
Improved Recovery -   -   -   -   - -  
Technical Revisions(2) -   -   -   53,629   - 9,409  
Discoveries(3) -   -   -   38,769   - 6,802  
Acquisitions -   -   -   -   - -  
Dispositions(4) (7,049 ) (4,926 ) (2,123 ) -   - (7,049 )
Economic Factors -   -   -   -   - -  
Production(5) (476 ) (347 ) (129 ) (40,873 ) - (7,647 )
Closing Balance (December 31, 2018) -   -   -   380,155   - 66,694  
             
             
  Total Oil   Light/Med
Crude Oil
  Heavy Crude Oil   Conventional Natural Gas   NGL TOTAL  
  (MBBL)   (MBBL)   (MBBL)   (MMCF)   (MBBL) MBOE  
TOTAL PROVED + PROBABLE            
Opening Balance (December 31, 2017) 13,900   7,568   6,332   505,133   - 102,520  
Extensions -   -   -   -   - -  
Improved Recovery -   -   -   -   - -  
Technical Revisions(2) -   -   -   31,079   - 5,452  
Discoveries(3) -   -   -   63,547   - 11,149  
Acquisitions -   -   -   -   - -  
Dispositions(4) (13,424 ) (7,221 ) (6,203 ) -   - (13,424 )
Economic Factors -   -   -   -   - -  
Production(5) (476 ) (347 ) (129 ) (40,873 ) - (7,647 )
Closing Balance (December 31, 2018) -   -   -   558,886   - 98,050  
                       
  1. The numbers in this table may not add due to rounding
  2. Conventional natural gas technical revisions are associated with the Nelson and Clarinete gas fields
  3. Conventional natural gas discoveries are associated with Cañahuate-3 on the Esperanza block, Breva-1 on the VIM-21 block and Pandereta-3 and Chirimia-1 on the VIM-5 block, all in the Lower Magdalena Valley basin, Colombia. 
  4. Dispositions include the Corporation’s oil assets in Ecuador (as announced March 7, 2018) and Colombia (as announced September 28, 2018)
  5. Production volumes include Colombian oil and Ecuador incremental production contract barrels to the effective dates of the dispositions

1P Reserve Metrics Reconciliation – Canacol Working Interest before Royalty (1) (2) (3)

  Calendar 2018
  Three-Year Ending
December 31, 2018
 
  Conventional Natural Gas
  Conventional Natural Gas
 
Capital Expenditures (M$ US) (2) $ 81,839   $ 204,099  
Capital Expenditures - Change in FDC (M$ US)  (4)   (31,373 )   (22,560 )
Total F&D (M$ US) $ 50,466   $ 181,539  
Net Acquisitions (M$ US)   -     3,665  
Total FD&A (M$ US) (6)(7) $ 50,466   $ 185,204  
Reserve Additions (MMCF)   92,398     216,384  
Reserve Additions – Net Acquisitions   -     -  
Reserve Additions Including Net Acquisitions (MMCF)   92,398     216,384  
1P F&D per Mcf (US$/MCF) (5) $ 0.55   $ 0.84  
1P FD&A per Mcf (US$/MCF)  (6)(7) $ 0.55   $ 0.86  
             
  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.  In 2016, such capital expenditures include US$ 33 million related to the Jobo 2 gas plant finance lease. 2017 capital expenditures exclude US$ 10.2 million related to the Corporation’s investment in the Sabanas flowline, US$ 8.9 million related to a compression finance lease on the Sabanas flowline and US$ 18.3 million related to other midstream initiatives.  2018 capital expenditures exclude US$ 8.9 million related to the second compression finance lease on the Sabanas flowline, US$ 18.4 million related to the third Jobo Station expansion and US$ 4.9 million related to other midstream initiatives.
  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 Reserve Metrics Reconciliation – Canacol Working Interest before Royalty (1) (2) (3)

  Calendar 2018
  Three-Year Ending
December 31, 2018
 
  Conventional Natural Gas
  Conventional Natural Gas
 
Capital Expenditures (M$ US) (2) $ 81,839   $ 204,099  
Capital Expenditures - Change in FDC (M$ US) (4)   (51,730 )   (44,118 )
Total F&D (M$ US) $ 30,109   $ 159,981  
Net Acquisitions (M$ US)   -     3,665  
Total FD&A (M$ US) (6)(7) $ 30,109   $ 163,646  
Reserve Additions (MMCF)   94,626     280,747  
Reserve Additions – Net Acquisitions   -     -  
Reserve Additions Including Net Acquisitions (MMCF)   94,626     280,747  
2P F&D per Mcf (US$/MCF) (5) $ 0.32   $ 0.57  
2P FD&A per Mcf (US$/MCF)  (6)(7) $ 0.32   $ 0.58  
             
  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.  In 2016, such capital expenditures include US$ 33 million related to the Jobo 2 gas plant finance lease. 2017 capital expenditures exclude US$ 10.2 million related to the Corporation’s investment in the Sabanas flowline, US$ 8.9 million related to a compression finance lease on the Sabanas flowline and US$ 18.3 million related to other midstream initiatives.  2018 capital expenditures exclude US$ 8.9 million related to the second compression finance lease on the Sabanas flowline, US$ 18.4 million related to the third Jobo Station expansion and US$ 4.9 million related to other midstream initiatives.
  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 (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.

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, 2018 are evaluated against contract pricing forecast for each gas contract.  Comparative volumes of conventional natural gas as at December 31, 2017 are evaluated against contract pricing for each gas contract at the 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, 2019 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.

Canacol is an 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, 2018, 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.

"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 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.

“1P” means Total Proved
“2P” means Total Proved + Probable
“3P” means Total Proved + Probable + Possible

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 million 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 million 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 a category of year end reserves by expected current production rate annualized fourth quarter of 2018 production rate.

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, 2018, 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, 2018 on SEDAR on or before March 31, 2019.

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 further information please contact:
Investor Relations
214-235-4798
Email: IR@canacolenergy.com
Website: canacolenergy.com