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

Source Press Release
Company Canacol Energy Ltd. 
Tags Strategy - Upstream, Capital Spending, Guidance, Strategy - Corporate, Financial & Operating Data
Date February 27, 2019

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 
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.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd