CALGARY, ALBERTA–(Marketwired – March 27, 2017) – Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to report its light, medium and heavy crude oil and conventional natural gas reserves and deemed volumes for the fiscal year end December 31, 2016. The Corporation engaged DeGolyer and MacNaughton Canada Limited (“DMCL”) to prepare independent reserves evaluations for its two primary conventional natural gas fields in Colombia and for its oil reserves in Colombia and deemed volumes in Ecuador. The DMCL evaluated reserves and deemed volumes represent 92% of the Corporation’s total reserves and deemed volumes on a Total Proved “1P” basis.

The Corporation’s conventional natural gas reserves are located in the Lower Magdalena Valley basin, Colombia. Canacol’s light and medium crude oil reserves are located in the Llanos and Middle Magdalena Valley basins, Colombia. Additional deemed volumes of light and medium crude oil are developed in the Oriente basin, Ecuador. Heavy crude oil reserves are located in the Caguan basin, Colombia.

1. The numbers in this table may not add exactly due to rounding
2. All reserves and deemed volumes are represented at Canacol’s working interest share before royalties
3. Light and medium crude volumes include working interest volumes and deemed volumes
4. 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
5. Net Present Value (NPV) are stated in thousands of USD and are discounted at 10 percent

Highlights include:

• Proved Developed Producing “PDP” reserves and deemed volumes increased by 49% since December 31, 2015, to total 42.4 million barrels of oil equivalent (“MMBOE”) at December 31, 2016
• Total Proved + Probable “2P” reserves and deemed volumes totaled 84.6 MMBOE at December 31, 2016, with a before tax value discounted at 10% of US$ 1.3 billion, representing CAD $ 8.79 per share
• Achieved 1P reserve replacement of 166% and 2P reserve replacement of 194% based on calendar 2016 gross reserve and deemed volume additions of 9.3 MMBOE (1P) and 11 MMBOE (2P)
• Achieved 2P finding and development costs (“F&D”) of US$ 4.71/BOE for its gas assets and US$ 5.31/BOE as a corporate total for calendar 2016
• Achieved 2P F&D of US$ 2.52/BOE for its gas assets and US$ 3.48/BOE as a corporate total for the 2 year period ending December 31, 2016
• Recorded 2P finding, development and acquisition costs (“FD&A”) of US$ 5.04/BOE for its gas assets and US$ 5.66/BOE as a corporate total for calendar 2016
• Recorded a 2P reserves life index (“RLI”) of 13 years based on annualized fourth quarter 2016 production of 17,778 BOEpd

Ravi Sharma, Chief Operating Officer of Canacol Energy, commented: “The Corporation has achieved significant conventional natural gas exploration and development drilling success over the past 3.5 years. During this time, we have added over 315 BCF of 2P conventional natural gas reserves from commercial success on 11 out of 12 wells, representing a 52% compound annual growth rate (“CAGR”). As of December 31, 2016, Canacol’s total 1P reserves and corresponding before tax NPV-10 are 57 MMBOE and US$ 900 million, respectively, or CAD $5.47 per share. The Corporation’s 2P reserves and corresponding before tax NPV-10 are 85 MMBOE and US$ 1.3 billion, respectively, or CAD $8.79 per share.

Canacol’s management team continues to execute its growth strategy with respect to high value Colombian gas. The Corporation forecasts 130 million cubic feet of gas per day (“MMcfd”) of natural gas production for exit rate 2017 and 230 MMcf/d of natural gas production for exit rate 2018. These targets represent production growth of 44% from current production of 90 MMcf/d and sequential production growth of 77% from 130 to 230 MMcf/d to exit 2018. “

Discussion of Year Ended December 31, 2016 Reserves Report

During the six month period from June 30th 2016 to December 31st 2016, the Corporation recorded increases in certain reserve categories as a result of the drilling and completion of exploration locations at Nelson-6, Nispero-1 and Trombon-1 on the Esperanza natural gas block in the Lower Magdalena valley Basin, Colombia.

The following tables summarize information from the independent reserves report prepared by DeGolyer and MacNaughton Canada Limited, effective December 31, 2016 (the “DMCL 2016 report”) and the independent reserves report prepared by Petrotech Engineering Ltd., effective December 31, 2016 (the “Petrotech 2016 report”). The DMCL 2016 report covers 100% of the Corporation’s oil reserves and deemed volumes and 90% of Canacol’s natural gas reserves on a 1P basis, including Nelson and Clarinete fields.

Each independent reserves 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, 2017.

1. All reserves and deemed volumes are Canacol working interest before royalties
2. MBOE is defined as thousands of barrels of oil equivalent. Gas volumes are converted to BOE using a factor of 5.7mcf/BOE as per Colombia regulatory practice

1. Gas price forecast is based on existing long term contracts adjusted for inflation

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 decks described above. The DMCL price deck at December 31, 2016 is included in the Corporation’s Annual Information Form. The DMCL and Petrotech forecasts for gas prices at December 31, 2016 are included in the Corporation’s Annual Information Form.
2. Net asset value (“NAV”) is calculated at December 31, 2016 NPV10 less estimated net debt of US$190 million (being $255 million of bank debt less estimated net working capital of $65 million) divided by 174 million basic shares outstanding as at December 31, 2016. NAV calculations are converted to $CAD at USD:CAD = 1.3427.

1. Calculated using average 3 month ending December 31, 2015 production of 9,064 BOEpd annualized. Production volumes include Ecuador incremental production contract barrels.
2. Calculated using average 3 month ending December 31, 2016 production of 17,778 BOEpd annualized. Production volumes include Ecuador incremental production contract barrels.
3. “RLI” Reserve Life Index is calculated by dividing a category of year end reserves by expected current production rate.

1. The numbers in this table may not add due to rounding
2. Technical revisions (conventional natural gas) are associated with the Nelson and Clarinete gas fields, technical revisions (light/medium oil) are associated with LLA23 and Ecuador assets, technical revisions (heavy oil) are associated with the Ombu block
3. Discoveries are associated with the Oboe discovery on VIM-5 block and Nispero, Trombon and Porquero discoveries on Esperanza block
4. Economic factors are related to price and royalty factor changes
5. Production volumes include Ecuador incremental production contract barrels

1. The numbers in this table may not add due to rounding
2. 2016 capital expenditure numbers exclude US $33 million related to the Jobo 2 gas plant finance lease
3. All values in this table are stated on a 2P (Total Proved + Probable) basis
4. Total oil and gas includes Colombian properties only. No Ecuador deemed volumes nor capital have been included
5. “Capital Expenditures – change in FDC” is rounded to the nearest M US$. FDC is the 2P (Proved + Probable) future development capital
6. F&D – Finding and Development Costs on a 2P (Total Proved + Probable) basis
7. FD&A – Finding, Development and Acquisition Costs on a 2P (Total Proved + Probable) basis
8. 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 light and medium crude oil, heavy crude oil and conventional natural gas are estimates only. There is no guarantee that the estimated reserves will be recovered and actual reserves of light and medium crude oil, heavy crude oil and conventional natural gas may prove to be greater than, or less than, the estimates provided.

Reserves of light and medium crude oil and heavy crude oil as at December 31, 2016 are evaluated against the DMCL forecast pricing effective at that date. Comparative volumes of light and medium crude oil and heavy crude oil as at December 31, 2015 are evaluated against the DMCL forecast pricing effective at that date. Deemed volumes of light crude oil are determined by dividing cash flow by the tariff price of USD$38.54/barrel which remains constant for the life of the incremental production contract. Reserves of conventional natural gas as at December 31, 2016 are evaluated against contract pricing forecast for each gas contract. Comparative volumes of conventional natural gas as at December 31, 2015 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, 2017 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, Ecuador and Mexico. 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 evaluations, effective December 31, 2016, were conducted by the Corporation’s independent reserves evaluators DeGolyer and MacNaughton Canada Limited (“DMCL”) and Petrotech Engineering Ltd. (“Petrotech”) 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 barrels of oil equivalent using a forecast price deck, adjusted for quality, 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;

“Deemed Volumes” refer to Volume 3 of COGEH, Reserves Recognition for International Properties, Section 4 – Fiscal Regime, Service Contracts, and refer to those volumes produced under a risked Service Agreement in which the Corporation does not have a direct interest, but represents reserves attributable to the Corporation. By definition, these volumes are calculated as the production revenue divided by the fixed tariff price or operating netback per barrel, and are considered additive to volumes certified as reserves. Under the terms of this risked Service Agreement, these calculated volumes correspond to actual volumes produced. The Corporation has a non-operated 25% equity participation interest in the Ecuador IPC for which it receives a fixed price tariff for each incremental barrel produced.

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.

2P Finding and development costs per barrel of oil equivalent (BOE) represent exploration and development costs incurred per BOE 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.

2P Finding, development and acquisition costs per barrel of oil equivalent (BOE) represent property acquisition, exploration, and development costs incurred per BOE 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.

“RLI” Reserve Life Index is calculated by dividing a category of year end reserves by expected current production rate.

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.

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, 2016, 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, 2016 on SEDAR on or before March 31, 2017.

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