Canacol Energy Ltd. Achieves 224% 2P Gas Reserve Replacement Ratio Increasing 2P Reserves to 624 BCF With a BTAX Value of US$2.1 Billion

/EIN News/ -- CALGARY, Alberta, Feb. 19, 2020 (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, 2019.  The Corporation’s conventional natural gas reserves are located in the Lower Magdalena Valley basin, Colombia.

Canacol Energy Ltd Gross 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		251.9		394.1		623.8		884.8
Total oil equivalent(3)	MMBOE		44.2		69.1		109.4		155.2
Before tax NPV-10(4)	MM US$	$	877.2	$	1,345.0	$	2,145.0	$	2,879.3
After tax NPV-10(4)	MM US$	$	703.3	$	1,033.4	$	1,583.2	$	2,087.2

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 12% since December 31, 2018, totaling 624 Bcf at December 31, 2019, with a before tax value discounted at 10% of US$ 2.1 billion, representing both CAD$ 15.47 per share of reserve value, and CAD$ 13.41 per share of 2P net asset value (net of US$285.6 million of net debt)
• Reserve replacement of 224% based on calendar 2019 gross conventional natural gas reserve additions of 117 Bcf
• 2P F&D of US$ 0.67/Mcf for the three year period ending December 31, 2019
• Recycle ratio of 4.4x for the year ended December 31, 2019
• Recycle ratio of 5.7x for the three year period ending December 31, 2019 (calculated based on the weighted average natural gas netback for the years ended December 31, 2019, 2018 and 2017)
• Reserves life index (“RLI”) of 9 years based on annualized fourth quarter 2019 conventional natural gas production of 180,986 Mcfpd or 31,752 BOEPD
• RLI of 8.3 years based on conventional natural gas production guidance of 205,000 Mcfpd for calendar 2020

Conventional Natural Gas Proved Developed Producing Reserves (“PDP”):

• Increased by 31% since December 31, 2018, totaling 252 Bcf at December 31, 2019
• Reserve replacement of 213% based on calendar 2019 gross conventional natural gas reserve additions of 112 Bcf

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

• Increased by 4% since December 31, 2018, totaling 394 Bcf at December 31, 2019
• Reserve replacement of 127% based on calendar 2019 gross conventional natural gas reserve additions of 66 Bcf
• 1P F&D of US$ 0.98/Mcf for the three year period ending December 31, 2019
• Recycle ratio of 2.7x for the year ended December 31, 2019
• Recycle ratio of 3.9x for the three year period ending December 31, 2019 (calculated based on the weighted average natural gas netback for the years ended December 31, 2019, 2018 and 2017)

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

• Increased by 20% since December 31, 2018, totaling 885 Bcf at December 31, 2019, with a before tax value discounted at 10% of US$ 2.9 billion

Mr. Ravi Sharma, Chief Operating Officer of Canacol, commented, “The Corporation has historically achieved significant conventional natural gas exploration and development drilling success from our assets located in the Lower Magdalena Valley, and this success continued into 2019.  Since 2013, we have added 696 BCF of 2P conventional natural gas reserves from commercial success in 27 out of 31 drilled wells, representing a 37% CAGR at an industry leading three year 2P F&D cost of US$ 0.67 / Mcf.  With a portfolio of 140 identified prospects and leads containing mean unrisked prospective gas resource of 2.6 TCF according to our 2018 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, 2019 Reserves Report

During the year ended December 31, 2019, the Corporation recorded increases in certain reserve categories as a result of the drilling and completion of locations at Nelson-13 and Palmer-2 on the Esperanza natural gas block, and Acordeon-1, Ocarina-1 and Clarinete-4 on the VIM-5 natural gas block, and Arandala-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, 2019 (the “BGEC 2019 report”).  The BGEC 2019 report covers 100% of the Corporation’s conventional natural gas reserves.

The BGEC 2019 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, 2020. 

Canacol Gross Reserves for the Year Ended December 31, 2019

Reserve Category(1)	31-Dec-18		31-Dec-19		Difference
	(Bcf)		(Bcf)		(%)
Proved Developed Producing (PDP)	192,563		251,865		+31	%
Total Proved (1P)	380,155		394,148		+4	%
Total Proved + Probable (2P)	558,886		623,758		+12	%
Total Proved + Probable + Possible (3P)	739,384		884,838		+20	%

(1) All reserves are Canacol working interest before royalties

5-Year Gas Price Forecast – BGEC Report December 31, 2019

		Reserve
		Report Date	2020	2021	2022	2023	2024
Volume weighted average gas price	US$/MMbtu	31-Dec-19	5.38	5.56	5.84	6.16	7.59

(1) 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.

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

	Before tax						After tax
				Net Asset						Net Asset
				Value						Value
Reserve Category	31-Dec-19			31-Dec-19			31-Dec-19			31-Dec-19
	(M US$)(2)			(C$/share)(2)			(M US$)(2)			(C$/share)(2)
Proved Developed Producing (PDP)	$	877,181		$	4.27		$	703,268		$	3.01
Total Proved (1P)	$	1,345,033		$	7.64		$	1,033,446		$	5.39
Total Proved + Probable (2P)	$	2,144,958		$	13.41		$	1,583,167		$	9.36
Total Proved + Probable + Possible (3P)	$	2,879,324		$	18.71		$	2,087,158		$	12.99

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, 2019 are included in the Corporation’s Annual Information Form.
2. Net asset value (“NAV”) is calculated at December 31, 2019 NPV10 less estimated net debt of US$285.6 million (being $350 million of bank debt less estimated cash of $64.4 million) divided by 180.1 million basic shares outstanding as at December 31, 2019.  NAV calculations are converted to $CAD at December 31, 2019 effective rate of USD:CAD =1.30.

Reserve Life Index (“RLI”)

Reserve Category	31-Dec-18		31-Dec-19
	(yrs.)(1)		(yrs.)(2)
Proved Developed Producing (PDP)	5		4
Total Proved (1P)	9		6
Total Proved + Probable (2P)	13		9

1. Calculated using average 3 month ending December 31, 2018 natural gas production of 116,618 Mcfpd or 20,459 BOEpd annualized. 
2. Calculated using average 3 month ending December 31, 2019 natural gas production of 180,986 Mcfpd or 31,752 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, 2019 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(4)
PROVED DEVELOPED PRODUCING
Opening Balance (December 31, 2018)			-	-	-	192,563		-	33,783
	Extensions		-	-	-	-		-	-
	Improved Recovery		-	-	-	-		-	-
	Technical Revisions(2)		-	-	-	84,840		-	14,884
	Discoveries(3)		-	-	-	26,869		-	4,714
	Acquisitions		-	-	-	-		-	-
	Dispositions		-	-	-	-		-	-
	Economic Factors		-	-	-	-		-	-
	Production		-	-	-	(52,407	)	-	(9,194	)
Closing Balance (December 31, 2019)			-	-	-	251,865		-	44,187
			Total Oil	Light/Med Crude Oil	Heavy Crude Oil	Conventional Natural Gas		NGL	TOTAL
			(MBBL)	(MBBL)	(MBBL)	(MMCF)		(MBBL)	MBOE(4)
TOTAL PROVED
Opening Balance (December 31, 2018)			-	-	-	380,155		-	66,694
	Extensions		-	-	-	-		-	-
	Improved Recovery		-	-	-	-		-	-
	Technical Revisions(2)		-	-	-	31,892		-	5,595
	Discoveries(3)		-	-	-	34,508		-	6,054
	Acquisitions		-	-	-	-		-	-
	Dispositions		-	-	-	-		-	-
	Economic Factors		-	-	-	-		-	-
	Production		-	-	-	(52,407	)	-	(9,194	)
Closing Balance (December 31, 2019)			-	-	-	394,148		-	69,149
			Total Oil	Light/Med  Crude Oil	Heavy Crude Oil	Conventional Natural Gas		NGL	TOTAL
			(MBBL)	(MBBL)	(MBBL)	(MMCF)		(MBBL)	MBOE(4)
TOTAL PROVED + PROBABLE
Opening Balance (December 31, 2018)			-	-	-	558,886		-	98,050
	Extensions		-	-	-	-		-	-
	Improved Recovery		-	-	-	-		-	-
	Technical Revisions(2)		-	-	-	47,965		-	8,415
	Discoveries(3)		-	-	-	69,314		-	12,160
	Acquisitions		-	-	-	-		-	-
	Dispositions		-	-	-	-		-	-
	Economic Factors		-	-	-	-		-	-
	Production		-	-	-	(52,407	)	-	(9,194	)
Closing Balance (December 31, 2019)			-	-	-	623,758		-	109,431

1. The numbers in this table may not add due to rounding
2. Conventional natural gas technical revisions are associated with the Palmer, Nelson, Cañahuate and Clarinete gas fields
3. Conventional natural gas discoveries are associated with Nelson-13 and Palmer-2 on the Esperanza block, Acordeon-1, Ocarina-1 and Clarinete-4 on the VIM-5 block, and Arandala-1 on the VIM-21 block, all in the Lower Magdalena Valley basin, Colombia. 
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

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

	Calendar 2019				Three-Year Ending December 31, 2019
	Conventional Natural Gas				Conventional Natural Gas
Net Capital Expenditures (M$ US) (2)(8)	$	70,359		$	225,814
Capital Expenditures - Change in FDC (M$ US)  (4)		24,982			1,849
Total F&D (M$ US)	$	95,341		$	227,663
Net Acquisitions (M$ US)		-			-
Total FD&A (M$ US) (6)(7)	$	95,341		$	227,663
Reserve Additions (MMCF)		66,400			233,471
Reserve Additions – Net Acquisitions		-			-
Reserve Additions Including Net Acquisitions (MMCF)		66,400			233,471
1P F&D per Mcf (US$/MCF) (5)	$	1.44		$	0.98
1P FD&A per Mcf (US$/MCF)  (6)(7)	$	1.44		$	0.98

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.  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.  2019 capital expenditures exclude US$ 14.5 million related to the third Jobo Station expansion, which was completed in 2019.
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.
8. 2019 capital expenditures include US$11.9 million of seismic acquisition costs, which encompasses prospects that will be drilled in 2020 forward.  This seismic cost increased Canacol’s 1P F&D by US$ 0.18 / MCF and US$ 0.05 / MCF for calendar 2019 and the three year period ending December 31, 2019, respectively.  2019 capital expenditures were reduced by US$ 14.9 million of proceeds from the divestiture of Canacol’s working interest in the Sabanas flowline, which decreased Canacol’s 1P F&D by US$ 0.22 / MCF and US$ nil / MCF for calendar 2019 and the three year period ending December 31, 2019, respectively.

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

	Calendar 2019				Three-Year Ending December 31, 2019
	Conventional Natural Gas				Conventional Natural Gas
Net Capital Expenditures (M$ US) (2)(8)	$	70,359		$	225,814
Capital Expenditures - Change in FDC (M$ US) (4)		31,183			(1,831	)
Total F&D (M$ US)	$	101,542		$	223,983
Net Acquisitions (M$ US)		-			-
Total FD&A (M$ US) (6)(7)	$	101,542		$	223,983
Reserve Additions (MMCF)		117,279			334,334
Reserve Additions – Net Acquisitions		-			-
Reserve Additions Including Net Acquisitions (MMCF)		117,279			334,334
2P F&D per Mcf (US$/MCF) (5)	$	0.87		$	0.67
2P FD&A per Mcf (US$/MCF) (6)(7)	$	0.87		$	0.67

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.  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.  2019 capital expenditures exclude US$ 14.5 million related to the third Jobo Station expansion, which was completed in 2019.
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.
8. 2019 capital expenditures include US$11.9 million of seismic acquisition costs, which encompasses prospects that will be drilled in 2020 forward.  This seismic cost increased Canacol’s 2P F&D by US$ 0.10 / MCF and US$ 0.04 / MCF for calendar 2019 and the three year period ending December 31, 2019, respectively.  2019 capital expenditures were reduced by US$ 14.9 million of proceeds from the divestiture of Canacol’s working interest in the Sabanas flowline, which decreased Canacol’s 2P F&D by US$ 0.13 / MCF and US$ nil / MCF for calendar 2019 and the three year period ending December 31, 2019, respectively.

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, 2019 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, 2018 evaluated using natural gas pricing based on existing long term contracts net of transportation (if applicable) and adjusted for inflation. 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, 2020 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, 2019, 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, 2017, 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 July 25, 2018.

"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, 2019, 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, 2019 on SEDAR on or before March 31, 2020.

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
                    Ph: +57 (1) 621 1747
                    Ph: +(1) 403 561 1648
                    Email: IR@canacolenergy.com
                    Website: canacolenergy.com