Canacol Energy Ltd. Reports a 6% Increase in EBITDAX and an 11% Increase in Adjusted Funds from Operations per Share in Q4 2020

Rhea-AI Summary

Canacol Energy Ltd. reported its 2020 financial and operational results, demonstrating resilience amid the COVID-19 pandemic. The 2020 EBITDAX rose 12% to $187.5 million, while the fourth quarter saw a 9% increase from Q3. Despite reduced drilling activities, Canacol replaced produced reserves and increased proved developed producing (PDP) reserves by 10%. Total natural gas revenues for the year rose 13% to $240.3 million. However, the company reported a net loss of $4.7 million, attributed mainly to a non-cash tax expense. Looking forward, Canacol plans to drill twelve wells in 2021 and expand its seismic activities.

Positive

• 2020 EBITDAX increased 12% to $187.5 million.
• PDP reserves rose 10% to 277 Bcf with a 140% replacement ratio.
• Total natural gas revenues grew 13% to $240.3 million for the year.
• Adjusted funds from operations increased 16% to $145.1 million.
• Cash and cash equivalents rose 66% to $68.3 million.

Negative

• Net loss of $4.7 million for the year due to a non-cash deferred tax expense of $51.4 million.
• Natural gas and LNG production decreased 6% to 170.1 MMscfpd in Q4.

CALGARY, Alberta, March 18, 2021 (GLOBE NEWSWIRE) -- Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX:CNE; OTCQX:CNNEF; BVC:CNEC) is pleased to report its financial and operating results for the three months and year ended December 31, 2020. Dollar amounts are expressed in United States dollars (“USD”), except as otherwise noted.

Charle Gamba, President and CEO of the Corporation, commented: "Canacol’s success continued into 2020 despite the COVID-19 global pandemic.   2020 EBITDAX of $187.5 million increased 12% over 2019 levels, and fourth quarter 2020 EBITDAX continued to strengthen, posting an increase of 9% over the third quarter 2020 levels. Despite a 2020 reduced drilling program which included only six of our planned twelve wells due to COVID-19 (and only two of those being exploration wells), the Corporation managed to more than replace its produced reserves, which is a direct indication of the high quality of our exploration 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. Since 2013, we have added 771 billion cubic feet of proved plus probable conventional natural gas reserves (“2P”) from commercial success in thirty-three out of thirty-seven drilled wells, representing a 31% compound annual growth rate (“CAGR”) at an industry-leading three-year 2P finding and development cost of 84 USD cents per thousand cubic feet. With a portfolio of 162 identified prospects and leads containing mean unrisked prospective gas resource of 4.7 trillion cubic feet, according to the Corporation’s 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."

Highlights for the three months and year ended December 31, 2020

(Production is stated as working-interest before royalties)

Financial and operational highlights of the Corporation include:

• The Corporation’s conventional natural gas proved developed producing reserves (“PDP”) increased 10% since December 31, 2019, totalling 277 billion cubic feet (“Bcf”) at December 31, 2020 (140% PDP reserves replacement ratio). The Corporation’s conventional natural gas total proved plus probable reserves (“2P”) increased 2% since December 31, 2019, totalling 637 Bcf at December 31, 2020 (122% 2P reserves replacement ratio). The Corporation’s conventional natural gas proved reserves (“1P”) increased 0.2% since December 31, 2019, totalling 395 Bcf at December 31, 2020 (101% 1P reserves replacement ratio).
• 1P and 2P finding and development cost (“F&D cost”) were $1.18 per Mcf and $0.84 per Mcf for the three year period ending December 31, 2020, respectively.
• The Corporation achieved a 2.7x and 4.4x 2P recycle ratio for the one and three year period ending December 31, 2020, respectively. The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2020 of $3.57 per Mcf, and the three-year recycle ratio was calculated based on weighted average natural gas netback for the three year ended December 31, 2020 of $3.71 per Mcf.
• The Corporation achieved a 2.1x and 3.2x 1P recycle ratio for the one and three year period ending December 31, 2020, respectively. The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2020 of $3.57 per Mcf, and the three-year recycle ratio was calculated based on weighted average natural gas netback for the three year ended December 31, 2020 of $3.71 per Mcf.
• The Corporation achieved a 1P and 2P Reserves life index (“RLI”) of 6.4 years and 10.3 years, respectively, based on annualized fourth quarter 2020 conventional natural gas production of 170,087 Mcfpd or 29,840 Boepd.
• Realized contractual natural gas and liquefied natural gas (“LNG”) sales decreased 6% to 169.8 MMscfpd for the three months ended December 31, 2020, compared to 180.8 MMscfpd for the same period in 2019. Natural gas and LNG production volumes decreased 6% to 170.1 MMscfpd from 181 MMscfpd during the three months ended December 31, 2020, compared to the same period in 2019. The decrease is primarily due to the decrease in spot market sales as a result of the COVID-19 pandemic.
• Realized contractual natural gas and LNG sales increased 20% to 171.6 MMscfpd for the year ended December 31, 2020, compared to 142.6 MMscfpd for the same period in 2019. Natural gas and LNG production volumes increased 19% to 171.1 MMscfpd from 143.5 MMscfpd during the year ended December 31, 2020, compared to the same period in 2019. The increase is due to the completion of the pipeline connecting the Corporation’s natural gas processing facility to Cartagena, Colombia in late Q3 2019 (the “2019 pipeline expansion”), offset by lower than anticipated spot market sales due to the COVID-19 pandemic.
• Total natural gas revenues, net of royalties and transportation expenses decreased 5% to $60.9 million for the three months ended December 31, 2020, compared to $64.2 million for same period in 2019, primarily due a reduction in spot market sales as a result of the COVID-19 pandemic. Total natural gas revenues, net of royalties and transportation expenses increased 13% to $240.3 million for the year ended December 31, 2020, compared to $212.4 million for same period in 2019, mainly attributable to the increase of natural gas production due to the 2019 pipeline expansion.
• Adjusted funds from operations increased 7% and 16% to $35.3 million and $145.1 million for the three months and year ended December 31, 2020, respectively, compared to $33 million and $124.9 million for the same periods in 2019, respectively. Adjusted funds from operations per basic share increased 11% and 14% to $0.20 per basic share and $0.80 per basic share for the three months and year ended December 31, 2020, respectively, compared to $0.18 per basic share and $0.70 per basic share for the same periods in 2019, respectively.
• EBITDAX increased 6% and 12% to $45.9 million and $187.5 million for the three months and year ended December 31, 2020, respectively, compared to $43.1 million and $167.5 million for the same periods in 2019, respectively.
• The Corporation realized a net income of $0.9 million and a net loss of $4.7 million for the three months and year ended December 31, 2020, respectively, compared to a net income of $25.4 million and $34.2 million for the same periods in 2019, respectively. The net loss realized during the year ended December 31, 2020 is solely due to the non-cash deferred tax expense of $51.4 million mainly due to an increase in the valuation allowance (refer to the “Income Tax Expense” section of the MD&A for further details).
• The Corporation’s natural gas and LNG operating netback was $3.58 per Mcf in the three months ended December 31, 2020 and 2019. The average sales price, net of transportation increased due to higher spot market gas sales prices during the three months ended December 31, 2020, however the increase was offset by an increase in royalties and operating expenses per Mcf. The Corporation’s natural gas and LNG operating netback decreased 7% to $3.57 per Mcf for the year ended December 31, 2020, as compared to $3.82 per Mcf in the same period in 2019. The decrease is mainly due to lower spot sales prices due the COVID-19 pandemic and higher royalties mainly due to increased production at the Corporation’s VIM-5 block, which is subject to a higher royalty rate.
• Net capital expenditures for the three months and year ended December 31, 2020 were $29.4 million and $84 million, respectively. Net capital expenditures included non-cash adjustments related to decommissioning obligations and right-of-use leased assets of $3.1 million and $1.4 million for the three months and year ended December 31, 2020, respectively.
• As at December 31, 2020, the Corporation had $68.3 million in cash and cash equivalents and $73.4 million in working capital surplus.

Outlook

For the remainder of 2021, the Corporation is focused on the following operational objectives: 1) the drilling of twelve exploration, appraisal, and development wells in a continuous program with the objective of targeting a 2P reserves replacement ratio of more than 200 percent, 2) the acquisition of the 655 square kilometers of 3D seismic on the Corporation’s VIM-5 and SSJN-7 blocks to expand its exploration prospect inventory, 3) the execution of a definitive agreement to construct a new gas pipeline from the Jobo natural gas processing facility to Medellin, Colombia which will increase the Corporation’s natural gas sales by an additional 100 MMscfpd in 2024, and 4) the continued strengthening of our environmental, social and governance strategy and reporting.

FINANCIAL & OPERATING HIGHLIGHTS
(in United States dollars (tabular amounts in thousands) except as otherwise noted)

Financial	Three months ended December 31,									Year ended December 31,
		2020			2019		Change				2020				2019		Change
Total natural gas, LNG and crude oil revenues, net of royalties and transportation expense		63,976			65,795		(3	%)			246,804				219,522		12	%
Adjusted Funds from operations(1)		35,251			32,999		7	%			145,122				124,915		16	%
Per share – basic ($)(1)		0.20			0.18		11	%			0.80				0.70		14	%
Per share – diluted ($)(1)		0.20			0.18		11	%			0.80				0.69		16	%
Net income (loss) and comprehensive income (loss)(2)		921			25,432		(96	%)			(4,743	)			34,247		n/a
Per share – basic ($)		0.01			0.14		(93	%)			(0.03	)			0.19		n/a
Per share – diluted ($)		0.01			0.14		(93	%)			(0.03	)			0.19		n/a
Cash flow provided by operating activities		26,477			35,388		(25	%)			152,325				106,470		43	%
Per share – basic ($)		0.15			0.20		(25	%)			0.84				0.60		40	%
Per share – diluted ($)		0.15			0.20		(25	%)			0.84				0.59		42	%
EBITDAX(1)		45,941			43,144		6	%			187,528				167,515		12	%
Weighted average shares outstanding – basic		179,764			179,238		—				180,646				178,266		1	%
Weighted average shares outstanding – diluted		179,764			181,412		(1	%)			180,646				180,395		—
Capital expenditures, net dispositions		29,366			21,514		36	%			83,964				100,487		(16	%)
											Dec 31, 2020				Dec 31, 2019		Change
Cash and cash equivalents											68,280				41,239		66	%
Restricted cash											—				4,524		(100	%)
Working capital surplus											73,404				50,676		45	%
Total debt											415,209				392,946		6	%
Total assets											749,792				754,062		(1	%)
Common shares, end of period (000’s)											179,515				180,075		—
Operating	Three months ended December 31,									Year ended December 31,
		2020			2019		Change				2020				2019		Change
Production, before royalties(1)
Natural gas and LNG (MMscfpd)		170,087			180,986		(6	%)			171,126				143,524		19	%
Colombia oil (bopd)		287			309		(7	%)			291				351		(17	%)
Total (boepd)		30,127			32,061		(6	%)			30,313				25,531		19	%
Realized contractual sales, before royalties(1)
Natural gas and LNG (MMscfpd)		169,763			180,753		(6	%)			171,600				142,603		20	%
Colombia oil (bopd)		300			301		—				286				356		(20	%)
Total (boepd)		30,083			32,012		(6	%)			30,392				25,374		20	%
Operating netbacks(1)
Natural gas and LNG ($/Mcf)		3.58			3.58		—				3.57				3.82		(7	%)
Colombia oil ($/bopd)		23.04			27.08		(15	%)			18.57				25.92		(28	%)
Corporate ($/boe)		20.44			20.49		—				20.34				21.80		(7	%)

(1)   Non-IFRS measures – see “Non-IFRS Measures” section within the MD&A.
(2)  During the year ended December 31, 2020, the Corporation realized a net loss of $4.6 million solely as a result of a non-cash deferred tax expense of $51.2 million related mainly to an increase in the valuation allowance (refer to the “Income Tax Expense” section within the MD&A for further details).

This press release should be read in conjunction with the Corporation’s audited consolidated financial statements and related Management’s Discussion and Analysis (“MD&A”). The Corporation’s has filed its audited consolidated financial statements, related MD&A and Annual Information Form as at and for the year ended December 31, 2020 with Canadian securities regulatory authorities. These filings are available for review on SEDAR at www.sedar.com.

Canacol is a natural gas exploration and production company with operations focused in Colombia. The Corporation’s shares are traded on the Toronto Stock Exchange under the symbol CNE, the OTCQX in the United States of America under the symbol CNNEF and the Bolsa de Valores de Colombia under the symbol CNEC.

This press release contains certain forward-looking statements within the meaning of applicable securities law. Forward-looking statements are frequently characterized by words such as “plan”, “expect”, “project”, “target”, “intend”, “believe”, “anticipate”, “estimate” 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. Information and guidance provided herein supersedes and replaces any forward looking information provided in prior disclosures. 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. Other risks are more fully described in the Corporation’s most recent MD&A and Annual Information Form, which are incorporated herein by reference and are filed on SEDAR at www.sedar.com. Average production figures for a given period are derived using arithmetic averaging of fluctuating historical production data for the entire period indicated and, accordingly, do not represent a constant rate of production for such period and are not an indicator of future production performance. Detailed information in respect of monthly production in the fields operated by the Corporation in Colombia is provided by the Corporation to the Ministry of Mines and Energy of Colombia and is published by the Ministry on its website; a direct link to this information is provided on the Corporation’s website. References to “net” production refer to the Corporation’s working-interest production before royalties.

Use of Non-IFRS Financial Measures - Such supplemental measures should not be considered as an alternative to, or more meaningful than, the measures as determined in accordance with IFRS as an indicator of the Corporation’s performance, and such measures may not be comparable to that reported by other companies. This press release also provides information on adjusted funds from operations. Adjusted funds from operations is a measure not defined in IFRS. It represents cash provided by operating activities before changes in non-cash working capital and decommissioning obligation expenditures. The Corporation considers funds from operations a key measure as it demonstrates the ability of the business to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Funds from operations should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance. The Corporation’s determination of adjusted funds from operations may not be comparable to that reported by other companies. For more details on how the Corporation reconciles its cash provided by operating activities to adjusted funds from operations, please refer to the “Non-IFRS Measures” section of the Corporation’s MD&A. Additionally, this press release references working capital, EBITDAX and operating netback measures. Working capital is calculated as current assets less current liabilities, excluding the current portion of long-term obligations, and is used to evaluate the Corporation’s financial leverage. EBITDAX is defined as consolidated net income adjusted for interest, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-recurring or non-cash charges. Operating netback is a benchmark common in the oil and gas industry and is calculated as total natural gas, LNG and petroleum sales, net transportation expenses, less royalties and operating expenses, calculated on a per barrel of oil equivalent basis of sales volumes using a conversion. Operating netback is an important measure in evaluating operational performance as it demonstrates field level profitability relative to current commodity prices. Working capital, EBITDAX and operating netback as presented do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities.

Operating netback is defined as revenues, net transportation expenses less royalties and operating expenses.

Realized contractual sales is defined as natural gas and LNG produced and sold plus income received from nominated take-or-pay contracts without the actual delivery of natural gas or LNG and the expiry of the customers’ rights to take the deliveries.

The Corporation’s LNG sales account for less than one percent of the Corporation’s total realized contractual natural gas and LNG sales during the three months and year ended December 31, 2020.

Boe Conversion - The term “boe” is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet of natural gas to barrels oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, we have expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and Energy of Colombia. 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 Mcf:1, utilizing a conversion on a 5.7 Mcf:1 basis may be misleading as an indication of value.

“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.

1P Reserves replacement ratio: Ratio of reserve additions to production, as reported in the MD&A during the year ended December 31, 2020 excluding acquisitions and dispositions on a Total Proved basis.

2P Reserves replacement ratio: Ratio of reserve additions to production, as reported in the MD&A during the year ended December 31, 2020, excluding acquisitions and dispositions on a Total Proved + Probable basis.

Finding and development costs per Mcf represent exploration and development costs incurred per Mcf of Total Proved + Probable reserves added during the year ended December 31, 2020. 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.

The recycle ratio is calculated by dividing natural gas netback by finding and development costs relating to natural gas.

The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2020 of $3.57/Mcf, and the three-year recycle ratio was calculated based on natural gas netback for the three year ended December 31, 2020 of $3.71/Mcf.      

 

FAQ

What were Canacol Energy's 2020 financial results?

Canacol Energy reported a EBITDAX of $187.5 million in 2020, up 12% from 2019.

How did Canacol Energy perform in the fourth quarter of 2020?

In Q4 2020, Canacol's EBITDAX increased by 9% compared to Q3 2020.

What was Canacol Energy's net income or loss for 2020?

Canacol Energy had a net loss of $4.7 million for the year ended December 31, 2020.

What are Canacol Energy's future plans for 2021?

In 2021, Canacol plans to drill twelve wells and expand seismic operations.

What is Canacol Energy's stock symbol?

Canacol Energy is traded on the OTCQX under the symbol CNNEF.