CALGARY, Alberta, March 18, 2020 (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, 2019. Dollar amounts are expressed in United States dollars (“USD”), except as otherwise noted.
Charle Gamba, President and CEO of the Corporation, commented: “In 2019 the Corporation achieved several important goals with respect to growing its gas business in Colombia including a 26% increase in gas sales year over year related to the expansion of transportation infrastructure, a 12% increase in 2P reserves year over year related to continued exploration and development success, the award of three new conventional gas exploration blocks in the 2019 exploration bid round and the sale of our last remaining oil producing asset.
For 2020 the Corporation remains focused on the following objectives: 1) the drilling of twelve exploration, appraisal, and development wells in a continuous program representing the largest exploration drilling program ever executed by Canacol, 2) the execution of a definitive agreement to construct a new gas pipeline which will increase the Corporation's gas sales by an additional 100 MMscfpd in 2023, 3) continuing our program of quarterly dividend payments and scheduled debt repayment, and 4) continue with our commitment of strengthening our Environmental, Social and Governance strategy (“ESG”) and reporting to ensure successful results for our stakeholders.
Our production mix consists of 100% natural gas with no oil production. Approximately 80% of our gas production is sold under take-or-pay contracts denominated in USD and priced at the wellhead. Approximately 20% of our gas sales is sold under interruptible contracts denominated in USD and priced at the wellhead. As such, the Corporation is insulated from the current effects of low worldwide oil prices which has seen its oil weighted peers recently cut capital programs, production forecasts, and return of capital to shareholders.
The Corporation therefore maintains its previously announced 2020 capital expenditure, production, and return of capital guidance. The 2020 capital budget remains at $114 million, which will be fully funded from existing cash held and 2020 cash flow. Forecasted realized contractual gas sales for 2020, including off-taker downtime, are anticipated to average approximately 205 MMscfpd, representing a 43% increase over the 2019 average natural gas realized contractual sales of 143 MMscfpd. The average natural gas sales price, net of transportation costs, where applicable, are expected to be approximately $4.80/Mcf. Actual contractual gas sales during the period January 1, 2020 to March 13, 2020 averaged 207 MMscfpd.
The Corporation’s forecasted production, EBITDAX and cash flow from operations for 2020 is anticipated to be substantially higher than previous years, with EBITDAX forecasted to be approximately $265 million, up 58% from $167.5 million in 2019. During 2020, the Corporation plans to use excess cash to: 1) maintain our quarterly dividend payment, which has been set at C$0.052 per share, totaling approximately $7 million for the first quarter of 2020, payable on April 15, 2020 to shareholders of record at the close of business on March 31, 2020; 2) reduce debt by approximately $15 million and 3) continue to repurchase common shares of the Corporation under its Normal Course Issuer Bid. Also, notable is a significant forecast decrease in the Corporation’s Net Debt to EBITDAX ratio, which stood at 2.1x at December 31, 2019 and is anticipated to be approximately 1.1x on December 31, 2020.”
Highlights for the three months and year ended December 31, 2019
(Production is stated as working-interest before royalties)
Financial and operational highlights of the Corporation include:
- The Corporation’s conventional natural gas total proved plus probable reserves (“2P”) increased 12% since December 31, 2018, totaling 624 billion cubic feet (“Bcf”) at December 31, 2019, with a before tax value discounted at 10% of $2.1 billion, representing both C$15.47 per share of reserve value and C$13.41 per share of 2P net asset value (net of $285.6 million of net debt). The Corporation’s conventional natural gas proved developed producing reserves (“PDP”) increased 31% since December 31, 2018, totaling 252 Bcf at December 31, 2019.
- 2P and PDP reserve replacement ratio of 224% and 213% based on calendar 2019 gross conventional natural gas reserve additions of 117 Bcf and 112 Bcf, respectively.2P finding and development cost was $0.67/Mcf for the three year period ending December 31, 2019.
- The Corporation’s 2P recycle ratio achieved was a 4.4x and 5.7x for the one and three year periods ending December 31, 2019, respectively. The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2019 of $3.82/Mcf, and the three-year recycle ratio was calculated based on natural gas netback for the three year ended December 31, 2019 of $3.83/Mcf.
- The Corporation’s 1P recycle ratio achieved was a 2.7x and 3.9x for the one and three year periods ending December 31, 2019, respectively. The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2019 of $3.82/Mcf, and the three-year recycle ratio was calculated based on natural gas netback for the three year ended December 31, 2019 of $3.83/Mcf.
- Realized contractual natural gas sales increased 52% and 26% to 180.8 MMscfpd and 142.6 MMscfpd for the three months and year ended December 31, 2019, compared to 119.3 MMscfpd and 113.3 MMscfpd for the same periods in 2018, respectively. Average natural gas production volumes increased 55% and 28% to 181 MMscfpd and 143.5 MMscfpd for the three months and year ended December 31, 2019, compared to 116.6 MMscfpd and 112.1 MMscfpd for the same periods in 2018, respectively.
- Total natural gas revenue, net of royalties and transportation expenses for the three months and year ended December 31, 2019, increased 39% and 24% to $64.2 million and $212.4 million, compared to $46.2 million and $171.2 million for same periods in 2018, respectively, mainly attributable to the increase of natural gas production.
- The Corporation realized an EBITDAX of $43.1 million and $167.5 million for the three months and year ended December 31, 2019, compared to $31.7 million and $136.9 million for the same periods in 2018, respectively.
- Adjusted funds from operations increased 15% and 19% to $33 million and $124.9 million for the three months and year ended December 31, 2019, compared to $28.7 million and $104.9 million for the same periods in 2018, respectively. Adjusted funds from operations per share increased 13% and 19% from $0.16 per basic share and $0.59 per basic share to $0.18 per basic share and $0.70 per basic share, respectively.
- The Corporation recorded net income of $25.4 million and $34.2 million for the three months and year ended December 31, 2019, compared to net losses of $16.3 million and $21.8 million for the same periods in 2018, respectively.
- The Corporation’s natural gas operating netback increased 1% to $3.82 per Mcf in the year ended December 31, 2019, compared to $3.80 per Mcf for the same period in 2018. The increase is as a result of the 33% reduction of operating expenses per Mcf to $0.28 per Mcf for the year ended December 31, 2019, compared to the $0.42 per Mcf for the same period in 2018.
- Net capital expenditures for the three months and year ended December 31, 2019 were $21.5 million and $100.5 million, respectively. Net capital expenditures were net of the $14.5 million disposition of working interest of the Sabanas flowline during the year ended December 31, 2019 and non-cash additions relating to decommissioning obligations of $0.8 and $3.8 million and right-of-use leased assets of $4.3 million and $8.8 million for the three months and year ended December 31, 2019, respectively.
- As at December 31, 2019, the Corporation had $41.2 million in cash and cash equivalents, $4.5 million in restricted cash and $50.7 million in working capital surplus.
- The Corporation drilled three development wells, Nelson-13, Palmer-2, Nelson-7 and four exploration wells, Pandereta-5, Acordeon-1, Ocarina-1 and Arandala-1 during the year ended December 31, 2019.
- The expansion of the Jobo to Cartagena pipeline was completed and the Jobo 3 natural gas processing facility commenced operation during the year ended December 31, 2019, lifting Canacol’s natural gas treatment capacity from previous levels of 200 MMcfpd to 330 MMcfpd.
- As a result of recent world events, the Corporation is benefiting from the current depreciation of the Colombian peso (“COP”) and the Canadian dollar (“CAD”). As of the date of this press release, the COP decline of approximately 22% against the USD, effectively reduces USD denominating expenditures on capital expenditures, operating costs and G&A of approximately $15 million for the remainder of 2020, as compared to the Corporation’s original budget estimates. The Corporation has foreign exchange collar on the COP which expires in July 2020 (on which Canacol has historically been ‘in the money’ on) effectively reduces the above savings by approximately 15% for the remainder of 2020. Similarly, the recent 8% weakness in the CAD effectively reduces the Canadian based G&A.
OUTLOOK
During the first quarter of 2020, the Corporation completed the drilling of the Nelson-14 development well, which encountered 309 feet of net gas pay, and is currently drilling the Clarinete-5 development well. Upon the completion of the Clarinete-5 well, the Corporation will drill the Porro Norte-1 exploration well, its first exploration well of 2020, which is anticipated to spud in mid-April 2020.
The Corporation is in the process of contracting a second drilling rig in order to achieve our drilling target of twelve wells, with the goal of replacing production by more than 200% and continuing to increase our reserves base. The Corporation anticipates adding the second drilling rig in May, 2020, which is expected to execute four of the twelve well drilling program through to year-end.
Canacol takes its responsibility to its environment, communities, and governance seriously. During 2020, we will continue to strengthen our ESG strategy and reporting, ensuring successful results for our stakeholders. We execute our activities to the highest technical standards to ensure minimum impact on the environment, and maximum investment in the local communities. During 2020, we will continue to build the greenhouse gas effect (“GHG”) inventory of our activities and deepen our commitment to the reduction of our carbon footprint, contributing to compliance with global objectives and commitments made by the Colombian government to counteract climate change. We are conscious of the importance of clean and abundant water for the future of the planet and our children, and we will continue to adopt and promote initiatives to ensure the protection and preservation of water sources in our areas of operation.
Finally, the Corporation has taken all of the appropriate measures to ensure the continuity of its operations and business in Colombia and Canada, including compliance with all local, provincial, and national mandatory decrees.
| Financial | Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||
| 2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
| Total natural gas and crude oil revenues, net of royalties and transportation expense | $ | 65,795 | $ | 50,727 | 30 | % | $ | 219,522 | $ | 204,151 | 8 | % | |||||||||||
| Adjusted funds from operations(1) | $ | 33,004 | $ | 28,679 | 15 | % | $ | 124,915 | $ | 104,914 | 19 | % | |||||||||||
| Per share – basic ($)(1) | 0.18 | 0.16 | 13 | % | 0.70 | 0.59 | 19 | % | |||||||||||||||
| Per share – diluted ($)(1) | 0.18 | 0.16 | 13 | % | 0.69 | 0.59 | 17 | % | |||||||||||||||
| Cash flow provided by operating activities | $ | 37,181 | $ | 18,753 | 98 | % | $ | 108,350 | $ | 94,011 | 15 | % | |||||||||||
| Per share – basic ($) | 0.21 | 0.11 | 91 | % | 0.61 | 0.53 | 15 | % | |||||||||||||||
| Per share – diluted ($) | 0.20 | 0.10 | 100 | % | 0.60 | 0.53 | 13 | % | |||||||||||||||
| Net income (loss) and comprehensive income (loss) | $ | 25,432 | $ | (16,272 | ) | n/a | $ | 34,247 | $ | (21,835 | ) | n/a | |||||||||||
| Per share – basic ($) | 0.14 | (0.09 | ) | n/a | 0.19 | (0.12 | ) | n/a | |||||||||||||||
| Per share – diluted ($) | 0.14 | (0.09 | ) | n/a | 0.19 | (0.12 | ) | n/a | |||||||||||||||
| EBITDAX(1) | $ | 43,144 | $ | 31,686 | 36 | % | $ | 167,515 | $ | 136,876 | 22 | % | |||||||||||
| Weighted average shares outstanding – basic | 179,238 | 177,678 | 1 | % | 178,266 | 177,184 | 1 | % | |||||||||||||||
| Weighted average shares outstanding – diluted | 181,412 | 178,977 | 1 | % | 180,395 | 178,681 | 1 | % | |||||||||||||||
| Capital expenditures, net dispositions | $ | 21,514 | $ | 37,701 | (43 | %) | $ | 100,487 | $ | 127,591 | (21 | %) | |||||||||||
| As at December 31, | 2019 | 2018 | Change | ||||||||||||||||||||
| Cash and cash equivalents | $ | 41,239 | $ | 51,632 | (20 | %) | |||||||||||||||||
| Restricted cash | $ | 4,524 | $ | 4,196 | 8 | % | |||||||||||||||||
| Working capital surplus | $ | 50,676 | $ | 60,782 | (17 | %) | |||||||||||||||||
| Total debt | $ | 392,946 | $ | 388,222 | 1 | % | |||||||||||||||||
| Total assets | $ | 754,062 | $ | 705,003 | 7 | % | |||||||||||||||||
| Common shares, end of period (000’s) | 180,075 | 177,462 | 1 | % | |||||||||||||||||||
| Operating | Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||
| 2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
| Natural gas and crude oil production, before royalties(1) | |||||||||||||||||||||||
| Natural gas (Mcfpd) | 180,986 | 116,616 | 55 | % | 143,524 | 112,102 | 28 | % | |||||||||||||||
| Colombia oil (bopd) | 309 | 488 | (37 | %) | 351 | 1,546 | (77 | %) | |||||||||||||||
| Total (boepd)(2) | 32,061 | 20,947 | 53 | % | 25,531 | 21,213 | 20 | % | |||||||||||||||
| Realized contractual sales, before royalties(1) | |||||||||||||||||||||||
| Natural gas (Mcfpd) | 180,753 | 119,284 | 52 | % | 142,603 | 113,261 | 26 | % | |||||||||||||||
| Colombia oil (bopd) | 301 | 592 | (49 | %) | 356 | 1,581 | (77 | %) | |||||||||||||||
| Total (boepd)(2) | 32,012 | 21,519 | 49 | % | 25,374 | 21,451 | 18 | % | |||||||||||||||
| Operating netbacks(1) | |||||||||||||||||||||||
| Natural gas ($/Mcf) | 3.58 | 3.92 | (9 | %) | 3.82 | 3.80 | 1 | % | |||||||||||||||
| Colombia oil ($/bopd) | 27.08 | 27.89 | (3 | %) | 25.92 | 31.18 | (17 | %) | |||||||||||||||
| Corporate ($/boe)(2) | 20.49 | 22.51 | (9 | %) | 21.80 | 22.42 | (3 | %) | |||||||||||||||
- Non-IFRS measures – see “Non-IFRS Measures” section within the Management's Discussion and Analysis.
- The Corporation has excluded results relating to the Ecuador IPC in the prior period for comparative purposes.
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 has filed its audited consolidated financial statements and related MD&A and Annual Information Form as of and for the year ended December 31, 2019 with Canadian securities regulatory authorities. These filings are available for review on SEDAR at www.sedar.com.
Canacol is an 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, the Bolsa de Valores de Colombia under the symbol CNEC and the Bolsa Mexicana de Valores under the symbol CNEN.
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 funds from operations. 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 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 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 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 gas sales is defined as gas produced and sold plus gas revenues received from nominated take or pay contracts.
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, 2019 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, 2019, 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, 2019. 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, 2019 of $3.82/Mcf, and the three-year recycle ratio was calculated based on natural gas netback for the three year ended December 31, 2019 of $3.83/Mcf.