CALGARY, ALBERTA–(Marketwired – May 10, 2017) – 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 ended March 31, 2017. Dollar amounts are expressed in United States dollars, except as otherwise noted.
“During the first quarter of 2017, Canacol achieved significant growth in realized contractual sales volumes to 18,043 boepd, a 61% increase over the same quarter in 2016,” commented Charle Gamba, President and CEO of Canacol. “Adjusted funds from operations for Q1 2017 increased 56% to $20.9 million compared to $13.5 million for the same quarter in 2016.
Work on the private pipeline project that will lift Canacol’s natural gas production to 130 MMscfpd in December 2017 is advancing very well. The right of ways required for the pipeline continue to be acquired, and the major tubular contract has been awarded to FlexSteel for delivery to Colombia in mid-July 2017. The SPV has also negotiated a contract with Enerflex Ltd. for compression which is expected to be delivered to Colombia in early August 2017. We anticipate construction of the pipeline to commence in September 2017, with first gas by December 1, 2017.
Canacol is in the final stages of evaluating three separate financing proposals for this pipeline and anticipates finalizing terms with the preferred option by the end of May 2017. The productive capacity of the Corporation’s currently producing wells is approximately 195 MMscfpd, and that of the Corporation’s gas processing facilities approximately 200 MMscfpd, more than adequate to lift production to 130 MMscfpd in December 2017 when construction of the private pipeline is complete. As previously announced, Canacol executed a ten year take-or-pay contract for 40 MMscfpd of gas at contractual terms comparable to the Corporation’s current US dollar denominated gas sale contracts which is expected to be transported by the new pipeline in December 2017.
Meanwhile we continue to encounter solid exploration success, announcing our seventh consecutive natural gas discovery at Canahuate-1 that tested 28 MMscfpd of dry gas, and an oil discovery at Mono Capuchino-1ST that tested 1,013 bopd of light oil. Throughout the remainder of 2017, we plan to drill two more high impact reserves add natural gas exploration wells, Toronja-1 in June 2017, and Pandereta 1 in October 2017. The reserves from Canahuate-1, and the potential reserves from Toronga and Pandereta, will move us closer to our goal of lifting production to 230 MMscfpd by December 2018 via the new pipeline expansion to Cartagena and Barranquilla that Promigas S.A. has initiated.
Canacol also replaced its $255 million BNP Senior Secured Term Loan and Apollo Notes with a $265 million seniorr secured term loan with a syndicate of banks led by Credit Suisse (“2017 Senior Secured Term Loan”). This refinancing and consolidation achieved the following benefits: a) it defers amortization payments until March 2019, allowing the Corporation to dedicate capital to high netback production related projects instead of debt service; b) it reduces the total annual interest costs as compared to the combined BNP Senior Secured Term Loan and Apollo Notes by approximately 1.1%; and c) it harmonizes compliances and administrative deliverables under one facility. Although the Corporation’s current contemplated 2017 capital budget lies within its 2017 cash flow and existing cash, the new credit agreement also allows an additional $40 million of greenshoe funds available within 12 months post-funding, allowing Canacol increased financial flexibility as it pursues its states gas production target of 230 MMscfpd by late 2018.”
Highlights for the three months ended March 31, 2017
(Production is stated as working-interest before royalties)
Financial and operational highlights of the Corporation include:
- Realized contractual sales volumes increased 61% to 18,043 boepd for the three months ended March 31, 2017 compared to 11,220 boepd for the same period in 2016, primarily due to increase in gas production in Esperanza and VIM-5 as a result of the additional sales related to the Promigas pipeline expansion.
- Average production volumes increased 55% to 16,992 boepd for the three months ended March 31, 2017 compared to 10,933 boepd for the same period in 2016, primarily due to increase in gas production in Esperanza and VIM-5 as a result of the additional sales related to the Promigas pipeline expansion.
- Adjusted funds from operations for the three months ended March 31, 2017 increased 56% to $20.9 million compared to the same period in 2016. Adjusted funds from operations are inclusive of results from the Ecuador Incremental Production Contract (the “Ecuador IPC”) (see full discussion in MD&A). The increase in adjusted funds from operations is primarily the result of additional sales related to the Promigas pipeline expansion.
- Total petroleum and natural gas revenues for the three months ended March 31, 2017 increased 83% to $41.6 million compared to $22.7 million for same period in 2016. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador IPC, for the three months ended March 31, 2017 increased 62% to $47 million compared to $29 million for the same period in 2016. The increase in revenues reflects the additional sales related to the Promigas pipeline expansion and an increase in benchmark crude oil prices.
- Total production expenses per boe increased 9% to $3.75/boe for the three months ended March 31, 2017 compared to $3.45/boe for the same period in 2016, despite a 55% production increase in the three months ended March 31, 2017 compared to the same period in 2016 as the increase in natural gas production did not increase production expenses significantly due to the majority of the natural gas production expenses being fixed.
- Net loss of $7.9 million for the three months ended March 31, 2017 is mainly driven by non-cash expenses related to depletion and depreciation ($9.8 million), stock-based compensation ($3.3 million), unrealized loss on financial instruments ($2.3 million) and unrealized loss on foreign exchange ($1.7 million), offset by non-cash deferred tax recovery of $5.6 million.
- On March 24, 2017, the Canahuate-1 exploration well was spud. The Canahuate-1 well is located three kilometers (“kms”) north of the Corporation’s Jobo gas processing facility and is targeting gas-bearing sandstones within the Cienaga de Oro reservoir (“CDO”). The well encountered 124 ft. md (86 feet true vertical depth) of net gas pay with average porosity of 18% within the primary CDO reservoir target. Two different zones were completed and flow tested at a combined rate of 28.4 MMscfpd of dry gas. Work is underway to tie the Canahuate-1 well into the Corporation’s gas processing facility at Jobo.
- The Mono Capuchino-1ST exploration well was spud on December 17, 2016, reaching a total depth of 10,023 ft. md before experiencing mechanical difficulties that required the well to be sidetracked. The Mono Capuchino-1ST well reached a total depth of 10,245 ft. md within the La Luna formation on February 22, 2017. The well encountered approximately 103 feet of net oil pay within the Tertiary Basal Lisama sandstone reservoir, and approximately 406 feet of net oil pay within the Cretaceous La Luna formation, which consists of shale and limestones and open fractures visible on image logs. Approximately 769 feet of open hole section within the La Luna was tested and recovered uncommercial heavy oil. The Mono Capuchino-1ST well will be tied into the permanent production facilities located at Mono Arana and brought on full time production from the Tertiary Basal Lisama sandstone reservoir, which tested at 1,013 barrels of oil per day (“bopd”) (gross), in the second quarter of 2017.
- Net capital expenditures including acquisitions for the three months ended March 31, 2017 was $24 million, while adjusted capital expenditures including acquisitions, inclusive of amounts related to the Ecuador IPC, was $24.8 million.
- At March 31, 2017, the Corporation had $44.8 million in cash and $62.5 million in restricted cash and continues to be well within all of its banking covenants.
| Financial | Three months ended March 31, | ||||||
| 2017 | 2016 | Change | |||||
| Total petroleum and natural gas revenues, net of royalties | 41,583 | 22,700 | 83 | % | |||
| Adjusted petroleum and natural gas revenues, net of royalties(2) | 46,975 | 29,000 | 62 | % | |||
| Cash provided by operating activities | 17,539 | 7,249 | 142 | % | |||
| Per share – basic ($) | 0.10 | 0.05 | 100 | % | |||
| Per share – diluted ($) | 0.10 | 0.05 | 100 | % | |||
| Adjusted funds from operations (1) (2) | 20,947 | 13,451 | 56 | % | |||
| Per share – basic ($) | 0.12 | 0.08 | 50 | % | |||
| Per share – diluted ($) | 0.12 | 0.08 | 50 | % | |||
| Net (loss) income and comprehensive (loss) income | (7,942 | ) | 461 | n/a | |||
| Per share – basic ($) | (0.05 | ) | – | n/a | |||
| Per share – diluted ($) | (0.05 | ) | – | n/a | |||
| Capital expenditures, net, including acquisitions | 24,000 | 15,548 | 54 | % | |||
| Adjusted capital expenditures, net, including acquisitions(1)(2) | 24,818 | 15,949 | 56 | % | |||
| March 31, 2017 |
December 31, 2016 |
Change | |||||
| Cash | 44,778 | 66,283 | (32 | %) | |||
| Restricted cash | 62,518 | 62,073 | 1 | % | |||
| Working capital surplus | 52,678 | 64,899 | (19 | %) | |||
| Bank debt | 254,485 | 250,638 | 2 | % | |||
| Total assets | 786,164 | 787,508 | – | ||||
| Common shares, end of period (000’s) | 174,422 | 174,359 | – | ||||
| Three months ended March 31, | |||||||
| Operating | 2017 | 2016 | Change | ||||
| Petroleum and natural gas production, before royalties (boepd) | |||||||
| Petroleum (3) | 3,505 | 4,526 | (23 | %) | |||
| Natural gas | 13,487 | 6,407 | 111 | % | |||
| Total (2) | 16,992 | 10,933 | 55 | % | |||
| Petroleum and natural gas sales, before royalties (boepd) | |||||||
| Petroleum (3) | 3,517 | 4,578 | (23 | %) | |||
| Natural gas | 13,409 | 6,329 | 112 | % | |||
| Total (2) | 16,926 | 10,907 | 55 | % | |||
| Realized contractual sales, before royalties (boepd) | |||||||
| Natural gas | 14,526 | 6,642 | 119 | % | |||
| Colombia oil | 2,014 | 2,856 | (29 | %) | |||
| Ecuador tariff oil (2) | 1,503 | 1,722 | (13 | %) | |||
| Total (2) | 18,043 | 11,220 | 61 | % | |||
| Operating netbacks ($/boe) (1) | |||||||
| Esperanza (natural gas) | 25.74 | 27.53 | (7 | %) | |||
| VIM-5 (natural gas) | 19.70 | 21.75 | (9 | %) | |||
| LLA-23 (oil) | 21.25 | 8.78 | 142 | % | |||
| Ecuador (tariff oil) (2) | 38.54 | 38.54 | – | ||||
| Total (2) | 24.56 | 23.90 | 3 | % | |||
| (1) | Non-IFRS measure – see “Non-IFRS Measures” section within MD&A. |
| (2) | Inclusive of amounts related to the Ecuador IPC – see “Non-IFRS Measures” section within MD&A. |
| (3) | Includes tariff oil production and sales related to the Ecuador IPC. |
This press release should be read in conjunction with the Corporation’s unaudited interim condensed consolidated financial statements and related Management’s Discussion and Analysis. The Corporation’s has filed its unaudited interim condensed consolidated financial statements and related Management’s Discussion and Analysis as of and for the three months ended March 31, 2017 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 and Ecuador. 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 Management Discussion and Analysis (“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 – Due to the nature of the equity method of accounting the Corporation applies under IFRS 11 to its interest in the Ecuador IPC, the Corporation does not record its proportionate share of revenues and expenditures as would be typical in oil and gas joint interest arrangements. Management has provided supplemental measures of adjusted revenues and expenditures, which are inclusive of the Ecuador IPC, to supplement the IFRS disclosures of the Corporation’s operations in this press release. 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, and includes the Corporation’s proportionate interest of those items that would otherwise have contributed to funds from operations from the Ecuador IPC had it been accounted for under the proportionate consolidation method of accounting. The Corporation considers adjusted 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. Adjusted 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 non-cash items, 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, share of joint venture profit/loss and other similar non-recurring or non-cash charges. Consolidated EBITDAX is further adjusted for the contribution to adjusted funds from operations, before taxes, of the results of the Ecuador IPC. Operating netback is a benchmark common in the oil and gas industry and is calculated as total petroleum and natural gas sales, less royalties, less production and transportation 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 less royalties and production and transportation 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 5.7:1, utilizing a conversion on a 5.7:1 basis may be misleading as an indication of value.
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