CALGARY, ALBERTA–(Marketwired – March 27, 2017) – Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to report its financial results for the year ended December 31, 2016. Dollar amounts are expressed in United States dollars, except as otherwise noted.
Charle Gamba, President and CEO of the Corporation, commented: “2016 saw the emergence of Canacol as a premier gas producer in Colombia. By April 2016, we had achieved our goal of 90 million standard cubic feet per day (“MMscfpd”) of gas production. As a result of the increased gas sales, our adjusted petroleum and natural gas revenues after royalties increased 43% to $173.2 million for the year ended December 31, 2016 compared to $121.5 million in 2015; our adjusted funds from operations increased 122% to $113 million for the year ended December 31, 2016 compared to $51 million in 2015; our EBITDAX increased 101% to $135.5 million for the year ended December 31, 2016 compared to $67.4 million in 2015; and we posted comprehensive income of $23.6 million in 2016. After achieving the 90 MMscfpd milestone, several significant new 2016 gas discoveries drive our reserve and production base towards our December 1, 2017 target of 130 MMscfpd, and our December 1, 2018 target of 230 MMscfpd, which will place Canacol as the second largest gas producer in Colombia behind the state oil company.
Our industry leading 2015/2016 average gas F&D of $2.52/boe ($0.44/Mcf), combined with our very low operating expenses and robust long term gas contracts denominated in US dollars, ensure that our current and future gas production will yield consistently high netbacks and margins for our shareholders. This operating base in conjunction with the financial flexibility achieved by the closing of the February, 2017 $265 million senior secured term loan, led by Credit Suisse, provides a solid platform for our targeted growth. For 2017, management’s primary goals are to 1) achieve a gas production rate of 130 MMscfpd by December 1, 2017 via the construction of a new private gas pipeline, 2) drill three gas exploration wells to continue to build the Corporation’s gas reserves base at industry leading F&D costs, and 3) drill two oil exploration wells to increase oil production and satisfy exploration commitments to the ANH.
With respect to the new private gas pipeline, a Special Purpose Vehicle (“SPV”) has been formed to build and operate a six inch pipeline that will transport 40 MMscfpd of gas from the Corporation’s Jobo gas processing facility to Sincelejo / Bremen approximately 80 kilometers (“kms”) to the north, where the private pipeline will connect to the Promigas operated pipeline that ships gas to Cartagena. Canacol has 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. A bank has been retained to raise the $60 million that the SPV will require to complete the pipeline outside of Canacol. In the meantime, the SPV is acquiring all of the right of ways required for the pipeline, and is tendering all of the major contracts which would include tubulars and compression. The Corporation anticipates that the pipeline will be in operation on December 1, 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.
Canacol has also spud the Canahuate-1 gas exploration well and the Pumara-1 oil exploration well. The Canahuate-1 exploration well, located on the Esperanza E&P Contract (100% operated working interest), was spud on March 24, 2017. The Canahuate-1 well is located approximately three kms north of the Corporation’s Jobo gas processing facility and is targeting gas bearing sandstones within the proven producing Cienaga de Oro reservoir. Over the past three years, six of the seven exploration wells drilled by the Corporation on its gas blocks, including the Esperanza E&P contract, have resulted in commercial gas discoveries. The Canahuate-1 well is expected to take approximately six weeks to drill and test.
Canacol also maintains a large inventory of light oil drill ready production and exploration opportunities. The Corporation will spud the Pumara-1 exploration well on the LLA-23 E&P Contract (100% operated working interest) on March 31, 2017. The Pumara-1 exploration well is located three kms north of the Labrador field and is targeting light oil bearing reservoirs within the proven producing C7, Mirador, Gacheta and Ubaque reservoirs. Over the past four years, five of the six exploration wells drilled by the Corporation on the LLA-23 contract have resulted in commercial light oil discoveries. The Pumara-1 well is expected to take approximately five weeks to drill and test, and if successful, it will be placed immediately on permanent production via the Corporation’s oil processing facilities located at Pointer.
With the 2017 capital program to be funded by a combination of existing working capital and cash flows, Canacol is well positioned to continue to build production and revenues despite the uncertainty and volatility associated with global oil prices, especially with a near to mid term global outlook of “low oil prices for longer”. It is important to point out that approximately 90% of our current production revenues are not impacted by global oil prices, and that the Corporation’s debt facility is not subject to redetermination should oil prices fall. Our financial strength, coupled with Canacol’s outstanding exploration drilling and commercialization track record, provides a solid platform which will allow us to reach our target of 230 MMscfpd of gas production exiting 2018.
The Corporation anticipates releasing an update on its Mono Capuchino-1 exploration well on March 28, 2017 and its 2017 guidance during the week of April 3, 2017.”
During 2016, the Corporation had many operational and financial accomplishments:
- The drilling and completion of the Oboe-1 exploration well and its combined test results of 66 MMscfpd in March 2016.
- The completion of the Promigas pipeline and the Promisol Jobo gas plant upgrade in April 2016, which allowed Canacol to increase gas production to 90 MMscfpd. Canacol’s total current gas processing capability is 200 MMscfpd.
- The drilling and completion of the Nispero-1 exploration well and its test result of 28 MMscfpd in August 2016.
- The completion of the first and second tranche of private placement offerings of 9,687,670 and 1,800,000 common shares of the Corporation, respectively, issued at C$4.08 per common share for a total of C$46.9 million in August 2016.
- The drilling and completion of the Trombon-1 exploration well and its test result of 26 MMscfpd in October 2016.
- The drilling and completion of the Nelson-6 exploration well and its test result of 23 MMscfpd in November 2016.
- The initiation of a private pipeline venture in November, 2016 that will deliver 40 MMscfpd of new gas production to new and existing customers located on the Caribbean coast in December 2017, thereby increasing the Corporation’s transportation capacity from its current 90 MMscfpd to 130 MMscfpd upon completion.
- The execution of the agreement with Promigas in November 2016 to expand the existing gas distribution network currently used by the Corporation to accommodate an additional 100 MMscfpd of new gas transportation and sales, thereby increasing the Corporation’s transportation capacity to 230 MMscfpd in December 2018.
- The drilling and completion of the Clarinete-3 development well and its test result of 18 MMscfpd in December 2016.
- The Nelson-5 Porquero recompletion and its test result of 13 MMscfpd in December 2016.
Highlights for the Three Months Ended December 31, 2016
(in thousands of United States dollars, except as otherwise noted; production is stated as working-interest before royalties)
Financial and operating highlights of the Corporation include:
- Realized contractual sales volumes increased 96% to 18,310 boepd for the three months ended December 31, 2016 compared to 9,359 boepd for the same period in 2015. The increase is primarily due to an increase in gas production in the Esperanza and VIM-5 blocks as a result of the additional sales related to the Promigas pipeline expansion.
- Average daily production volumes increased 96% to 17,728 boepd for the three months ended December 31, 2016 compared to 9,064 boepd for the same period in 2015. The increase is primarily due to an increase in gas production in the Esperanza and VIM-5 blocks as a result of the additional sales related to the Promigas pipeline expansion.
- Adjusted funds from operations for the three months ended December 31, 2016 increased 395% to $42 million compared to $8.5 million for the same period in 2015. 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 and an increase in benchmark crude oil prices.
- Petroleum and natural gas revenues for the three months ended December 31, 2016 increased 141% to $42 million compared to $17.4 million for the same period in 2015. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador IPC, for the three months ended December 31, 2016 increased 93% to $47.9 million compared to $24.9 million for the same period in 2015. The increase is primarily the result of additional sales related to the Promigas pipeline expansion.
- Average corporate operating netback for the three months ended December 31, 2016 increased 9% to $24/boe compared to $21.96/boe for the same period in 2015. Operating corporate netback is inclusive of results from the Ecuador IPC.
- The Corporation recorded a comprehensive income of $20.3 million for the three months ended December 31, 2016 despite the non-cash impairment charge of $37.3 million, mainly due to the execution of its tax planning strategies which significantly reduced income tax expense. The Corporation recognized a current income tax recovery of $6.3 million and a deferred income tax recovery of $42.3 million during the three months ended December 31, 2016 despite its $42 million adjusted funds from operations.
- Capital expenditures for the three months and year ended December 31, 2016 were $58.6 million and $107.9 million, respectively, while adjusted capital expenditures, inclusive of amounts related to the Ecuador IPC, were $59.7 million and $110.2 million, respectively.
- At December 31, 2016, the Corporation had $66.3 million in cash and $62.1 million in restricted cash.
|Petroleum and natural gas revenues, net of royalties||41,967||17,402||141%||147,985||39,360||276%||149,047||(1%)|
|Adjusted petroleum and natural gas revenues, net of royalties(2)||47,943||24,883||93%||173,184||54,782||216%||177,937||(3%)|
|Cash provided by operating activities||30,289||4,974||509%||73,577||19,276||282%||64,445||14%|
|Per share – basic ($)||0.17||0.03||467%||0.44||0.14||214%||0.58||(24%)|
|Per share – diluted ($)||0.17||0.03||467%||0.44||0.13||238%||0.58||(24%)|
|Adjusted funds from operations (1) (2)||41,979||8,473||395%||113,019||23,690||377%||87,395||29%|
|Per share – basic ($)||0.24||0.05||380%||0.68||0.17||300%||0.79||(14%)|
|Per share -diluted ($)||0.24||0.05||380%||0.67||0.16||319%||0.78||(14%)|
|Comprehensive income (loss)||20,331||(84,466)||n/a||23,638||(103,495)||n/a||(106,022)||n/a|
|Per share – basic ($)||0.12||(0.54)||n/a||0.14||(0.72)||n/a||(0.96)||n/a|
|Per share – diluted ($)||0.12||(0.54)||n/a||0.14||(0.72)||n/a||(0.96)||n/a|
|Capital expenditures, net, including acquisitions||58,638||22,394||162%||107,930||44,693||141%||217,342||(50%)|
|Adjusted capital expenditures, net, including acquisitions (1)(2)||59,691||22,867||161%||110,224||48,947||125%||243,108||(55%)|
|Working capital surplus, excluding non-cash items and current portion of bank debt(1)||64,899||46,310||40%|
|Current and long-term bank debt||250,638||248,228||1%|
|Common shares, end of period (000s)||174,359||159,266||9%|
|Petroleum and natural gas production, before royalties (boepd)|
|Petroleum and natural gas sales, before royalties (boepd)|
|Realized contractual sales, before royalties (boepd)|
|Ecuador (tariff oil) (2)||1,631||2,078||(22%)||1,704||2,117||(20%)||1,927||(12%)|
|Operating netbacks ($/boe) (1)|
|Esperanza (natural gas)||26.35||24.03||10%||27.15||23.27||17%||20.62||32%|
|VIM-5 (natural gas)||21.99||20.78||6%||23.68||20.78||14%||–||n/a|
|Ecuador (tariff oil) (2)||38.54||38.54||–||38.54||38.54||–||38.54||–|
|(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.|
The Corporation’s has filed its audited consolidated financial statements and related Management’s Discussion and Analysis and Annual Information Form as of and for the year ended December 31, 2016 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, Ecuador and Mexico. The Corporation’s common stock trades on the Toronto Stock Exchange, the OTCQX in the United States of America, the Colombia Stock Exchange and the Mexico Stock Exchange under ticker symbols CNE, CNNEF, CNEC and CNEN respectively.
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”, “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 and operating netback measures. Working capital is calculated as current assets less current liabilities, excluding non-cash items such as the current portion of commodity contracts, the current portion of warrants, and the current portion of any embedded derivatives asset/liability, and is used to evaluate the Corporation’s financial leverage. 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 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.
Total cash sales is defined as realized contractual gas sales and crude oil sales plus cash received for gas classified as deferred income according to IFRS.
The reserves evaluations, effective December 31, 2016, were conducted by the Corporation’s independent reserves evaluators DeGolyer and MacNaughton (“D&M”) and Petrotech Engineering Ltd. (“Petrotech”) and are in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. The reserves are provided on a Canacol working interest before royalty basis in units of barrels of oil equivalent using a forecast price deck, adjusted for quality, in US dollars. The estimated values may or may not represent the fair market value of the reserve estimates.
“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;
“deemed volumes” means those volumes produced under a service agreement in which the Corporation does not have a direct interest, but represents reserves attributable to the Corporation as calculated using the cash flow divided by the fixed tariff price over the life of the reserves. The Corporation has a non-operated 25% equity participation interest in the Ecuador IPC for which it receives a fixed price tariff for each incremental barrel produced;
Boe Conversion – “boe” barrel of oil equivalent is derived by converting natural gas to oil in the ratio of 5.7 Mcf of natural gas to one bbl of oil. A BOE conversion ratio of 5.7 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 5.7:1, utilizing a conversion on a 5.7:1 basis may be misleading as an indication of value. In this news release, the Corporation has expressed Boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and Energy of Colombia.
F&D – Finding and development costs on a 2P (Total Proved plus Probable) basis.
With the F&D 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.
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.
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