Canacol Energy Ltd. Provides Production and Drilling Update and Announces Light Oil Discovery in Ecuador
CALGARY, ALBERTA--(Marketwired - Aug. 10, 2015) - Canacol Energy Ltd. ("Canacol" or the "Corporation") (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to provide the following update concerning its production and drilling operations in Colombia and Ecuador.
Average net production before royalty for the month of July 2015 was 10,973 barrels of oil equivalent per day ("boepd"), which consisted of 7,175 barrels of oil per day ("bopd") and 22 million cubic standard feet of gas per day ("mmscfpd") (3,798 boepd) of natural gas. Average net production before royalty for the period August 1, 2015 to August 9, 2015 was 11,492 boepd, which consisted of 7,998 bopd and 20 mmscfpd (3,494 boepd) of natural gas. Production in July and August 2015 to date represent significant increases over June 2015 despite planned, scheduled maintenance at one of the Corporation's gas off takers facilities which negatively impacted the amount of gas shipped, however, the scheduled maintenance is now completed. As previously reported, average net production before royalty for the period April 1, 2015 through June 30, 2015 averaged 9,970 boepd which consisted of 5,515 bopd and 25 mmscfpd (4,455 boepd) of natural gas.
Charle Gamba, President and CEO of Canacol, commented, "Canacol remains focused on three objectives for calendar 2015: to ensure that the project to add 65 mmscfpd of new natural gas production remains on track to deliver for December 2015, to continue to invest in and increase tariff oil production in Ecuador where netbacks are not sensitive to global oil prices, and to lower operating cost and execute low cost well workovers to maintain light oil production on the LLA23 block with the highest possible margin. In this cycle of low global oil prices, the strategy that we embarked on three years ago to diversify our production base to include Colombian natural gas production and Ecuador fixed tariff production, both insensitive to global oil prices, is yielding very obvious benefits. In the meantime, we remain well capitalized with approximately US$ 45 million of current unrestricted cash, and an additional US$ 25 million of undrawn debt."
The Corporation anticipates achieving the higher end of its calendar 2015 net before royalty production guidance of between 10,000 to 12,000 boepd. The Corporation is also on schedule to add an additional 65 mmscfpd (11,400 boepd) of new natural gas production in December 2015 to its existing production via its new, US dollar denominated, long term take or pay gas sales contracts not tied to global oil price. The Corporation anticipates exiting calendar 2015 with more than 20,000 boepd of net production before royalty. The Corporation anticipates that approximately 75% of calendar exit production will consist of natural gas from Colombia and tariff light oil from Ecuador, both not tied to global oil prices.
Approximately 55% of the Corporation's current total net production before royalty is not tied to global oil price, this being natural gas production from Colombia and tariff light oil production from Ecuador. The Corporation receives an average blended netback of approximately US$ 23.00 / barrel of oil equivalent for its Colombia natural gas production (average 4,455 boepd for the period April 1, 2015 to June 30, 2015, and 3,798 boepd for the month of July), and a flat tariff netback of US$ 38.56 / barrel for its Ecuadorian production (average 1,757 bopd for the period April 1, 2015 to June 30, 2015, and average production of 2,174 bopd for the month of July 2015). All of the Corporation's Colombian oil production is tied to global oil prices. The Corporation received an average sales price of approximately US$ 50.08 / barrel for its Colombian oil production for the period April 1, 2015 to June 30, 2015. The majority of its Colombian oil production came from its operated LLA23 block, which averaged 3,472 bopd net before royalty for the period April 1, 2015 to June 30, 2015, 4,262 bopd net before royalty for the month of July 2015, and 4,888 bopd net before royalty for the period August 1, 2015 to August 9, 2015. The increase in net oil production from the LLA23 block over the past 5 months reflect the positive results of the ongoing workover program in the Labrador and Pantro fields. The workover program, which has added approximately 1,400 bopd of net production before royalty over a 5 month period, has cost approximately US$ 5 million to execute, with additional workovers planned for the months of August and September 2015 in order to continue to maintain low cost production. As recently stated, the Corporation has reduced its operating costs in the LLA23 block via a series of infrastructure projects to approximately US$ 11 / barrel.
Colombian Gas Project
Canacol is involved in three construction projects that will allow the Corporation to increase gas production via the sale of gas to off takers located in Cartagena and Barranquilla under long term US dollar denominated take or pay contracts that are not tied to global oil prices. Upon completion of these projects, anticipated to be prior to December 1, 2015, the Corporation's net natural gas production before royalty will increase from current levels of 20 to 30 mmscfpd to approximately 83 mmscfpd (14,500 boepd). These projects consist of an expansion of the Promigas S.A. E.S.P. natural gas pipeline between Jobo and Cartagena, an expansion of the gas processing facilities at Jobo to increase treatment capacity from current capacity of 50 mmscfpd to 140 mmscfpd, and the completion of the tie-in of the Clarinete 1 gas well into the Jobo gas processing facility.
In July, Canacol announced that the Autoridad Nacional de Licencias Ambientales approved the environmental permit enabling Promigas to commence construction necessary to increase capacity of the existing Jobo to Cartagena natural gas pipeline, with actual construction having commenced the second week of July 2015. The Corporation has also commenced construction to expand the capacity of Canacol's existing gas processing facility located at Jobo from the current capacity of 50 mmscfpd to 140 mmscfpd. This expansion is anticipated to be completed in early November 2015. The Corporation is also completing the tie in of the Clarinete 1 well into the Jobo processing facility via a 12 kilometer flow line, which is scheduled to be completed in September 2015. The productive capacity of Canacol's existing gas wells, located in the Nelson, Palmer, and Clarinete fields, is approximately 120 mmscfpd (21,000 boepd), more than sufficient to deliver the total 83 mmscfpd (14,500 boepd) of gas required starting December 1, 2015.
The Corporation and its joint venture operating partners have completed the drilling and testing of the successful Secoya Oeste - A001 exploration well located adjacent to the producing Libertador and Atacapi light oil fields in the Oriente Basin of Ecuador. The Corporation holds a non-operated working interest of 25% in the Ecuadorian consortium which includes a risked service contract governing light oil production from the Libertador and Atacapi light oil fields. The Secoya Oeste - A001 exploration well was spud in early June 2015 targeting the T, U, and basal Tena sandstone reservoirs which produce in the adjacent Libertador and Atacapi oil fields. The well encountered 33 feet of net oil pay within these reservoirs. The Lower U sandstone reservoir tested at an average gross rate of 972 bopd (243 bopd net) of 27 degrees API oil with a 10% water cut over the course of a 50 hour test using a jet pump. The Upper U sandstone tested at an average gross rate of 326 bopd (82 bopd net) of 29 degrees API oil with 8% water cut over the course of a 53 hour test using a jet pump. The consortium plans to commingle the two intervals and bring the well on permanent production shortly, and is using the well results to plan the drilling of potential follow up appraisal and development wells. The consortium operates these two fields, and the new Secoya Oeste - A001 discovery well, under a risked service contract whereby the state oil company pays the consortium a flat tariff of US$ 38.56 / barrel of incremental production not tied to global oil prices. As the state oil company pays for all operating costs, the US$ 38.56 / barrel tariff is the netback the consortium receives for incremental production.
The Corporation commenced the drilling of the Clarinete 2 appraisal well at its Clarinete gas discovery located on the VIM5 block in the Lower Magdalena Valley on August 1, 2015. The Corporation has a 100% operated working interest in the VIM5 block. The well is located approximately 1.5 kilometers ("kms") to the west of the Clarinete 1 discovery well, and is targeting the same two productive sandstone reservoirs that tested approximately 42 mmscfpd of natural gas from the Tertiary Cienaga de Oro Formation in the Clarinete 1 discovery well. The well is anticipated to take approximately five weeks to drill, complete, and production test. Upon the completion of testing operations at Clarinete 2 the drilling rig will be mobilized to drill Oboe 1. Oboe 1 is located approximately 3 kms to the north of the Clarinete 1 discovery well, and is targeting the same two productive sandstone reservoirs tested at the Clarinete 1 discovery. Oboe 1 is also anticipated to take approximately five weeks to drill, complete, and test. As per a third party reserves report effective February 2015, the Corporation has booked 150 billion cubic feet ("bcf") of net recoverable 2P reserves to the Clarinete natural gas discovery based on the Clarinete 1 well.
The Corporation will provide updates when relevant information becomes available.
Canacol is an exploration and production company with operations focused in Colombia and Ecuador. 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.
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. 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.
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.
Data obtained from the initial testing results at the well identified in this press release, including barrels of oil produced and levels of water-cut, should be considered to be preliminary until a further and detailed analysis or interpretation has been done on such data. The well test results obtained and disclosed in this press release are not necessarily indicative of long-term performance or of ultimate recovery. The reader is cautioned not to unduly rely on such results as such results may not be indicative of future performance of the well or of expected production results for the Corporation in the future.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have two risk components, the chance of discovery and the chance of development. There is no certainty that the Prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Application of any geological and economic chance factor does not equate prospective resources to contingent resources or reserves. Low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. Best estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. High estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Mean estimate is the arithmetic average from the probabilistic assessment.
Although the Corporation has identified prospective resources, there are numerous uncertainties inherent in estimating oil and gas resources, including many factors beyond the Corporation's control and no assurance can be given that the indicated level of resources or recovery of hydrocarbons will be realized. In general, estimates of recoverable resources are based upon a number of factors and assumptions made as of the date on which the resource estimates were determined, such as geological and engineering estimates which have inherent uncertainties and the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. There are several significant negative factors relating to the prospective resource estimate which include (i) structural events that are well defined seismically and are low risk, however, reservoir quality, seal, hydrocarbon migration and associated hydrocarbon column estimates are more at risk than the former, (ii) well costs are very high due to the exploratory nature of the initial group of wells, (iii) due to limited infrastructure proximate to the prospects, gas discoveries may be stranded for some time until infrastructure is in place, which may take some time due to the remoteness of the prospects and costs associated with same, and (iv) other factors which are not within the control of the Corporation.
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Canacol Energy Ltd.