Canacol Energy : Reports 86% Increase in 2P Reserves, Filing of Fiscal 2015 Financial Results and Annual Information Form, and Clarinete-2 ST Well Update

CALGARY, ALBERTA--(Marketwired - Sep 23, 2015) - Canacol Energy Ltd. ("Canacol" or the "Corporation") (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to report its reserves and financial results for the year ended June 30, 2015. Dollar amounts are expressed in United States dollars, except as otherwise noted.

Charle Gamba, President and CEO of the Corporation, stated: "Despite fiscal 2015 having proven to be a challenging year from a world oil price perspective, the Corporation managed to increase proved plus probable reserves and deemed volumes, grow production, refinance its debt facility to defer repayment until calendar year 2017, and reduce operating and transportation expenses to maintain as high a netback as possible. I'm also pleased to report that after some mechanical related drilling problems, the Clarinete-2 ST appraisal well has encountered 127 feet of net gas pay within the main Cienaga de Oro reservoir target, confirming a significant gas discovery at Clarinete.

"With respect to reserves, the Corporation increased proved plus probable reserves and deemed volumes at June 30, 2015 to 79.9 million barrels of oil equivalent ('boe') with a pre-tax NPV-10 value of $1.23 billion, an 86% increase in reserves and a 38% increase in value year over year. The Corporation now has the longest reserve-life index of any producer in Colombia.

"The Corporation grew average production for fiscal 2015 to 11,504 boe per day ('boepd'), a 9% increase year over year, despite a low level of capital investment related to drilling. Production for fiscal Q4 2015 was 9,961 boepd, of which 57% of production came from our Esperanza and Ecuador properties, with the pricing of both unaffected by world oil prices.

"In April of 2015 a newly syndicated $200 million BNP Senior Secured Term Loan replaced the CS Senior Secured Term Loan with less restrictive covenants and the first of eight term out payments commencing on December 31, 2017, effectively freeing up funds which can be used to invest in growing our gas production business. At June 30, 2015, the Corporation had a working capital surplus of $62.9 million (with $45.8 million of that being in unrestricted cash), and a further $61.8 million in restricted cash. In addition, at June 30, 2015, the Corporation had available an additional $25 million in committed Apollo Senior Notes that it can draw down at any time up to April 2016 at the sole discretion of the Corporation, subject to certain conditions.

"For fiscal year 2015, the Corporation reduced operating and transportation expenses by 22% to $13.84/boe compared to fiscal year 2014. Operating and transportation expense for fiscal Q4 2015 was $9.18/boe.

"On the financing front, in early September 2015 Canacol announced a strategic private placement with Cavengas Holding S.R.L. for C$79 million (approximately US$60 million) which will allow for both a partial debt repayment and the ability to maintain a flexible capital expenditure program as the Corporation continues to focus on developing its substantial natural gas portfolio.

"For the remainder of calendar 2015, the Corporation remains focused on two projects: adding an additional 65 million standard cubic feet ('MMscf') (11,400 boepd) of gas production in December 2015 via new sales contracts, and appraising the Clarinete gas discovery through the drilling of two appraisal wells so that the discovery can be brought into commercial production. The first appraisal well, Clarinete-2 ST, has encountered 127 feet of net gas pay, an amount of pay similar to that encountered in the Clarinete-1 discovery well which tested 44 MMscf per day ('MMscfpd') from two intervals, and thus confirming a substantial gas discovery on our 100% operated VIM-5 block. The Corporation is currently preparing to start production testing of the well.

"In summary, during fiscal 2015, the Corporation managed to increase reserves, grow production, deferred debt repayments to free up funds to reinvest in gas production growth, and reduced operating and transportation expenses to maximize netbacks, placing the Corporation on a strong footing for fiscal 2016. With an anticipated exit rate for calendar 2015 of more than 20,000 boepd, the majority being natural gas and Ecuador tariff oil production, and with a substantial development shaping up at our Clarinete gas discovery via the results of our appraisal drilling program, calendar 2016 should prove to be an interesting year indeed for Canacol as we continue to deleverage from oil in a likely scenario of depressed long term world oil prices."

Outlook

Calendar 2015 has been a transformational year for Canacol on both a financial and operational front.

Operationally, like many of its peers, Canacol entered calendar 2015 heavily levered to world oil prices. By the quarter ended June 30, 2015, by continuing to market its growing gas production base and its success in Ecuador, the Corporation's revenues are now 57% insensitive to world oil prices. For the remainder of calendar 2015 and into 2016, Canacol is squarely focused on being in a position to further monetize its significant gas position in Colombia's Lower Magdalena basin. To this end:

• On July 13, 2015, the Corporation announced that the Autoridad Nacional de Licencias Ambientales has approved the environmental permit enabling Promigas S.A. E.S.P. to commence construction necessary to increase capacity of the existing Jobo to Cartagena natural gas pipeline. This expansion allows Canacol to increase net gas production by an additional 65 MMscfpd (11,400 boepd) commencing December 1, 2015. Upon completion of this pipeline expansion, anticipated to be prior to December 1, 2015, the Corporation's net natural gas shipping capacity will increase to approximately 83 MMscfpd (14,500 boepd).
• In June of 2015, the Corporation awarded a contract to Promisol 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 km flow line, which is scheduled to be completed by the end of September 2015.
• As announced on August 10, 2015, the Corporation had begun the drilling of Clarinete-2, a 1.5 km step out from the original Clarinete-1 discovery well. After sidetracking the Clarinete-2 well in a shallow shale due to mechanical problems while drilling, the Clarinete-2 ST well has successfully reached total depth and has encountered 127 feet of net gas pay in two gas bearing zones.

Canacol is continuing its successful focus on cost reductions on its LLA-23 light oil block, where operating costs have been reduced from $19.17/bbl to $12.59/bbl in the three months ended June 30, 2015, and are expected to fall further as a result of the recently completed centralized processing facilities installed at LLA-23.

Given the relative volatility of world oil prices at the present time, the Corporation will closely monitor changes thereto and has the flexibility to adjust its capital spending accordingly, however, no oil exploration drilling is currently planned for calendar 2015, and no further material capital expenditures are currently planned on other Colombian oil blocks.

In light of the above mentioned natural gas projects continuing forward on their originally anticipated timelines, and the expectation of entering a new 2016 calendar year with an additional 65 MMscfpd of gas production (11,400 boepd), Canacol is pleased to confirm the changing of its fiscal year end to December 31.

Highlights for Fiscal Q4 2015 and Fiscal 2015

(in thousands of United States dollars, except as otherwise noted; production is stated as working-interest before royalties)

Financial, operating and reserves highlights of the Corporation include:

• Total proved reserves and deemed volumes increased 62% to 51.5 million boe at June 30, 2015 compared to 31.8 million boe at June 30, 2014, and total proved plus probable reserves and deemed volumes increased 86% to 79.9 million boe at June 30, 2015 compared to 43.0 million boe at June 30, 2014.
• Total pre-tax NPV-10 proved reserve and deemed volume value increased 49% to $810.2 million at June 30, 2015 compared to $542.4 million at June 30, 2014, and total pre-tax NPV-10 proved plus probable reserve and deemed volume value increased 38% to $1.23 billion at June 30, 2015 compared to $886.7 million at June 30, 2014.
• Average sales volumes decreased 17% to 10,256 boepd for fiscal Q4 2015 compared to 12,323 boepd for the comparable period. Average sales volume increased 10% to 11,522 boepd for fiscal 2015 compared to 10,470 boepd for the comparable period.
• Average daily production volumes decreased 18% to 9,961 boepd for fiscal Q4 2014 compared to 12,212 boepd for the comparable period. Average daily production volumes increased 9% to 11,504 boepd for fiscal 2015 compared to 10,577 boepd for the comparable period.
• Petroleum and natural gas revenues for fiscal Q4 2015 decreased 56% to $27.3 million compared to $61.7 million for the comparable period. Petroleum and natural gas revenues for fiscal 2015 decreased 28% to $149.0 million compared to $207.8 million for the comparable period. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador Incremental Production Contract (the "Ecuador IPC") (see full discussion in MD&A), for fiscal Q4 2015 decreased 51% to $33.9 million compared to $69.0 million for the comparable period. Adjusted petroleum and natural gas revenues for fiscal 2015 decreased 23% to $177.9 million compared to $230.9 million for the comparable period.
• Average corporate operating netback for fiscal Q4 2015 decreased 40% to $26.68/boe compared to $44.70/boe for the comparable period. Average corporate operating netback for fiscal 2015 decreased 33% to $28.05/boe compared to $41.85/boe for the comparable period. Operating corporate netback is inclusive of results from the Ecuador IPC.
• Adjusted funds from operations for fiscal Q4 2015 decreased 32% to $16.4 million compared to $24.0 million for the comparable period. Adjusted funds from operations for fiscal 2015 decreased 12% to $87.4 million compared to $98.9 million for the comparable period.
• The Corporation recorded a net loss of $58.5 million for fiscal Q4 2015 compared to net loss of $2.1 million for the comparable period. Driving the fiscal Q4 2015 net loss is a $44.7 million non-cash impairment charge on the Rancho Hermoso, Capella, Santa Isabel and VMM-2 fields, a $29.7 million non-cash deferred tax expense impact as a result of the devaluation of the Colombian peso versus the United States dollar, and a non-cash depletion and depreciation expense of $12.7 million. The impairment charge on the fields related to reserve and deemed volume write-downs at June 30, 2015 and does not affect any of the Corporation's other oil and gas properties, on which there were no impairment charges. The Corporation recorded a net loss of $106 million for fiscal 2015 compared to net income of $9.9 million for the comparable period. Driving the fiscal 2015 net loss is a $72.1 million non-cash impairment charge on the Rancho Hermoso, Capella, Santa Isabel and VMM-2 fields, a $43.2 million non-cash deferred tax expense impact as a result of the devaluation of the Colombian peso versus the United States dollar, and a non-cash depletion and depreciation expense of $61.3 million. The impairment charge on the fields related to reserve and deemed volume write-downs at June 30, 2015 and does not affect any of the Corporation's other oil and gas properties, on which there were no impairment charges.
• Capital expenditures for fiscal Q4 2015 and fiscal 2015 were $28.9 million and $217.3 million, respectively, while adjusted capital expenditures, inclusive of amounts related to the Ecuador IPC, were $30.9 million and $243.1 million, respectively. Included in fiscal 2015 capital expenditures were property acquisition costs of $75.6 million related to the acquisition of the VIM-5 and VIM-19 E&P contracts and increased working interest in the Corporation's COR-4 and COR-12 blocks.
• At June 30, 2015, the Corporation had $45.8 million in cash and cash equivalents and $61.8 million in restricted cash.

Clarinete-2 ST Results (VIM-5 E&P Contract, 100% operated by CNE Oil & Gas SAS)

The Clarinete-2 well was spud on August 2, 2015, and had to be sidetracked on August 31, 2015 after becoming mechanically stuck in the shallow Porquero shales at a depth of approximately 4,300 feet, not having reached the primary Cienaga de Oro reservoir target at 5,967 feet. The Clarinete-2 ST reached total depth of 7,842 feet on September 16, 2015. The well encountered 127 feet of total net potential gas pay with an average porosity of 23% within the same two main reservoir intervals of the Cienaga de Oro sandstone that tested a combined rate of approximately 44 MMscfpd in the Clarinete-1 discovery well. The Corporation is currently casing the well and plans to conduct production testing over the next week. Upon completion of the production testing of the Clarinete-2 ST well, the rig will be mobilized to drill the Oboe-1 well located approximately three kilometers to the north of the Clarinete-1 discovery well. Oboe-1 is anticipated to spud in late October 2015 and will take approximately five to six weeks to drill and test.

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 June 30, 2015 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 common stock trades on the Toronto Stock Exchange, the OTCQX in the United States of America, and the Colombia Stock Exchange under ticker symbols CNE, CNNEF, and CNEC, 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.

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.

Estimates of reserves and related future net revenue are effective June 30, 2015, were conducted by the Corporation's independent qualified reserves evaluators, DeGolyer and MacNaughton Canada Ltd. and Petrotech Engineering Ltd., and were prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. The reserves are provided on a net before royalty basis in units of thousands of barrels of oil equivalent using a forecast price deck for gas and oil, adjusted for crude quality, in US dollars. The estimated net present value of future net revenues attributable to reserves do not represent fair market value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

"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" are defined as 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 an incremental production contract on the Libertador/Atacapi fields in Ecuador for which it receives a fixed price tariff for each incremental barrel produced.