Canacol Energy Ltd. Reports Filing of December 31, 2015 Financial Results and Annual Information Form

CALGARY, ALBERTA--(Marketwired - March 28, 2016) - Canacol Energy Ltd. ("Canacol" or the "Corporation") (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to report its reserves and financial results for the six months ended December 31, 2015. Dollar amounts are expressed in United States dollars, except as otherwise noted. 

Charle Gamba, President and CEO of the Corporation, commented: "In July 2015 we announced the changing our fiscal year end to December 31 with the intention of aligning our year end with that of our peer group, and more importantly to reflect the 2016 evolution of Canacol as we become a significant natural gas producer in Colombia. Today we are pleased to report the results of our first December 31 year end. 

"During the prolonged downturn in global commodity prices, particularly the relentless drop in oil price during 2015 which continues to this day, Canacol's management team has focused on growing our high net back gas business in Colombia. Canacol's realized gas netback for the last quarter of 2015 was US$ 24.03 / boe, reflecting the strength of this commodity in Colombia. Our growth in the Colombian gas market during 2015 and the first quarter of 2016 to date is reflected by both the increase in gas production, which will reach 90 MMscfpd near the end of March, generating approximately $163 million in gross revenues this year, and the increase in value of the Corporation's 2P reserves which now stand at 79 MMboe, 80% of which are gas with a before tax undiscounted value of $1.3 billion or C$9.44 per share. These reserves do not include the recent Oboe-1 well, which tested at a combined rate of 66 MMscfpd.

"For the remainder of 2016, and during the current low price oil environment, the management team will focus on executing its US$ 52 million capital program which will primarily target exploration for additional gas reserves from its large portfolio of drill ready gas opportunities. The Corporation has also embarked upon the planning of a new gas pipeline project with the objective of increasing Canacol's gas sales to Colombia's Caribbean coast by an additional 100 MMscfpd in 2018. Meanwhile, the company continues to maintain a large inventory of light oil drill ready production and exploration opportunities which could be rapidly executed should global oil prices recover to a reasonable level to justify capital investment."

During this timeframe the Corporation has had many operational and financial accomplishments:

• The drilling of the recent Clarinete-2ST well and its combined test results of over 30 MMscf/d in October, 2015.
• The drilling of Oboe-1 and its combined test results of over 66 MMscf/d (11,579 boe/d), with the associated reserves not currently booked,
• The completion of the upgrade, on schedule, of the Canacol owned Jobo gas processing plant to now process 80 MMscf/d of gas.
• The current commissioning and testing of the completed Promisol Jobo gas plant to process an additional 100 mmcf/d of gas, bringing Canacol's total gas processing capability to 180 MMscf/d.
• The tying-in of both Clarinete-1 and Clarinete-2ST to the Jobo plant via a 12 km 6" flow-line, such that both are now capable of delivering gas.
• The strategic investment with Cavengas for C$79 million in September, 2015, which allowed for both a partial repayment of debt and the ability to maintain a flexible capital expenditure program as the corporation continues to focus on developing its substantial natural gas portfolio.

Additionally, Canacol has been actively reducing its costs in 2016:

• A planned 2016 Capex budget of $52 million, down 37% from the $82 million spent in calendar 2015.
• Continued reductions on LLA-23 costs, to post six months ended December 31, 2015, operating costs of $8.74/boe, almost half of the $15.90/boe for the twelve months ended June, 2015.
• Aggressive G&A reductions, including staff reductions.

The Corporation's recently released December 31, 2015 NI 51-101 compliant reserves reports showed marked increases during 2015 as a result of gas drilling, and allowed the Corporation to post some of the best metrics in the industry. Highlights included:

• Proven developed producing ("PDP") reserves increased by 110% since June 30, 2015, to total 28.4 MMboe at December 31, 2015.
• Proved plus probable ("2P") reserves totaled 79.2 MMboe at December 31, 2015, with a before tax value discounted at 10% of $1.3 billion, being C$9.44 per share.
• Achieved a 2P reserve replacement of 1,013%, based on calendar 2015 gross reserve additions of 30.3 MMboe, being more than 10 times of those produced in the same period.
• Achieved a 1P reserve replacement of 656% based on calendar 2015 gross proven reserve additions of 19.7 MMboe.
• Achieved 2P finding and development costs ("F&D") of $1.81/boe for its gas assets and $2.85/boe as a corporate total for calendar 2015.
• Recorded 2P finding, development and acquisition costs ("FD&A") of $2.44/boe for its gas assets and $3.38/boe as a corporate total for calendar 2015.
• Recorded a 2P reserves life index ("RLI") of 24 years based on 2015 production, and a 10 year RLI based on expected future gas production of 90 MMscfpd upon the completion of the Promigas pipeline expansion (1P RLI being 16 years and 7 years, respectively).

Looking forward to the remainder of 2016, management shall remain focused on:

1) Disciplined capital spending with anticipated capex of $52 million predicated on a WTI price of $30/bbl for the first half of 2016, and $35/bbl for the second half of 2016,

2) Continuing to grow Canacol's Colombian gas reserves and production base through its exploration program targeting 100 BCF (18 MMboe) of unrisked reserve potential, which has commenced with the recently announced success at Oboe-1 which tested at a combined rate of 66 MMscfpd,

3) Initiating the planning and construction of a new gas pipeline which will send 100 MMscpfd of new Canacol gas production to the Caribbean coast of Colombia in 2018, and

4) Maintaining Canacol's large inventory of light oil drill ready production and exploration opportunities which could be rapidly executed should global oil prices recover to a reasonable level and justify capital investment.

Highlights for the Three and Six Months Ended December 31, 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:

• Proven developed producing ("PDP") reserves and deemed volumes increased 110% to 28.4 million boe at December 31, 2015 compared to 13.5 million boe at June 30, 2015. Total proved ("1P") reserves and deemed volumes increased 3% to 53 million boe at December 31, 2015 compared to 51.5 million boe at June 30, 2015. 
• Total pre-tax NPV-10 PDP reserve and deemed volume value increased 99% to $570.5 million at December 31, 2015 compared to $286.7 million at June 30, 2015, and total pre-tax NPV-10 1P reserve and deemed volume value increased 16% to $936.4 million at December 31, 2015 compared to $810.2 million at June 30, 2015.
• Average sales volumes decreased 21% to 9,010 boepd for the three months ended December 31, 2015 compared to 11,403 boepd for the same period in 2014. Average sales volume decreased 14% to 9,869 boepd for the six months ended December 31, 2015 compared to 11,522 boepd for the twelve months ended June 30, 2015.
• Average daily production volumes decreased 23% to 9,064 boepd for the three months ended December 31, 2015 compared to 11,822 boepd for the same period in 2014. Average daily production volumes decreased 15% to 9,760 boepd for six months ended December 31, 2015 compared to 11,504 boepd for the twelve months ended June 30, 2015. The overall decrease in production volumes in the three months ended December 31, 2015 compared to the same period in 2014 is primarily due to production declines from LLA-23 and Rancho Hermoso and other, as well as decreased gas production due to pipeline capacity being down for further construction, offset by increases in tariff oil production from Ecuador. LLA-23 oil production decreased in the three months ended December 31, 2015 compared to the three months ended September 30, 2015 as the prior quarter included flush production associated with the workovers performed during the quarter.
• Petroleum and natural gas revenues for the three months ended December 31, 2015 decreased 55% to $16.5 million compared to $36.4 million for the same period in 2014. Petroleum and natural gas revenues for the six months ended December 31, 2015 decreased 74% to $38.4 million compared to $149 million for the twelve months ended June 30, 2015. 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 the three months ended December 31, 2015 decreased 45% to $24 million compared to $43.9 million for the same period in 2014. Adjusted petroleum and natural gas revenues for the six months ended December 31, 2015 decreased 70% to $53.9 million compared to $177.9 million for the twelve months ended June 30, 2015.
• Average corporate operating netback for the three months ended December 31, 2015 decreased 13% to $21.96/boe compared to $25.14/boe for the same period in 2014. Average corporate operating netback for the six months ended December 31, 2015 decreased 20% to $22.38/boe compared to $28.05/boe for the twelve months ended June 30, 2015. Operating corporate netback is inclusive of results from the Ecuador IPC. 
• Adjusted funds from operations for the three months ended December 31, 2015 decreased 62% to $8.5 million compared to $23 million for the same period in 2014. Adjusted funds from operations for the six months ended December 31, 2015 decreased 73% to $23.7 million compared to $87.4 million for the twelve months ended June 30, 2015. 
• The Corporation recorded a comprehensive loss of $84.5 million for the three months ended December 31, 2015 compared to a comprehensive loss of $46 million for the same period in 2014. The comprehensive loss for the three months ended December 31, 2015 was mainly driven by non-cash items that did not affect the core business of the Corporation. Most significantly, the non-cash impairment expense on development and production assets of $44.6 million, the non-cash depletion and depreciation expense of $13.9 million, the non-cash deferred income tax expense of $8.8 million, and the non-cash exploration expense of $8.7 million. The Corporation recorded a comprehensive loss of $103.5 million for the six months ended December 31, 2015 compared to a comprehensive loss of $106 million for the twelve months ended June 30, 2015. The comprehensive loss for the six months ended December 31, 2015 was mainly driven by non-cash items that did not affect the core business of the Corporation. Most significantly, the non-cash impairment expense on development and production assets of $44.6 million, the non-cash depletion and depreciation expense of $26.5 million, the non-cash deferred income tax expense of $12.3 million, and the non-cash exploration expense of $8.7 million. 
• Capital expenditures for the three and six months ended December 31, 2015 were $22.4 million and $44.7 million, respectively, while adjusted capital expenditures, inclusive of amounts related to the Ecuador IPC, were $22.9 million and $48.9 million, respectively. Capital expenditures for the three and six months ended December 31, 2015 included non-cash decommissioning costs of $7.9 million and $10.7 million, respectively, and non-cash capitalized stock-based compensation of $0.5 million and $0.9 million, respectively.
• At December 31, 2015, the Corporation had $43.3 million in cash and $61.7 million in restricted cash. 

Financial		Three months ended December 31, 2015		Three months ended December 31, 2014		Change		Six months ended December 31, 2015		Twelve months ended June 30, 2015		Change
Petroleum and natural gas revenues, net of royalties		16,472		36,404		(55	%)	38,430		149,047		(74	%)
Adjusted petroleum and natural gas revenues, net of royalties (2)		23,953		43,878		(45	%)	53,852		177,937		(70	%)
Cash provided by operating activities		4,974		31,743		(84	%)	19,276		64,445		(70	%)
	Per share - basic ($)	0.03		0.29		(90	%)	0.14		0.58		(76	%)
	Per share - diluted ($)	0.03		0.29		(90	%)	0.13		0.58		(78	%)
Adjusted funds from operations (1) (2)		8,473		22,952		(62	%)	23,690		87,395		(73	%)
	Per share - basic ($)	0.05		0.21		(76	%)	0.17		0.79		(78	%)
	Per share - diluted ($)	0.05		0.21		(76	%)	0.16		0.78		(79	%)
Comprehensive loss		(84,466	)	(45,970	)	84	%	(103,495	)	(106,022	)	(2	%)
	Per share - basic ($)	(0.54	)	(0.43	)	26	%	(0.72	)	(0.96	)	(25	%)
	Per share - diluted ($)	(0.54	)	(0.43	)	26	%	(0.72	)	(0.96	)	(25	%)
Capital expenditures, net, including acquisitions		22,394		78,403		(71	%)	44,693		217,342		(79	%)
Adjusted capital expenditures, net, including acquisitions (1)(2)		22,867		87,228		(74	%)	48,947		243,108		(80	%)
								December 31, 2015		June 30, 2015		Change
Cash								43,257		45,765		(5	%)
Restricted cash								61,721		61,772		-
Working capital surplus, excluding non-cash items (1)								46,310		62,883		(26	%)
Long-term bank debt								248,228		267,023		(7	%)
Total assets								668,349		669,742		-
Common shares, end of period (000s)								159,266		126,434		26	%
Operating		Three months ended December 31, 2015		Three months ended December 31, 2014		Change		Six months ended December 31, 2015		Twelve months ended June 30, 2015		Change
Petroleum and natural gas production, before royalties (boepd)
	Petroleum (3)	5,523		8,586		(36	%)	6,253		7,999		(22	%)
	Natural gas	3,541		3,236		9	%	3,507		3,505		-
	Total (2)	9,064		11,822		(23	%)	9,760		11,504		(15	%)
Petroleum and natural gas sales, before royalties (boepd)
	Petroleum (3)	5,468		8,187		(33	%)	6,370		8,010		(20	%)
	Natural gas	3,542		3,216		10	%	3,499		3,512		-
	Total (2)	9,010		11,403		(21	%)	9,869		11,522		(14	%)
Realized sales prices ($/boe)
	LLA-23 (oil)	28.56		58.62		(51	%)	31.89		59.91		(47	%)
	Esperanza (natural gas)	28.77		25.12		15	%	27.67		25.04		11	%
	Clarinete (natural gas)	31.37		-		n/a		31.37		-		n/a
	Ecuador (tariff oil) (2)	38.54		38.54		-		38.54		38.54		-
	Total (2)	31.20		45.55		(32	%)	32.18		45.76		(30	%)
Operating netbacks ($/boe) (1)
	LLA-23 (oil)	12.02		30.78		(61	%)	16.74		34.91		(52	%)
	Esperanza (natural gas)	24.03		20.04		20	%	23.27		20.62		13	%
	Clarinete (natural gas)	20.78		-		n/a		20.78		-		n/a
	Ecuador (tariff oil) (2)	38.54		38.54		-		38.54		38.54		-
	Total (2)	21.96		25.14		(13	%)	22.38		28.05		(20	%)

(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.

The Corporation has filed its audited consolidated financial statements and related Management's Discussion and Analysis and Annual Information Form as of and for the six months ended December 31, 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.

The reserves evaluations, effective December 31, 2015, 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;

"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;

"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.

1P Reserves replacement ratio: Ratio of reserve additions to production, as reported in financial statements during the fiscal year ended December 31, excluding acquisitions and dispositions on a proven basis.

2P Reserves replacement ratio: Ratio of reserve additions to production, as reported in financial statements during the fiscal year ended December 31, excluding acquisitions and dispositions on a proven + probable basis.

With the finding and development 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.