Canacol Energy Ltd. Reports a 41% Increase in Gas Sales and 62% Increase in Funds from Operations for Fiscal 2018


CALGARY, Alberta, March 21, 2019 (GLOBE NEWSWIRE) -- 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 and year ended December 31, 2018.  Dollar amounts are expressed in United States dollars, except as otherwise noted.

Charle Gamba, President and CEO of the Corporation, commented:  “Q4 2018 was another successful quarter for Canacol as we increased the Corporation’s realized contractual gas sales by 40% to 119.3 MMscfpd, up from 85.2 MMscfpd during the same period in 2017.  Additionally, our average gas sales price (net of transportation expenses) remained strong at $4.95/Mcf for Q4 2018, which is higher than Q3 2018 ($4.80/Mcf) and our prior guidance ($4.75/Mcf), and we also achieved a strong natural gas netback of $3.92/Mcf for Q4 2018, which is a margin in excess of 79%.  Our strong realized contractual gas sales and natural gas netback during Q4 2018 generated $28.7 million of funds from operations (compared to $16.6 million, a 73% increase from Q4 2017) despite a 73% decrease in Colombia oil production due to the sale of most of our conventional oil assets.

For 2019, management remains focused on 1) completing the expansion of the Jobo gas processing facility during the first quarter, which will lift gas treatment capacity from current levels of 200 MMscfpd to 330 MMscfpd in advance of the completion of the Promigas gas pipeline expansion scheduled to be completed by June 1, 2019, which will lift gas sales to approximately 215 MMscfpd from current levels of approximately 130 MMscfpd; 2) the drilling of eight exploration, appraisal and development wells in a continuous program targeting a 3P reserves replacement ratio of over 200%; and 3) execution of a definitive agreement to construct a new gas pipeline from Jobo to either Medellin or Cartagena/Barranquilla, thereby increasing the Corporation’s gas sales by an additional 100 MMscfpd in 2021 to a total sales level greater than 300 MMscfpd.”

Highlights for the three months and year ended December 31, 2018

(Production is stated as working-interest before royalties)

Financial and operational highlights of the Corporation include:

  • As announced on February 27, 2019, the Corporation’s conventional natural gas 1P reserves increased 16% since December 31, 2017, totalling 380 billion cubic feet (“Bcf”) at December 31, 2018 (226% 1P reserves replacement ratio). The Corporation’s conventional natural gas 2P reserves increased 11% since December 31, 2017, totalling 559 Bcf at December 31, 2018 (232% reserves replacement ratio);
  • 1P finding and development cost (“F&D cost”) was $0.55/Mcf and $0.84/Mcf for the one and three year periods ending December 31, 2018, respectively;
  • 2P F&D cost was $0.32/Mcf and $0.57/Mcf for the one and three year periods ending December 31, 2018, respectively;
  • The Corporation achieved a 7x and 4.8x 1P recycle ratio for the one and three year periods ending December 31, 2018, respectively;
  • The Corporation achieved a 12x and 7.1x 2P recycle ratio for the one and three year periods ending December 31, 2018, respectively;
  • Realized contractual gas sales increased 40% and 41% to 119.3 MMscfpd and 113.3 MMscfpd for the three months and year ended December 31, 2018, respectively, compared to 85.2 MMscfpd and 80.5 MMscfpd for the same periods in 2017, respectively.  Average natural gas production volumes increased 40% and 43% to 116.6 MMscfpd and 112.1 MMscfpd for the three months and year ended December 31, 2018, respectively, compared to 83 MMscfpd and 78.5 MMscfpd for the same periods in 2017, respectively.  The increases are primarily due to an increase in gas production as a result of the additional sales relating to the completion of the Sabanas pipeline;
  • Total natural gas and crude oil revenues net of royalties and transportation expenses for the three months and year ended December 31, 2018 increased 28% and 33% to $50.7 million and $204.2 million, respectively, compared to $39.8 million and $153.7 million for same periods in 2017, respectively.  The increases are mainly attributable to the increase of natural gas production, offset by a decrease of crude oil production due to the sale of the Corporation’s oil assets;
  • Funds from operations increased 73% and 62% to $28.7 million and $104.9 million for the three months and year ended December 31, 2018, respectively, compared to $16.6 million and $64.9 million for the same periods in 2017, respectively;
  • The Corporation realized an EBITDAX of $33.4 million and $138.6 million for the three months and year ended December 31, 2018, respectively, compared to $29.9 million and $126.1 million for the same periods in 2017, respectively;
  • The Corporation recorded a net loss of $16.3 million and $21.8 million for the three months and year ended December 31, 2018, compared to a net loss of $150.3 million and $148 million for the same periods in 2017, respectively.  The net losses were driven by non-cash charges such as depletion and depreciation, stock-based compensation expense and deferred income tax expense;
  • Net capital expenditures for the three months and year ended December 31, 2018 was $37.7 million and $127.6 million, respectively. Net capital expenditures included non-cash costs of $1 million and $22.7 million for the three months and year ended December 31, 2018, respectively;
  • During the three months ended December 31, 2018, the Corporation distributed $20 million to its shareholders by way of a return of capital via the distribution of 22,598,870 of common shares of Arrow Exploration Corp. (“Arrow Shares”). Through the return of capital, the registered shareholders of Canacol received 0.127 Arrow Shares per each common share owned on the record date, October 3, 2018;
  • During the three months ended December 31, 2018, the Corporation entered into a credit agreement for an amount of $30 million with Credit Suisse (the “2018 Credit Facility”). A portion of the proceeds from the 2018 Credit Facility totaling $24.2 million was used to purchase the Jobo 2 natural gas processing facility, previously held under a finance lease agreement. The residual proceeds will contribute to the completion of the Jobo 3 natural gas plant expansion; and
  • At December 31, 2018, the Corporation had $51.6 million in cash and $4.2 million in restricted cash.

Outlook

In 2018, Canacol became Colombia’s premier independent gas explorer and producer, second only in terms of gas production to Ecopetrol, the Colombian state oil and gas company.

The Corporation achieved significant growth in production and cash flows at margins in excess of 79%, whilst its exploration and development drilling programs continued to increase reserves at industry leading F&D costs.  With over 140 exploration prospects and leads identified on its 1.1 million net acres of exploration lands containing 2.6 TCF of gross mean unrisked prospective resources (Gaffney Cline and Associates April 2018), the Corporation anticipates maintaining robust production and reserves growth for many years to come.

Growth highlights from 2018 included:

  • Q4 2018 realized contractual natural gas sales of 119.3 MMscfpd, marking the fifth consecutive quarterly increase in realized contractual natural gas sales, and a 40% increase over Q4 2017 of 85.2 MMscfpd;
  • Natural gas revenues net of transportation expenses increased 42% to $195.7 million for the year ended December 31, 2018 compared to $138.1 million for the 2017 comparable period;
  • Funds from operations increased 62% to $104.9 million for the year ended December 31, 2018 compared to $64.9 million for the 2017 comparable period;
  • Continued drilling success that has yielded a historic 80% rate (12 for 15) of commercial gas discovery from our exploration programs and 100% (8 for 8) on gas development wells;
  • A 226% 1P reserves replacement ratio, and a 232% 2P reserves replacement ratio;
  • A 16% increase in 1P reserves to 380 Bcf, and an 11% increase in 2P reserves to 559 Bcf from December 31, 2017;
  • An industry leading 1P F&D cost of $0.55/Mcf and $0.84/Mcf for the one and three year periods ending December 31, 2018, respectively,
  • An industry leading 2P F&D cost of $0.32/Mcf and $0.57/Mcf for the one and three year periods ending December 31, 2018, respectively;
  • Achieved an industry leading 7x and 4.8x 1P recycle ratio for the one and three year periods ending December 31, 2018, respectively;
  • Achieved an industry leading 12x and 7.1x 2P recycle ratio for the one and three year periods ending December 31, 2018, respectively;
  • Completed the refinancing of the Corporation’s $305 million syndicated credit facility into $320 million of senior unsecured notes with a seven-year bullet payment at maturity, effectively reducing the interest rate and achieving greater operational and financial flexibility;
  • Divestment of most of the Corporation’s conventional oil assets in Ecuador and Colombia, becoming a gas focused Colombia player with little to no competition; and
  • Confirmed exploration upside of gross unrisked mean prospective resources of 2.6 TCF in over 145 identified prospects and leads for future exploration drilling.



Financial Three months ended
 December 31,
 Year ended
December 31,
 2018 2017Change 20182017Change
          
Total natural gas and crude oil revenues, net of royalties and transportation expense 50,727 39,781 28% 204,151 153,665 33%
          
Funds from operations (1) 28,679 16,573 73% 104,914 64,896 62%
Per share  – basic ($) (1) 0.16 0.09 78% 0.59 0.37 59%
Per share  – diluted ($) (1) 0.16 0.09 78% 0.59 0.37 59%
          
Net loss and comprehensive loss (16,272) (150,343)(89%) (21,835)(148,029)(85%)
Per share – basic ($) (0.09(0.85)(89%) (0.12)(0.85)(86%)
Per share – diluted ($) (0.09)(0.85)(89%) (0.12)(0.85)(86%)
          
EBITDAX (1) 33,440 29,857 12% 138,630 126,084 10%
          
Weighted average shares outstanding – basic 177,678 175,988 1% 177,184 175,180 1%
Weighted average shares outstanding – diluted 178,977 177,881 1% 178,681 177,000 1%
          
Capital expenditures, net, including acquisitions 37,701 41,652 (9%) 127,591 121,202 5%
          
       Dec 31,
2018
Dec 31,
2017
Change
          
Cash and cash equivalents      51,632 39,071 32%
Restricted cash      4,196 27,919 (85%)
Working capital surplus      55,481 110,401 (50%)
Total debt      388,222 340,858 14%
Total assets      705,003 696,443 1%
          
Common shares, end of period (000’s)      177,462 176,109 1%
          
Operating Three months ended
December 31,
 Year ended
December 31,
 2018 2017Change 20182017Change
          
Natural gas and crude oil production, before royalties         
Natural gas (Mcfpd) 116,616 83,043 40% 112,102 78,461 43%
Colombia oil (bopd) 488 1,825 (73%) 1,546 1,909 (19%)
Ecuador tariff oil (bopd) (2)  1,183 (100%) 139 1,406 (90%)
Total (boepd) (2) 20,947 17,577 19% 21,352 17,080 25%
          
Realized contractual sales, before royalties (boepd)         
Natural gas (Mcfpd) 119,284 85,215 40% 113,261 80,513 41%
Colombia oil (bopd) 592 1,820 (67%) 1,581 1,915 (17%)
Ecuador tariff oil (bopd) (2)  1,183 (100%) 139 1,406 (90%)
Total (boepd) (2) 21,519 17,953 20% 21,590 17,446 24%
          
Operating netbacks ($/boe) (1)         
Natural gas ($/Mcf) 3.92 3.56 10% 3.80 3.89 (2%)
Colombia oil ($/bbl) 27.89 23.44 19% 31.18 19.05 64%
Ecuador tariff oil ($/bbl) (2)  38.54 (100%) 38.54 38.54  
Corporate ($/boe) (2) 22.51 19.21 17% 22.27 19.96 12%
  1. Non-IFRS measures – see “Non-IFRS Measures” section within MD&A.
  2. Includes tariff oil production and sales related to the Ecuador IPC – see “Non-IFRS Measures” section within MD&A.

This press release should be read in conjunction with the Corporation’s audited consolidated financial statements and related Management’s Discussion and Analysis.  The Corporation’s has filed its audited consolidated financial statements and related Management's Discussion and Analysis as of and for the year ended December 31, 2018 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. 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.

“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.

“1P” means Total Proved

“2P” means Total Proved + Probable

“3P” means Total Proved + Probable + Possible

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 Total Proved 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 Total Proved + Probable basis.

Finding and development costs per million cubic feet (Mcf) represent exploration and development costs incurred per Mcf of Total Proved + Probable reserves added during the year.  The Corporation, industry analysts, and investors use such metrics to measure a Corporation’s ability to establish a long‐term trend of adding reserves at a reasonable cost. 

The recycle ratio is calculated by dividing natural gas netback by finding and development costs relating to natural gas.

The one-year recycle ratio was calculated based on natural gas netback for the year ended December 31, 2018 of $3.80/Mcf, and the three-year recycle ratio was calculated based on natural gas netback for the three year ended December 31, 2018 of $4.03/Mcf

For further information please contact:                                              
Investor Relations
+1 (214) 235-4798                                                   
Email: IR@canacolenergy.com
http://www.canacolenergy.com