Canacol Energy Ltd.
TSX : CNE
OTCQX : CNNEF
BVC : CNEC

Canacol Energy Ltd.

February 12, 2015 16:45 ET

Canacol Energy Ltd. Reports Fiscal Q2 2015 Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - Feb. 12, 2015) - 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 and six months ended December 31, 2014. Dollar amounts are expressed in United States dollars, except as otherwise noted.

Overview

With the Corporation's diversified asset strategy, Canacol continued to focus more attention on its significant natural gas assets in Colombia in light of weakness in benchmark crude oil prices. Production for fiscal Q2 2015 remained strong at 11,822 boepd, a 17% increase over the comparable quarter, with 44% of production arising from its Esperanza and Ecuador assets that were unaffected by benchmark crude oil prices. Production for the month of January, 2015, averaged 11,940 boepd. The Corporation acquired two new key gas blocks in the quarter, VIM-5 and VIM-19, which lay adjacent to its existing producing Esperanza block, and made a significant gas discovery with its exploration well at Clarinete-1 that tested a combined 45.3 MMcfpd (7,947 boepd) of sweet, dry gas from two intervals. The success at Clarinete-1 represents a significant event that will have a material impact on the Corporation's reserves base and creates a significant opportunity for commercialization into a local gas market that has seen increasing demand at very favorable economics and sets the stage for significant production growth by the end of calendar 2015 and into 2016.

The Corporation continued to maintain a strong cash position during the quarter with cash and cash equivalents of $124.7 million available at December 31, 2014, and a further $74.8 million of restricted cash as of the same date. Canacol incurred a net loss of $46.0 million for the quarter driven entirely by several non-cash items that did not affect the core business of the Corporation. In particular, significant devaluation of the Colombian peso versus the United States dollar in the quarter resulted in a non-cash deferred tax expense impact of approximately $22.4 million, while an impairment charge, primarily related to the mature and immaterial Rancho Hermoso property due to lower forecast crude oil prices, as well as losses on disposition of minor non-core assets resulted in a net loss impact of approximately $22.3 million. The Corporation's core producing assets at Esperanza, LLA-23 and Ecuador were unaffected. Evidencing the non-cash nature of the net loss, adjusted funds from operations, although affected by lower crude oil prices, remained strong at $23.0 million for the quarter.

The Corporation is in the process of securing a new $200 million 54 month syndicated term loan from BNP Paribas which will replace the existing term loan under similar terms but will defer principal debt repayments for 30 months until September 2017.

The primary focus and driver of growth for the Corporation over the next year will be the expanding natural gas business in the Lower Magdalena Basin of Colombia. This local market is seeing increased demand against a backdrop of declining supply, and the favorable pricing is de-coupled from world oil prices. Canacol has significant productive capacity in the area from its Nelson, Palmer and Clarinete fields, as well as significant exploration potential on its 636,340 net acres of land in the area. Canacol currently produces approximately 20 MMcfpd (3,509 boepd) under existing contracts and has entered into four additional new take-or pay gas contracts, with three expected to commence shipments in December 2015. As a result, the Corporation expects production to increase significantly to 83 MMcfpd (14,561 boepd) in December 2015 and higher again in 2016 with additional contracts.

In light of both the magnitude of the material gas discovery made at Clarinete, and the impending closure of a new debt facility that will replace the existing debt facility and free up additional capital for investment via not having to repay any debt until September 2017, the Corporation is finalizing its capital and production guidance for calendar 2015 and plans to release it within the next two weeks once it has been approved by the Board of Directors.

President's Message

Charle Gamba, President and CEO of the Corporation, commented: "Fiscal Q2 2015 was the first reported quarter impacted by the recent significant decline in benchmark crude oil prices. Nevertheless, production was 11,822 boepd for the quarter and we posted adjusted funds from operations of $23.0 million for the period. Two of our key producing assets, Esperanza and Ecuador, were unaffected by crude oil price declines; Esperanza because of its long-term natural gas contracts linked to the Guajira price index currently set at $5.08/MMbtu ($28.96/boe), while Ecuador tariff oil received a flat tariff of $38.54/bbl and incurred no royalties, production or transportation costs. Together, Esperanza and Ecuador accounted for 44% of total production during the quarter. Significantly, gas production is further expected to increase from approximately 20 MMcfpd (3,509 boepd) currently to 83 MMcfpd (14,561 boepd) in late calendar 2015 as a result of new gas supply contracts which we have previously announced. These contracts, which are for a period for five years, have pricing of $5.40/MMbtu, escalating at 2% annually, on 35 MMcfpd of production, and $8.00/MMbtu, escalating at 3% annually, on an additional 30 MMcfpd of production.

The most significant event of the quarter was the acquisition of the VIM-5 and VIM-19 blocks, adjacent to our existing producing Esperanza property, and the drilling of the highly successful Clarinete-1 gas well which recently tested at 20.6 MMcfpd with no water at the end of a 72 hour flow period from the lower Cienaga de Oro sandstone interval and 24.7 MMcfpd with no water at the end of a 16 hour flow period from the upper Cienaga de Oro sandstone interval. The combined gross deliverability of the Clarinete-1 well from both intervals is approximately 45.3 MMcfpd (7,947 boepd). As a result of the Clarinete discovery, we were able to recently sign an additional 15 year gas supply contract for 35 MMcfpd (6,140 boepd) at $4.90/MMbtu ($27.93/boe), escalated at 2% per annum, commencing in the third quarter of calendar 2016. The gas will be used for liquefaction into liquefied natural gas for the Caribbean market and Canacol has further secured an option, valid for six months from the agreement date, to participate for a 26% interest in the ownership of the venture in exchange for the investment of $13 million. Through this beneficial ownership, we expect to derive additional revenues of $1.25/MMbtu ($7.12/boe), for a total all-in realized sales price of $6.25/MMbtu ($35.63/boe).

On the crude oil side, our LLA-23 property produced approximately 42% of total production for the quarter and achieved an operating netback of $30.78/bbl. We are in the process of upgrading our facilities at LLA-23 to centralize all operations from the different fields within the block into one site; by doing so reducing operating expenses, transportation expenses and water handling costs via reinjection. As a result, we expect to start seeing the benefits of reduced operating costs by mid-2015. Meanwhile, operations on our other oil producing properties are being monitored closely with the intention to shut-in further production where uneconomic.

From a financial standpoint, Canacol continued to maintain a strong cash position with cash and cash equivalents of $124.7 million available at December 31, 2014, and a further $74.8 million of restricted cash as of the same date. In October, we also announced a significant strategic financing with Apollo Investment Corporation for an additional $100 million, $50 million of which was drawn in October and the remaining $50 million remains committed and available to be drawn within 18 months. We are also in the process of entering into a new term loan, expected to close in March 2015, for $200 million to retire our existing term loan and with the main benefit being the deferral of amortization payments for 30 months while we build our significant gas business.

Canacol is increasingly well positioned to continue to realize growth through development of our extensive and diversified asset base, particularly with respect to natural gas opportunities, while maintaining a reduced exposure to benchmark crude oil prices. We expect a significant step-change in 2015 as we build our productive capacity on our gas assets and commission such production by the end of the year. We look forward to delivering enhanced shareholder value from these initiatives."

Highlights for Fiscal Q2 2015

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

Financial and operational highlights of the Corporation include:

  • Average daily sales volumes increased 29% to 11,403 barrels of oil equivalent per day ("boepd") for the three months ended December 31, 2014 compared to 8,821 boepd for the comparable period. Average daily sales volume increased 36% to 12,356 boepd for the six months ended December 31, 2014 compared to 9,091 boepd for the comparable period.

  • Average daily production volumes increased 17% to 11,822 boepd for the three months ended December 31, 2014 compared to 10,095 boepd for the comparable period. Average daily production volumes increased 30% to 12,539 boepd for the six months ended December 31, 2014 compared to 9,615 boepd for the comparable period. The increases in production volumes are primarily due to new production from the Labrador, Leono, Pantro and Tigro discoveries on the LLA-23 block, production increases from the Libertador and Atacapi fields in Ecuador, and new production from the Oso Pardo and Morsa discoveries on the Santa Isabel block.

  • Petroleum and natural gas revenues for the three months ended December 31, 2014 decreased 14% to $36.4 million compared to $42.2 million for the comparable period. Petroleum and natural gas revenues for the six months ended December 31, 2014 increased 5% to $95.3 million compared to $90.4 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 the three months ended December 31, 2014 decreased 7% to $43.9 million compared to $47.1 million for the comparable period. Adjusted petroleum and natural gas revenues for the six months ended December 31, 2014 increased 12% to $111.2 million compared to $99.5 million for the comparable period.

  • Average operating netback for the three months ended December 31, 2014 decreased 35% to $25.14/boe compared to $38.44/boe for the comparable period. Average operating netback for the six months ended December 31, 2014 decreased 18% to $31.89/boe compared to $38.89/boe for the comparable period. The decrease of average operating netback is mainly attributable to decreases in benchmark crude oil prices. Average operating netback is inclusive of results from the Ecuador IPC.

  • Adjusted funds from operations for three months ended December 31, 2014 increased 37% to $23.0 million compared to $16.7 million for the comparable period. Adjusted funds from operations for six months ended December 31, 2014 increased 44% to $60.1 million compared to $41.8 million for the comparable period. Adjusted funds from operations is inclusive of results from the Ecuador IPC.

  • Net loss for the three months ended December 31, 2014 increased 342% to $46.0 million compared to $10.4 million for the comparable period. Net loss for the six months ended December 31, 2014 increased 329% to $31.9 million compared to $7.4 million for the comparable period. Driving the net loss in the three months ended December 31, 2014 is a non-cash deferred tax expense of approximately $22.4 million attributable to the significant devaluation of the Colombian peso versus the United States dollar, as well as an impairment charge, primarily related to the Rancho Hermoso property due to lower forecast crude oil prices, and losses on disposition of minor non-core assets that together resulted in a net loss impact of approximately $22.3 million. Rancho Hermoso is a mature field with no expected material impact on the Corporation's future production and operating cash flows. The Corporation's core producing assets at Esperanza, LLA-23 and Ecuador were unaffected.

  • Capital expenditures for the three and six months ended December 31, 2014 were $78.4 million and $125.9 million, respectively, while adjusted capital expenditures, inclusive of amounts related to the Ecuador IPC, were $87.2 million and $143.4 million, respectively.

  • At December 31, 2014, the Corporation had $124.7 million in cash and cash equivalents and $74.8 million in restricted cash.

Financial Three months ended December 31, Six months ended December 31,
2014 2013 Change 2014 2013 Change
Petroleum and natural gas revenues, net of royalties 36,404 42,168 (14 %) 95,321 90,390 5 %
Adjusted petroleum and natural gas revenues, net of royalties, including revenues related to the Ecuador IPC (2) 43,878 47,101 (7 %) 111,234 99,491 12 %
Cash provided by operating activities 31,743 36,406 (13 %) 77,361 56,130 38 %
Per share - basic ($) 0.29 0.42 (31 %) 0.72 0.65 11 %
Per share - diluted ($) 0.29 0.41 (29 %) 0.71 0.64 11 %
Adjusted funds from operations (1) (2) 22,952 16,713 37 % 60,114 41,759 44 %
Per share - basic ($) 0.21 0.19 11 % 0.56 0.48 17 %
Per share - diluted ($) 0.21 0.19 11 % 0.55 0.48 15 %
Net income (loss) (45,970 ) (10,412 ) 342 % (31,860 ) (7,431 ) 329 %
Per share - basic and diluted ($) (0.43 ) (0.12 ) 258 % (0.30 ) (0.09 ) 233 %
Capital expenditures, net 78,403 22,749 245 % 125,925 40,157 214 %
Adjusted capital expenditures, net, including capital expenditures related to the Ecuador IPC (1)(2) 87,228 32,679 167 % 143,437 56,422 154 %
December 31,
2014
June 30,
2014
Change
Cash and cash equivalents 124,696 163,729 (24 %)
Restricted cash 74,771 66,827 12 %
Working capital surplus, excluding the current portion of bank debt and non-cash items (1) 78,824 159,117 (50 %)
Short-term and long-term bank debt 244,580 210,688 16 %
Total assets 757,948 756,587
Common shares, end of period (000s) 107,814 107,736
Operating Three months ended December 31, Six months ended December 31,
2014 2013 Change 2014 2013 Change
Petroleum and natural gas production, before royalties (boepd)
Petroleum (3) 8,586 6,998 23 % 9,254 6,555 41 %
Natural gas 3,236 3,097 4 % 3,285 3,060 7 %
Total (2) 11,822 10,095 17 % 12,539 9,615 30 %
Petroleum and natural gas sales, before royalties (boepd)
Petroleum (3) 8,187 5,868 40 % 9,092 6,088 49 %
Natural gas 3,216 2,953 9 % 3,264 3,003 9 %
Total (2) 11,403 8,821 29 % 12,356 9,091 36 %
Realized sales prices ($/boe)
LLA-23 (oil) 58.62 86.86 (33 %) 72.49 89.81 (19 %)
Esperanza (natural gas) 25.12 29.45 (15 %) 23.27 29.56 (21 %)
Ecuador (tariff oil) (2) 38.54 38.54 - 38.54 38.54 -
Total (2) 45.55 61.81 (26 %) 53.41 63.64 (16 %)
Operating netbacks ($/boe) (1)
LLA-23 (oil) 30.78 64.68 (52 %) 43.50 66.05 (34 %)
Esperanza (natural gas) 20.04 24.56 (18 %) 18.41 24.82 (26 %)
Ecuador (tariff oil) (2) 38.54 38.54 - 38.54 38.54 -
Total (2) 25.14 38.44 (35 %) 31.89 38.89 (18 %)
(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.

Financing Update

The Corporation is in the process of accessing the syndicated loan market with a new senior term loan in the amount of $200 million in February 2015, which will be used for both refinancing existing indebtedness in the amount of $190.6 million and general corporate purposes. The new term loan, which is led and underwritten by BNP Paribas, has a term of 54 months with interest payable quarterly and principal payable in 8 equal quarterly instalments starting in September 2017 following an initial 30 month grace period. The new term loan will be secured by all the material assets of the Corporation and benefits from favorable leverage, interest coverage and minimum current ratios. The leverage ratio and interest coverage ratio are historical in nature and are expected to materially improve as production from new gas contracts comes on in late 2015. There are no prepayment penalties in connection with the new term loan. Closing of the transaction is subject to legal approvals, Canacol Board of Directors approval, and other customary closing conditions. The transaction is expected to close and be funded in March 2015.

Outlook

In light of continued weakness in benchmark crude oil prices, the Corporation will focus its efforts in calendar 2015 on: 1) development activity and infrastructure spending at its Esperanza and VIM-5 gas contracts to bring total production up to 83 MMcfpd (14,561 boepd) from the current 20 MMcfpd (3,509 boepd) by calendar year end 2015; 2) negotiation of additional gas contracts related to the Clarinete gas discovery and initiation of field development to commercialize the discovery; 3) infrastructure spending and seismic acquisition on the LLA-23 light oil contract with a focus on continued cost reductions and firming up future exploration leads; and 4) tariff oil production operations in Ecuador, which are insensitive to crude oil prices.

Two production tests at Clarinete-1 were completed and announced in January and February 2015. The lower part of the Cienaga de Oro sandstone reservoir was perforated in various intervals between 6,919 and 7,230 feet measured depth. This interval flowed naturally at a stable gross rate of 20.6 MMcfpd (3,606 boepd) using a 36/64 inch choke with a tubing head pressure of 2,528 pounds per square inch with no water, at the end of a 72 hour flow period. The upper part of the Cienaga de Oro sandstone reservoir was perforated in various intervals between 6,409 and 6,568 feet measured depth. This interval achieved a final rate of 24.7 MMcfpd (4,333 boepd) using a 42/64 inch choke with a tubing head pressure of 2,274 pounds per square inch with no water, at the end of a 16 hour flow period. The combined gross deliverability of the Clarinete-1 well from both intervals is approximately 45.3 MMcfpd (7,947 boepd). Meanwhile the Corporation is preparing to lay a flowline to tie the Clarinete-1 well into its operated gas processing facility at the Jobo station. The Corporation has identified ten prospects and leads within the recently acquired VIM-5 and VIM-19 that contain a significant volume of prospective resource assuming all prospects are drilled according to a July 2014 NI 51-101 compliant report from Gaffney Cline and Associates ("GCA"). The gross unrisked pre drill best estimate for the Clarinete prospect as per the GCA prospective resource report is 540 bcf of gas. Pursuant to an existing agreement, and subject to approval from the ANH, an industry joint venture partner has the ability to earn up to 25% of the Corporation's 100% interest in exchange for fulfilling certain financial commitments. The Corporation plans to negotiate additional new gas sales contracts associated with the Clarinete discovery, and has already executed one new contract described below.

In February 2015, the Corporation executed a new 15 year take or pay contract for the sale of 35 MMcfpd (6,140 boepd) of gas to Altenesol Colombia S.A.S ("Altenesol") commencing in the third quarter of calendar 2016. Under the terms of the contract, Altenesol will pay $4.90/MMbtu ($27.93/boe), escalated at 2% per year across the term of the contract. In addition, Canacol and Altenesol executed an agreement pursuant to which Canacol has the option, valid for six months from the agreement date, to participate in the revenues generated by the sale of the LNG through an equity ownership position in Altenesol of approximately 26% in exchange for investing $13 million in the project. Altenesol will use the gas to produce approximately 360,000 gallons of LNG per day at a dedicated liquefaction facility to be located close to Canacol's operated Jobo gas processing facility. Altenesol has recently executed a 15 year take or pay contract to sell the LNG to be produced by the facility to a large international distributor for export to markets in the Caribbean at a sales price of approximately $11/MMbtu ($62.70/boe) at the sales point of Cartagena in Colombia. Canacol, through its beneficial ownership of Altenesol, will also derive revenues from the sale of the LNG of approximately $1.25/MMbtu ($7.12/boe). As such, total revenues from the gas sales contract and Canacol's beneficial ownership in Altenesol are expected to be approximately $6.25/MMbtu ($35.63/boe) escalated at 2% per year across the 15 year tenure of the take or pay contract. The gas for the contract is expected to come from the recently discovered Clarinete gas field described above.

On the Esperanza contract, the Corporation plans to test the Corozo-1 well, subject to ANH approval, using the same rig from Clarinete-1 once operations there are completed. Based upon the significant gas resource potential of the Clarinete discovery, the Corporation decided to defer the drilling of the Canandonga-1 exploration well on the Esperanza contract, and instead drilled the Nelson-5 development well at its operated Nelson gas field, which is currently being tied in. Otherwise, the Corporation is in the process of various infrastructure spending at Esperanza to install flow lines and expand the Jobo station in order to deliver the 83 MMcfpd of contracted gas by the end of calendar 2015. The Corporation has already executed three new gas sales contracts for a combined 65 MMcfpd which is expected to take Canacol's current daily gas production of approximately 20 MMcfpd (3,509 boepd) to 83 MMcfpd (14,561 boepd) in late calendar 2015. The new contracts each have a five year term, with pricing of $ 5.40/MMbtu escalated at 2% per year for two of the contracts totaling 35 MMcfpd, and $8.00/MMbtu escalated at approximately 3% per year for the third contract of 30 MMcfpd. Canacol currently sells approximately 18 MMcfpd (3,158 boepd) of gas from the Nelson Field to a local ferronickel producer under a 10 year contract that expires in 2021. That contract was linked to the Guajira price index, which changed effective October 29, 2014 from $3.97/MMbtu ($22.63/boe) to $5.08/MMbtu ($28.96/boe). Nevertheless, as mentioned above, the Corporation has diversified its future gas sales with the addition of three new fixed-price gas contracts commencing in December 2015.

Despite low crude oil prices, production from the LLA-23 block remains profitable due to the high deliverability of the reservoirs and the effective cost structure. The Corporation will continue with spending on facilities upgrades and water injection that commenced in 2014 and expects to realize lower operating costs by mid-2015. The Corporation is also in the process of acquiring 400 square kilometer 3D seismic on the block with the objective of firming up the portfolio of 12 currently identified exploration leads into prospects for drilling in calendar 2015 and 2016. No immediate exploration drilling on the LLA-23 block is planned at the present time.

In Ecuador, the consortium plans to drill one new development well and work over four existing producing wells. Further, the consortium plans to complete five waterflood pilots and spend capital on waterflood facilities and other infrastructure.

In other areas of Colombia, the Corporation and its partner expect to drill up to two additional appraisal wells into the shallow Lisama discovery on the VMM-2 block in calendar 2015. The operator of the Capella property is expected to continue its development program for the field through calendar 2015. The operator of the VMM-3 block drilled the Pico Plata-1 exploration well in early October 2014 targeting the shale of the Cretaceous La Luna formation and is currently coring the well. No material calendar 2015 capital expenditures are planned on any of the Corporation's other oil properties at the present time.

The Corporation's has filed its unaudited interim condensed consolidated financial statements and related Management's Discussion and Analysis as of and for the three and six months ended December 31, 2014 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 news 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"), which is incorporated herein by reference and is 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 news 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 news 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 news 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 equivalent ("boe") 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.

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