Frontera Announces Third Quarter 2019 Results
Production and Operational Performance Consistent with Strong Guidance Results
Continued Focus on Shareholder Returns with Dividends and Buybacks
TORONTO, Nov. 7, 2019 /CNW/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") announces today the release of its Interim Condensed Consolidated Financial Statements for the third quarter of 2019, together with its Management, Discussion and Analysis ("MD&A"). These documents will be posted on the Company's website at www.fronteraenergy.ca and SEDAR at www.sedar.com. All values in this news release and the Company's financial disclosures are in United States dollars unless otherwise stated.
Production averaged 70,213 boe/d in the third quarter of 2019, an increase of 6% compared to 66,393 boe/d in the third quarter of 2018, driven by production growth in both Colombia and Peru. Third quarter 2019 production decreased 6% compared to the second quarter of 2019, reflecting reduced production in July 2019 due to a third-party force majeure event on the NorPeruano pipeline in Peru. For the first nine months of 2019 production averaged 70,866 boe/d, in-line with 70,732 boe/d in the first nine months of 2018, demonstrating the stability of the Company's core producing assets. Frontera is on track to achieve the top end of 2019 production guidance of between 65,000 and 70,000 boe/d, with production currently over 73,000 boe/d.
Net loss of $49 million ($0.50/share) in the third quarter of 2019 was impacted by impairments relating to long-term receivables from Infrastructure Ventures Inc. of $37 million, exploration and evaluation assets of $8 million and a tax charge of $25 million.
During the third quarter of 2019, the Brent oil benchmark price averaged $62.03/bbl, compared to $75.84/bbl in the third quarter of 2018 and $68.47/bbl in the second quarter of 2019, a decrease of 18% and 9% respectively. Weaker Brent oil pricing was partially offset by continued favorable narrow oil price differentials for Vasconia blend, helping the Company achieve a strong realized net sales price of $53.21/boe in the third quarter of 2019. Net sales price was unchanged compared to the third quarter of 2018 which suffered from hedging losses, and 11% lower than the second quarter of 2019, reflecting lower Brent oil prices and modestly wider differentials.
Operating netback of $29.61/boe in the third quarter of 2019 was 15% higher than in the third quarter of 2018 driven by a 16% reduction in production costs and a 13% reduction in transportation costs. Operating netback was 19% lower quarter over quarter driven by lower realized oil prices, while production and transportation costs were stable.
Third quarter 2019 sales volumes were 54,378 boe/d, impacted by a build in inventory of 8,694 boe/d in Peru and Colombia. Sales volumes of 61,071 boe/d in the third quarter of 2018 benefited from an overlift of 5,383 boe/d and an additional cargo in each of Colombia and Peru. Sales volumes were down 18% compared to the second quarter of 2019 which benefited from an inventory draw of 1,369 boe/d and a cargo sold from Peru.
At the end of the third quarter of 2019, crude oil inventory was 2.7 million bbls, an increase of 43% compared to the second quarter of 2019 and of 71% compared to the third quarter of 2018. In Peru, the timing of the sale of third-party fuel oil in the NorPeruano pipeline prevented the Company from selling its oil during the quarter resulting in increasing inventory by 0.5 million bbls to 1.9 million bbls. It is expected that the Company will reduce inventory in Peru by between 0.3 and 0.5 million bbls during the fourth quarter of 2019. Inventory also built in Colombia by 0.3 million bbls to 0.8 million bbls as a result of the timing of nominations of the Company's cargoes, which is expected to reverse depending on the timing of additional Colombia cargoes. Total Company inventory at the end of 2019 is expected to be lower than the third quarter of 2019.
Year to Date Performance Relative to Guidance:
The Company continues to deliver year to date results that are expected to be towards the favorable end of 2019 guidance for average daily production, operating EBITDA, operating costs, and transportation costs. Capital expenditures for 2019 are expected to be within the guidance range including the impact of the consolidation of CGX Energy Inc. ("CGX") and abandonments.
2019 Year To Date |
2019 Guidance (1) |
||
Operating EBITDA |
($MM) |
452 |
525 to 575 |
Capital Expenditures |
($MM) |
213 |
325 to 375 |
Average Daily Production |
(boe/d) |
70,866 |
65,000 to 70,000 |
Production Costs (2) |
($/boe) |
11.39 |
12.00 to 12.50 |
Transportation Costs (3) |
($/boe) |
12.39 |
12.50 to 13.50 |
Brent Oil Price Assumption |
($/bbl) |
65.05 |
65.00 |
Oil Price Differential (4) |
($/bbl) |
2.58 |
3.50 |
Foreign Exchange Rate (4) |
(USD:COP) |
3,240:1 |
3,100:1 |
1Original 2019 Guidance was revised with more positive metrics on August 1, 2019. |
2Calculated using production before royalties as this most accurately reflects per unit production costs. |
3Calculated using production after royalties as this most accurately reflects per unit transportation costs. |
4Year to date averages from Bloomberg. |
Gabriel de Alba, Chairman of the Board of Directors of Frontera, commented:
"The Company has been delivering on its promises, being on track to achieve the favorable end of all key guidance ranges while delivering excess cash to shareholders. Year to date, we have made dividend distributions to shareholders of $108 million (C$1.44/share) providing a yield of over 13% based on the recent share price. The Company has also declared a regular cash dividend of C$0.205 per share for January 2020. The Board remains committed to the regular dividend of $15 million per quarter during quarters when Brent oil price averages $60/bbl or higher. The Company continues to generate excess cash as demonstrated by cash flow from operating activities which continues to exceed cash used in investing activities. Additionally, the Company has renewed its NCIB which will enable it to repurchase up to 10% of the public float. To date, under the new NCIB the Company has repurchased 377,200 shares.
We are achieving cost reduction and capital efficiency improvements driving significant improvements in our metrics year-over-year with lower production costs, transportation costs and G&A costs. The exciting opportunities added to the portfolio in 2019, which include acreage offshore Guyana and in Ecuador, will lead to capital being invested in those opportunities in 2020 and beyond."
Richard Herbert, Chief Executive Officer of Frontera, commented:
"Frontera is delivering on our commitment to sustain core production while developing assets for longer-term growth. Year to date production of 70,866 boe/d in 2019 is just above the high end of guidance and is supported by 3% production growth in Colombia compared to 70,732 boe/d over the same period in 2018. Current production of over 73,000 boe/d has been stable since the resumption of production from Block 192 in Peru in July.
Our heavy oil business unit, the cornerstone of our long term stable production profile has had tremendous success so far in 2019. The Quifa field has been at or around 50,000 bbl/d on a gross basis for the past two months, the highest production levels since 2015 thanks to the additional water-handling capacity added in 2018. The CPE-6 block has had success from both development drilling of horizontal wells, which have yielded production rates above our expectations, and exploration wells to the northwest and southeast of the Hamaca field, which have increased our optimism about Hamaca field expansion and new field discovery on CPE-6. In addition, we are currently drilling two exploration appraisal wells, the first of which looks promising, to confirm the new field discovered from the Coplero-1 exploration well drilled in the third quarter of 2019.
In Colombia, additional exploration drilling on the La Belleza-1 well in the VIM-1 block, in northern Colombia, is drilling on time and on budget with results expected by the end of the year. This is the first well to be drilled with our partner Parex Resources Inc. We are excited to be drilling again in the Lower Magdalena Valley where we have a significant amount of under-utilized gas processing capacity. Frontera will be evaluating additional natural gas and natural gas liquids bearing zones from existing wells as part of a well service campaign in the fourth quarter. We also plan to drill an exploration well at Guama in the first quarter of 2020 as the Company looks to increase the overall mix of natural gas within the production profile.
Offshore Guyana, one of the world's most exciting exploration basins where Frontera is moving forward in its joint venture with local partner CGX, the 3D seismic acquisition program on the northern part of the Corentyne block has just been completed. With the Corentyne and Demerara blocks largely covered by high-quality 3D seismic, we are preparing to select drilling locations in each block for drilling in the second half of 2020. Recent nearby positive drilling results from two exploration wells drilled on the Orinduik block on the slope offshore Guyana, immediately adjacent to the Demerara block, have also de-risked a number of high-quality exploration prospects on our blocks."
Financial Highlights:
2019 |
2018 |
|||
Q3 |
Q2 |
Q3 |
||
Revenue |
($MM) |
278 |
377 |
367 |
Net (loss) income (1) |
($MM) |
(49) |
228 |
45 |
Per share - basic (2) |
($) |
(0.50) |
2.32 |
0.45 |
Net sales (3) |
($MM) |
266 |
362 |
299 |
Cash provided by operating activities |
($MM) |
113 |
176 |
178 |
Operating EBITDA (3) |
($MM) |
126 |
181 |
93 |
Operating EBITDA margin (Operating EBITDA/Net sales)(3) |
(%) |
47% |
50% |
31% |
General and administrative (G&A) |
($MM) |
18 |
18 |
23 |
Capital expenditures |
($MM) |
71 |
73 |
124 |
Total cash, including restricted cash(4) |
($MM) |
442 |
486 |
786 |
Working capital |
($MM) |
125 |
176 |
331 |
1Net (loss) income attributable to equity holders of the Company. |
2Basic weighted average numbers of common shares outstanding for the quarter ended September 30, 2019 97,956,379 (June 30, 2019 98,003,260 and September 30, 2018 99,931,626). |
3These metrics are Non-IFRS financial measures. See Advisories - "Non-IFRS Financial Measures" - below and "Non-IFRS Measures" on page 16 of the MD&A. |
4Includes $314 million of cash and cash equivalents, $36 million of short-term restricted cash and $92 million of long term restricted cash. |
Cash provided by operating activities of $113 million compared to $90 million of cash used in investing activities in the third quarter of 2019, generating $23 million of additional cash, exceeding the regular quarterly dividend of $15 million. Cash provided by operating activities adjusted for changes in non-cash working capital was $74 million in the third quarter of 2019.
Net loss of $49 million ($0.50/share) in the third quarter of 2019 was impacted by $45 million of impairment charges and a $25 million tax charge and compares to net income of $228 million ($2.32/share) in the second quarter of 2019, which benefited from the recognition of a deferred tax asset, and net income of $45 million ($0.45/share) in the third quarter of 2018.
Operating EBITDA of $126 million was 30% lower than the second quarter of 2019 driven by lower oil price and higher inventories and 35% higher than the third quarter of 2018 on reduced operating, transportation and G&A costs. Operating EBITDA in the first nine months of 2019 was $452 million compared to $304 million in the first nine months of 2018 driven by cost reduction initiatives and the reduced impact of losses on risk management activities. Operating EBITDA margin of 47% in the third quarter of 2019 was a slight decrease over a 50% operating EBITDA margin in the second quarter of 2019 but was significantly higher than the 31% operating EBITDA margin in the third quarter of 2018.
For the third quarter of 2019, revenue was $278 million, compared to $377 million in the second quarter of 2019 as a result of lower oil price, increase in inventory at the end of third quarter of 2019 and one additional cargo in the second quarter compared to the third quarter.
Production costs during the third quarter of 2019 of $11.60/boe were 4% higher compared to the second quarter of 2019 and 16% lower than in the third quarter of 2018. On October 1, 2019 the Company moved to a new operational model with a view to further decreasing operating and capital costs and improving operational efficiency.
Transportation costs during the third quarter of 2019 of $12.00/boe were 4% lower compared to $12.49/boe in the second quarter of 2019 and 13% lower compared to $13.77/boe during the third quarter of 2018.
G&A costs were $18 million during the third quarter of 2019, flat compared to the second quarter of 2019 when adjusting for the number of days in each quarter. G&A costs were 20% lower compared to the third quarter of 2018 reflecting the continuing benefits of cost savings initiatives implemented in 2018 and 2019.
Cash and cash equivalents including restricted cash totaled $442 million as at September 30, 2019, a decrease of $43 million compared to June 30, 2019 reflecting $55 million on shareholder returns, offset by $23 million of cash provided by operating activities in excess of cash used in investing activities.
During the third quarter of 2019 the Company paid regular and special dividends of C$0.74/share in aggregate. In addition, the Company paid its regular quarterly dividend of C$0.205/share on October 16, 2019 and announced a regular quarterly dividend of C$0.205 to be paid on or about January 17, 2020 to shareholders of record on January 3, 2020. The Company's policy is to pay a quarterly dividend of approximately $15 million during quarters in which Brent oil price averages $60/bbl or higher. The declaration and payment of any specific dividend, the actual amount, the declaration date, the record date, and the payment of each quarterly dividend will be subject to the discretion of the Board of Directors. To date in 2019, the Company has paid dividends of C$1.44/share in regular and special dividends, representing a yield of over 13% based on the recent share price.
In October 2019 the Company announced the renewal of its normal course issuer bid ("NCIB"), pursuant to which the Company may repurchase up to 6,532,400 shares of the Company, representing 10% of the public float, during a 12 month period between October 18, 2019 and October 17, 2020. To date, under the renewed NCIB, the Company repurchased for cancellation 377,200 shares.
The Company has hedged approximately 60% of fourth quarter 2019 production, 40% of first quarter 2020 production and 30% of second quarter 2020 production using a combination of Brent oil price linked purchased put options, zero cost collars, put spreads and three-way collars to protect the Company's balance sheet and capital program within hedging limits set by the Board of Directors.
Stable Quarterly Production:
Production, before royalties(1) |
2019 |
2018 |
||||||||
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
||||||
Oil and liquids (bbl/d) |
||||||||||
Colombia |
61,420 |
61,956 |
63,052 |
59,687 |
57,655 |
|||||
Peru |
6,510 |
9,975 |
2,271 |
8,974 |
4,616 |
|||||
Total oil and liquids (bbl/d) |
67,930 |
71,931 |
65,323 |
68,661 |
62,271 |
|||||
Natural gas (boe/d)(2) |
||||||||||
Colombia |
2,283 |
2,454 |
2,651 |
3,263 |
4,122 |
|||||
Total natural gas (boe/d) |
2,283 |
2,454 |
2,651 |
3,263 |
4,122 |
|||||
Total equivalent production (boe/d) |
70,213 |
74,385 |
67,974 |
71,924 |
66,393 |
|||||
1Additional production details are available in the MD&A "Financial and operational results" section, page 2. |
2Colombian standard natural gas conversion ratio of 5.7 Mcf per bbl as required by the Colombian Ministry of Mines and Energy. |
Production in the third quarter of 2019 averaged 70,213 boe/d compared to 74,385 boe/d in the second quarter of 2019 as a result of production being interrupted during July on Block 192 in Peru following a force majeure event on the NorPeruano pipeline. Production from Colombia decreased 1% during the third quarter of 2019 compared with the previous quarter, as a result of managed production decline from the light and medium oil and natural gas business units offset by growth in the heavy oil business unit which was up 4% during the quarter.
Total Company production was 97% oil-weighted in the third quarter of 2019 compared to 97% in the second quarter of 2019 and 94% in the third quarter of 2018. The higher oil mix as a percentage of total production results in better realized prices given narrow oil price differentials so far in 2019.
During the third quarter of 2019, capital expenditures were $71 million down 4% compared to $73 million in the previous quarter and down 43% from the third quarter of 2018. The decrease reflects a similar level of activity and similar activity type in the third quarter of 2019 where there were 31 wells drilled compared to the second quarter of 2019 where there were 42 wells drilled. The decrease in the third quarter of 2019 compared to the third quarter of 2018 reflects a return to more normalized spending levels for ongoing development wells and exploration initiatives which excludes major infrastructure projects or higher cost exploration projects in the second half of 2018. Capital expenditures in the fourth quarter will include more exploration and abandonment activity as well as additional spending on infrastructure at CPE-6, which is expected to bring the annual spending within the range for 2019 guidance.
A total of 31 development and exploration wells were drilled in the third quarter of 2019. 30 development wells were drilled compared to 27 development wells planned, as efficiency improvements at Quifa have led to wells being drilled in less time. As such the Company has released one of the four active Quifa rigs earlier than expected as part of the 2019 development drilling campaign. There was one exploration well drilled at CPE-6, in line with expectations.
In October 2019, the Company began drilling the Galope-1 appraisal well on the CPE-6 block to evaluate the new field discovered by the Coplero-1 exploration well drilled during the third quarter of 2019. The well was drilled to a total depth of 8,126 feet MD on November 1, 2019. The well encountered 10.5 feet of net pay in the C7B reservoir within the Carbonera formation. Petrophysical analysis of LWD data indicates a sandstone reservoir with 33% porosity, permeability of 2.6 Darcys, water saturation of 36% and a clay content of 1.5%. The well is expected to be completed and tested using an electrical submersible pump during the fourth quarter of 2019. The Company is currently drilling a second appraisal well, Contrapuento-1, to further delineate the new field.
The 3D seismic acquisition program has been successfully completed on the northern section of the Corentyne block offshore Guyana. The 3D program covers approximately 582 km2 and will greatly enhance the geological understanding of the block and allow for further development and derisking of future exploration prospects.
In the Lower Magdalena Valley, on the VIM-1 block, operated by our joint venture partner Parex Resources, the La Belleza-1 exploration well has drilled to over 10,000 feet depth with a target drilling depth of over 12,000 feet. Drilling is on time and on budget with results expected before year end.
In October 2019, the Company began drilling the Hamaca-39 horizontal water disposal well in the Hamaca exploitation area on the CPE-6 block. The well reached a MD of 6,163 feet, and was completed and injection tested successfully. This well is important for water disposal capacity in the Hamaca field as facilities are expanded to allow for increased production.
Third Quarter Conference Call Details:
As previously disclosed, a conference call for investors and analysts will be held on Friday, November 8, 2019 at 8:00 a.m. (MST), 10:00 a.m. (EST/GMT-5). Participants will include Gabriel de Alba, Chairman of the Board of Directors; Richard Herbert, Chief Executive Officer; David Dyck, Chief Financial Officer; and select members of the senior management team.
Analysts and investors are invited to participate using the following dial-in numbers:
Participant Number (International/Local): |
647-427-7450 |
Participant Number (Toll free Colombia): |
01-800-518-0661 |
Participant Number (Toll free North America): |
1-888-231-8191 |
Conference ID: |
9998073 |
Webcast Audio: |
A replay of the conference call will be available until 11:59 p.m. (EST/GMT-5) Friday, November 22, 2019.
Encore Toll Free Dial-in Number: |
1-855-859-2056 |
Local Dial-in Number: |
416-849-0833 |
Encore ID: |
9998073 |
About Frontera:
Frontera Energy Corporation is a Canadian public company and a leading explorer and producer of crude oil and natural gas, with operations focused in South America. The Company has a diversified portfolio of assets with interests in more than 40 exploration and production blocks in Colombia, Peru, Ecuador and Guyana. The Company's strategy is focused on sustainable growth in production and reserves. Frontera is committed to conducting business safely, in a socially and environmentally responsible manner. Frontera's common shares trade on the Toronto Stock Exchange under the ticker symbol "FEC".
If you would like to receive News Releases via e-mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.
Advisories:
Cautionary Note Concerning Forward-Looking Statements
This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of the corporate strategy, production, revenue and other financial results, cash flow and costs, future income generation capacity, reserve and resource estimates, potential resources and reserves, regulatory approvals, the Company's exploration and development plans and objectives, including its drilling plans and the timing thereof, expectations regarding the Company's inventory levels and the impact of timing and nomination of cargoes thereon, cost savings initiatives and G&A savings and timing of payment of dividends) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company's prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates or has investments; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 13, 2019 filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.
This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected capital expenditures, Operating EBITDA and financial results for the Company in 2019), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws.
In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.
Non-IFRS Financial Measures
This news release contains financial terms that are not considered in the International Financial Reporting Standards ("IFRS"): Operating EBITDA, Operating Netback, and Net Sales. These non-IFRS measures do not have any standardized meaning, and therefore are unlikely to be comparable to similar measures presented by other companies. These non-IFRS measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity.
Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets. Operating EBITDA represents the operating results of the Company's primary business, excluding the effects of capital structure, other investments (infrastructure assets), non-cash items that depend on accounting policy choices, and one-time items that are not expected to recur.
A reconciliation of Operating EBITDA to net income (loss) is as follows:
Three Months Ended |
|||
(in thousands of US$) |
September 30, |
June 30, |
September 30, |
Net (loss) income (1) |
(49,117) |
227,809 |
45,105 |
Share-based compensation |
1,314 |
1,145 |
1,042 |
Depletion, depreciation and amortization |
94,019 |
99,092 |
78,041 |
Impairment and exploration expenses |
46,391 |
16,863 |
59,071 |
Restructuring, severance and other costs |
5,463 |
2,048 |
2,108 |
Share of income from associates |
(17,183) |
(19,753) |
(19,239) |
Foreign exchange loss (gain) |
3,735 |
(1,681) |
1,094 |
Finance income |
(5,580) |
(5,469) |
(7,567) |
Finance expenses |
19,732 |
14,644 |
13,626 |
Unrealized gain on risk management contracts |
(4,338) |
(6,460) |
(61,830) |
Other loss, net |
1,359 |
497 |
2,606 |
Income tax expense (recovery) |
29,899 |
(156,772) |
(19,817) |
Non-controlling interests |
461 |
9,196 |
(164) |
Reversal of provision related to high-price clause |
— |
— |
(21,832) |
Fees paid on suspended pipeline capacity |
— |
— |
5,633 |
Payments under terminated pipeline contracts |
— |
— |
15,578 |
Operating EBITDA |
126,155 |
181,159 |
93,455 |
1Net income (loss) attributable to equity holders of the Company. |
|||
2019 |
2018 |
||||
(in thousands of US$) |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Financial and Operational results: |
|||||
Operating EBITDA |
126,155 |
181,159 |
144,855 |
118,398 |
93,455 |
Netbacks
Management believes that Netback is a useful measure to assess the net profit after all the costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel. Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less production costs, high price royalties and royalties paid in cash, and transportation and diluent costs, and shows how efficient the Company is at extracting and selling its product. Refer to the "Operating Netback" section on page 7 of the MD&A.
Net Sales
Net sales is a non-IFRS subtotal that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. This is a useful indicator for management as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these risk management activities. The exclusion of diluent cost is helpful to understand the Company's sales performance based on the net realized proceeds from production net of dilution, the cost of which is partially recovered when the blended product is sold. Net sales does not include the sales and purchases of oil and gas for trading as the gross margins from these activities are not considered significant or material to the Company's operations. Refer to the reconciliation in the "Sales" section on page 8 of the MD&A.
Please see the MD&A for additional information about these financial measures.
Well Test Results and Production Levels
Disclosure of well tests results in this news release should be considered preliminary until detailed pressure transient analysis and well-test interpretations have been completed. Hydrocarbons can be seen during the drilling of a well in numerous circumstances and do not necessarily indicate a commercial discovery or the presence of commercial hydrocarbons in a well. There is no representation by the Company that the disclosed well results included in this news release are necessarily indicative of long-term performance or ultimate recovery. As a result, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company or that such rates are indicative of future performance of the well.
In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.
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 to barrels 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, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy.
Definitions:
bbl(s) |
Barrel(s) of oil |
bbl/d |
Barrel of oil per day |
boe |
Refer to "Boe Conversion" disclosure above |
boe/d |
Barrel of oil equivalent per day |
LWD |
Logging While Drilling |
Mcf |
Thousand cubic feet |
MD |
Measured Depth |
SOURCE Frontera Energy Corporation
Grayson Andersen, Corporate Vice President, Capital Markets, +57-314-250-1467, [email protected], www.fronteraenergy.ca
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