FRONTERA ANNOUNCES FOURTH QUARTER AND YEAR END 2023 RESULTS
Recorded Full Year
Delivered Full Year Average Daily Production of 40,919 Boe/d
Generated Full Year Operating EBITDA of
Generated Full Year Adjusted Infrastructure EBITDA of
Declared Quarterly Dividend of
Recorded 164.1
7.3 Year 1P and 11.0 Year 2P Gross Reserves Life Index
514-628 Mmboe PMean Unrisked Gross Prospective Resources Estimated in Maastrichtian Horizons in the Northern Portion of the Corentyne Block
"During 2023, Frontera continued to take concrete steps to deliver significant value to shareholders
. The Company delivered EBITDA of $467MM, at the higher end of guidance for 2023, closing the year with a strong balance sheet including
Our significant Infrastructure business generated Adjusted Infrastructure EBITDA of approximately
Frontera recently announced the initiation of a new quarterly dividend and remains committed to enhancing shareholder returns. The Company will continue to consider future shareholder value enhancement initiatives in 2024 and beyond, including potential additional dividends, distributions, or bond buybacks, based on the overall results of our businesses and strategic goals ."
"Frontera successfully achieved its strategic, capital and production targets across the Company's three core businesses in 2023:
Through our
Our commitment to sustained production and value over volumes continues to be supported by our upstream
In our standalone and growing infrastructure business, we generated full year Adjusted Infrastructure EBITDA of approximately
In our potentially transformational
Frontera is committed to sustainability and achieved 108% of its 2023 ESG goals. We started the operation of our first solar farm named "Ikotia" in December which we expect will reduce CPE-6 power consumption from the grid and offset 50% of the block's scope 1 emissions.
As we turn now to 2024, we remain focused on executing our recently announced 2024 plan and continuing to deliver sustainable value-focused production, strong operational and financial results, and driving shareholder returns."
Fourth Quarter and Full Year 2023 Operational and Financial Summary
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Year ended
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Q4 2023 |
Q3 2023 |
Q4 2022 |
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2023 |
2022 |
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Operational Results |
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Heavy crude oil production (1) |
(bbl/d) |
23,002 |
24,097 |
22,144 |
|
23,359 |
21,441 |
|||||
Light and medium crude oil combined production (1) |
(bbl/d) |
13,795 |
13,964 |
17,073 |
|
14,856 |
17,274 |
|||||
Total crude oil production |
(bbl/d) |
36,797 |
38,061 |
39,217 |
|
38,215 |
38,715 |
|||||
Conventional natural gas production (1) |
(mcf/d) |
4,760 |
5,250 |
9,097 |
|
6,042 |
9,741 |
|||||
Natural gas liquids production (1) |
(boe/d) |
1,635 |
1,820 |
993 |
|
1,644 |
958 |
|||||
Total production (2) |
(boe/d) (3) |
39,267 |
40,802 |
41,806 |
|
40,919 |
41,382 |
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Total inventory balance |
(bbl) |
1,076,394 |
1,330,418 |
1,238,780 |
|
1,076,394 |
1,238,780 |
|||||
Brent price reference |
($/bbl) |
82.85 |
85.92 |
88.63 |
|
82.17 |
99.04 |
|||||
Oil and gas sales, net of purchases (4) (5) |
($/boe) |
75.76 |
78.48 |
82.60 |
|
72.93 |
91.39 |
|||||
Premiums paid on oil price risk management contracts (6) |
($/boe) |
(0.69) |
(0.59) |
(1.32) |
|
(0.80) |
(1.22) |
|||||
Royalties (6) |
($/boe) |
(1.79) |
(3.76) |
(6.04) |
|
(2.98) |
(7.83) |
|||||
Net sales realized price (4) (5) |
($/boe) |
73.28 |
74.13 |
75.24 |
|
69.15 |
82.34 |
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Production costs (excluding energy cost), net of realized FX hedge impact (4)(5) |
($/boe) |
(9.69) |
(8.82) |
(8.48) |
|
(8.76) |
(8.79) |
|||||
Energy costs, net of realized FX hedge impact (4)(5) |
($/boe) |
(5.06) |
(5.04) |
(3.08) |
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(4.49) |
(3.35) |
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Transportation costs, net of realized FX hedge impact (4)(5) |
($/boe) |
(11.02) |
(11.73) |
(10.55) |
|
(11.21) |
(10.44) |
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Operating netback per boe (4)(5) |
($/boe) |
47.51 |
48.54 |
53.13 |
|
44.69 |
59.76 |
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Financial Results |
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Oil & gas sales, net of purchases (7) |
($M) |
240,105 |
254,805 |
260,824 |
|
905,249 |
1,105,503 |
|||||
Premiums paid on oil price risk management contracts |
($M) |
(2,198) |
(1,930) |
(4,182) |
|
(9,903) |
(14,733) |
|||||
Royalties |
($M) |
(5,683) |
(12,216) |
(19,076) |
|
(36,949) |
(94,709) |
|||||
Net sales (7) |
($M) |
232,224 |
240,659 |
237,566 |
|
858,397 |
996,061 |
|||||
Net income (8) |
($M) |
92,038 |
32,582 |
197,796 |
|
193,497 |
286,615 |
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Per share – basic |
($) |
1.08 |
0.38 |
2.29 |
|
2.27 |
3.16 |
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Per share – diluted |
($) |
1.04 |
0.37 |
2.25 |
|
2.19 |
3.08 |
|||||
General and administrative |
($M) |
16,891 |
11,925 |
12,761 |
|
53,907 |
55,063 |
|||||
Outstanding Common Shares |
Number of |
85,151,216 |
85,431,716 |
85,592,075 |
|
85,151,216 |
85,592,075 |
|||||
Operating EBITDA (7) |
($M) |
121,036 |
137,800 |
144,994 |
|
467,219 |
641,877 |
|||||
Cash provided by operating activities |
($M) |
73,432 |
153,957 |
138,312 |
|
411,794 |
620,479 |
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Capital expenditures (7) |
($M) |
82,292 |
74,130 |
134,165 |
|
442,734 |
417,563 |
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Cash and cash equivalents – unrestricted |
($M) |
159,673 |
189,190 |
289,845 |
|
159,673 |
289,845 |
|||||
Restricted cash short and long-term (9) |
($M) |
30,300 |
32,048 |
23,202 |
|
30,300 |
23,202 |
|||||
Total cash (9) |
($M) |
189,973 |
221,238 |
313,047 |
|
189,973 |
313,047 |
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Total debt and lease liabilities (9) |
($M) |
536,822 |
525,517 |
511,552 |
|
536,822 |
511,552 |
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Consolidated total indebtedness (excluding Unrestricted Subsidiaries) (10) |
($M) |
430,170 |
409,853 |
407,808 |
|
430,170 |
407,808 |
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Net debt (excluding Unrestricted Subsidiaries) (10) |
($M) |
318,092 |
271,508 |
178,534 |
|
318,092 |
178,534 |
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(1) References to heavy crude oil, light and medium crude oil combined, conventional natural gas and natural gas liquids in the above table and elsewhere in this news release refer to the heavy crude oil, light crude oil and medium crude oil combined, conventional natural gas and natural gas liquids, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). |
(2) Represents W.I. production before royalties. Refer to the "Further Disclosures" section on page 44 of the Company's MD&A for the fiscal year ended |
(3) Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the |
(4) Non-IFRS ratio (equivalent to a "non-GAAP ratio", as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112" ). Refer to the "Non-IFRS and Other Financial Measures'' section on page 27 of the MD&A. |
(5) 2022 prior period figures are different compared with those previously reported as a result of the exclusion of Promotora Agricola de los |
(6) Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 27 of the MD&A. |
(7) Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 27 of the MD&A. |
(8) Net income (loss) attributable to equity holders of the Company. |
(9) Capital management measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 27 of the MD&A. |
(10) "Unrestricted Subsidiaries" include |
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Fourth Quarter and Full Year Operational and Financial Results:
- The Company recorded net income of
$92.0 million or$1.04 /share in the fourth quarter of 2023, compared with net income of$32.6 million or$0.37 /share in the prior quarter and net income of$197.8 million or$2.25 /share in the fourth quarter of 2022. For the year endedDecember 31, 2023 , the Company reported net income of$193.5 million , compared to net income of$286.6 million for the year endedDecember 31, 2022 . - Production averaged 39,267 boe/d in the fourth quarter 2023 (consisting of 23,002 bbl/d of heavy crude oil, 13,795 bbl/d of light and medium crude oil combined, 4,760 mcf/d of conventional natural gas and 1,635 boe/d of natural gas liquids) compared to 40,802 boe/d in the prior quarter and 41,806 boe/d in the fourth quarter of 2022, lower production during the quarter was a result of lower planned drilling and workover activity in the fourth quarter, natural decline, and unplanned maintenance on an injector well in Quifa. In 2023, Frontera's production averaged 40,919 boe/d (consisting of 23,359 bbl/d of heavy crude oil, 14,856 bbl/d of light and medium crude oil combined, 6,042 mcf/d of conventional natural gas and 1,644 boe/d of natural gas liquids), within the Company's 2023 guidance of 40,000-43,000 boe/d.
- Operating EBITDA was
$121.0 million in the fourth quarter of 2023 compared with$137.8 million in the prior quarter and$145.0 million in the fourth quarter of 2022. The decrease in operating EBITDA quarter over quarter was primarily a result of lower commodity prices and lower volumes sold in the fourth quarter. Frontera's weighted average Brent price was$81.88 /bbl in 2023, generating$467.2 million of EBITDA. - Cash provided by operating activities in the fourth quarter of 2023 was
$73.4 million , compared with$154.0 million in the prior quarter and$138.3 million in the fourth quarter of 2022. The decrease quarter over quarter was primarily due to changes in working capital mainly related to income taxes withheld, lower commodity prices and volumes sold. - The Company reported a total cash position of
$190.0 million atDecember 31, 2023 , compared to$221.2 million atSeptember 30, 2023 and$313.0 million atDecember 31, 2022 . The Company generated$411.8 million of cash from operations in 2023, compared to$620.5 million in 2022. During the year, the Company primarily invested$442.7 million in capital expenditures, including$153.7 million related to the Wei-1,$12.7 million related to the acquisition of the IFC interest on ODL,$56.9 million in net debt service payments and$5.9 million in share buyback. - As at
December 31, 2023 , the Company had a total crude oil inventory balance of 1,076,394 bbls compared to 1,330,418 bbls atSeptember 30, 2023 . As ofDecember 31, 2023 , the Company had a total inventory balance inColombia of 551,715 barrels, including 322,639 crude oil barrels and 229,076 barrels of diluent and others. This compared to 812,797 as ofSeptember 30, 2023 , and 683,416 barrels as atDecember 31, 2022 . The decrease in inventory balance was primarily due to inventory drawn for export sales. Inventory balances in the fourth quarter related toEcuador andPeru were 44,479 barrels and 480,200 barrels, respectively. - Capital expenditures were approximately
$82.3 million in the fourth quarter of 2023, compared with$74.1 million in the prior quarter and$134.2 million in the fourth quarter of 2022. During the fourth quarter, the Company drilled 14 development wells at its Quifa SW, Cajua and CPE-6 blocks as well as one exploration well,Perico Norte -A4 on the Perico block inEcuador . For the full year 2023, the Company executed approximately$442.7 million in total capital spending, including$157.3 million in total capital spending related to the Wei-1 well, within its 2023 capital guidance of$420-475 million and compared to$417.6 million in 2022. - The Company's net sales realized price was
$73.28 /boe in the fourth quarter of 2023, compared to$74.13 /boe in the prior quarter and$75.24 /boe in the fourth quarter of 2022. The decrease in net sales realized price quarter-over-quarter was primarily driven by the decrease in Brent benchmark oil price compared with the previous quarter, partially offset by lower royalties. The Company's net sales realized price in 2023 was$69.15 /boe, compared to$82.34 /boe in 2022. - The Company's operating netback was
$47.51 /boe in the fourth quarter of 2023, compared with$48.54 /boe in the prior quarter and$53.13 /boe in the fourth quarter of 2022. The decrease in operating netback quarter-over-quarter was primarily due to a lower net sales realized price and, higher production costs, resulting from higher well services activity costs and higher energy costs. The Company's operating netback for the year endedDecember 31, 2023 , was$44.69 /boe, compared to$59.76 /boe in 2022. - Production costs (excluding energy cost), net of realized FX hedge impact, averaged
$9.69 /boe in the fourth quarter of 2023, compared with$8.82 /boe in the prior quarter and$8.48 /boe in the fourth quarter of 2022. The increase quarter over quarter was due to higher technical assistance and maintenance costs, partially offset by lower cost associated to well services activities. Frontera's total production costs, including energy cost, net of realized FX hedge impact, averaged$13.25 /boe in 2023, within the Company's 2023 guidance range of$12.50-$13.50 /boe. - Transportation costs averaged
$11.02 /boe in the fourth quarter of 2023, compared with$11.73 /boe in the prior quarter and up from$10.55 /boe in the fourth quarter of 2022. The decrease during the quarter was mainly due to an increase in local sales volumes to the thermal market. Frontera's transportation costs averaged$11.21 /boe in 2023, within the Company's 2023 guidance range of$10.50-$11.50 /boe. - Total ODL volumes transported were 252,810 bbl/d during the fourth quarter of 2023, up 13% versus the fourth quarter of 2022. Total volumes transported through ODL for 2023 were 243,617 and received capital distributions of
$47 million during the year. -
Puerto Bahia liquids volumes were 52,754 bbl/d during the fourth quarter down 21% compared to the third quarter of 2022, driven mainly by lower imported crude volumes, and 60,718 bbl/d for the full year 2023 compared to 62,422 bbl/d in 2022.Puerto Bahia liquids revenues were$7.6 million during the fourth quarter, up 12% compared to the fourth quarter of 2022, mainly due to higher tariffs. For the full year 2023,Puerto Bahia liquids revenues were$32.1 million compared to$29.6 million in 2022, mainly due to higher tariffs. - Adjusted Infrastructure EBITDA in the fourth quarter of 2023 was
$30.7 million , compared with$26.6 million in the fourth quarter of 2022, and$119.8 million for the full year 2023. - In the Company's exciting Guyana Exploration business, the discovery of 228 feet of net pay in Kawa-1 and 114 feet of net pay in Wei-1, on North Corentyne was confirmed. Results further demonstrate the potential for a standalone shallow oil resource development across the Corentyne block.
- Total costs associated for the Wei-1 well are now estimated to be
$189 million following the successful implementation of several cost saving initiatives. Frontera's direct and indirect WI in the Corentyne block is estimated at up to 72.52% and 93.42%, respectively. - During the fourth quarter of 2023, the Company repurchased for cancellation 280,500 Common Shares at a cost of approximately
$1.7 million .
Frontera announced the results of its annual independent reserves assessment for the year ended
Key Highlights:
- Added 4.2 MMboe of 2P gross reserves, for total Company 2P gross reserves of 164.1 MMboe consisting of 64% heavy crude oil, 24% light and medium crude oil, 8% conventional natural gas and 4% natural gas liquids, compared to 174.8 MMboe at
December 31, 2022 . - 2023 year-end gross proved developed producing reserves increased by 2% to 40.0 MMboe and the proved developed producing reserves replacement ratio was 105%.
- Delivered three-year average gross PDP, 1P and 2P Reserves Replacement Ratio of 129%, 104% and 79%, respectively.
Reserves Replacement Ratio (%) |
PDP Reserves |
1P Reserves |
2P Reserves |
2021 |
133 % |
175 % |
131 % |
2022 |
150 % |
52 % |
77 % |
2023 |
105 % |
85 % |
28 % |
Three-year average |
129 % |
104 % |
79 % |
- Delivered a 1P gross reserves life index of 7.3 years compared to 7.4 years at
December 31, 2022 , and a 2P reserves life index of 11.0 years compared to 11.6 years atDecember 31, 2022 . - The NPV of the Company's 2P reserves, discounted at 10% before tax, is
$3.5 billion ($21.60 /2P boe) atDecember 31, 2023 , compared to$3.7 billion ($21.24 /2P boe) atDecember 31, 2022 . The decrease in NPV10 for the 2P reserves is primarily due to a decrease in the forecast oil price used to calculate the NPV10, however the NPV10 per boe increased by 2% driven by operational efficiencies and reduced future development costs. - Reduced the future development cost for 2P reserves by
$300 million to$1.2 billion atDecember 31, 2023 , compared to$1.5 billion atDecember 31, 2022 . The reduction is primarily due to the Company's focus on sustained production, value over volumes and an optimized development plan.
2023 Year-End D&M Certified Gross Reserves Volumes(1)
Reserves Category |
|
MBoe (2) |
Percentage Change |
Proved Developed Producing (PDP) |
39,976 |
39,287 |
2 % |
Proved Developed Non-Producing (PDNP) |
7,864 |
9,951 |
(21 %) |
Proved Undeveloped (PUD |
60,889 |
61,774 |
(1 %) |
Total Proved (1P) |
108,729 |
111,013 |
(2 %) |
Probable |
55,363 |
63,752 |
(13 %) |
Total Proved Plus Probable (2P) |
164,092 |
174,765 |
(6 %) |
Possible (3) |
36,563 |
43,770 |
(16 %) |
Total Proved Plus Probable Plus Possible (3P) |
200,654 |
218,535 |
(8 %) |
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(1) Gross reserves represent Frontera's W.I. before royalties. |
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(2) See "Boe Conversion" section in the "Advisories", at the end of this press release. |
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(3) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. |
Frontera achieved 108% of its 2023 Sustainability Goals, started the operation of its first solar farm (Ikotia) in December that will reduce almost 8,000 TCO2e from the power generation in CPE6 in 2024 and offset 50% of its scope 1 emissions. The Company also completed 5,737 cumulative hectares preserved and restored in key connectivity corridors in Casanare and Meta (
The Company invested approximately $5.5 million in education, including economic development, and quality of life initiatives, benefiting 94,875 people through 256 social projects in Colombia,
Since 2018, Frontera has returned more than
NCIB: Under the Company's current NCIB which commenced on
Dividend: Pursuant to Frontera's dividend policy, Frontera's Board of Directors has declared a dividend of
Frontera's three core businesses include: (1) its
During the fourth quarter of 2023, Frontera produced 37,814 boe/d from its Colombian operations (consisting of 23,002 bbl/d of heavy crude oil, 12,342 bbl/d of light and medium crude oil, 4,760 mcf/d of conventional natural gas and 1,635 boe/d of natural gas liquids).
In the fourth quarter of 2023, the Company drilled 13 development wells at its Quifa and CPE-6 blocks well services at 11 others.
For the year ended
Currently, the Company has 4 drilling rigs active at its Quifa and CPE-6 blocks in
At Quifa, fourth quarter 2023 production averaged approximately 16,452 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company drilled 8 wells on the block in the fourth quarter of 2023. The Company also invested in new flow lines in the Quifa block to integrate the SAARA project. The Company's current water handling capacity in Quifa is approximately 1.5 million bwpd.
During the fourth quarter 2023, Frontera continued with its recommissioning efforts supporting SAARA, its reverse osmosis water treatment facility. As of year-end 2023, the plant had processed 20.6 million barrels of water as part of its recommissioning program, providing irrigation source water to the Company's nearby ProAgrollanos palm oil plantation. In 2024, Frontera successfully completed the pilot phase of the SAARA project with Ecopetrol. The Company intends to invest in the commissioning of the first phase of the project, the stabilization phase, to reach a minimum of 250,000 barrels of water per day available for the Quifa block, subject to final JV approval.
At CPE-6, fourth quarter 2023 production averaged approximately 6,162 bbl/d of heavy crude oil, increasing 18% from 5,214 bbl/d at year end 2022. The Company drilled 5 development wells. Additionally, the Company invested in new flow lines and in the expansion and improvement of the development facilities in CPE-6 block, which doubled the water-handling capacity from 120,000 to 240,000 bwpd.
At Guatiquia, production during the fourth quarter 2023 averaged 6,206 bbl/d of light and medium crude compared with 6,763 bbl/d in the third quarter of 2023.
In the Cubiro Block production averaged 1,535 bbl/d of light and medium crude oil in the fourth quarter of 2023 compared with 1,729 bbl/d in the third quarter 2023.
At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,775 boe/d of light and medium crude oil in the fourth quarter of 2023 compared to approximately 1,798 boe/d of light and medium crude oil in the third quarter of 2023.
The Company's exploration focus remains on the
Additionally, during the year 2023, the Company received approval from the Agencia Nacional de Hidrocarburos ("ANH") to terminate by mutual agreement the CR-1 and COR-24 contracts, which reduced exploratory commitments by
In
In the Perico Block, (Frontera 50% W.I. and operator), the Company spudded the Perico Norte-4 well on
The Perico Centro-1 well (formerly Jandiayacu-1) was spud on
The Perico Norte A-3 (formerly Yin-2) appraisal well was drilled in July, discovering 48 feet of net pay in the Lower U sand and 24 feet net pay in the Hollin main formation.
Frontera is currently conducting long-term testing and preparing the environmental impact assessments in order to obtain a production environmental license at the Perico Norte-1 (formerly Jandaya-1),
At the Espejo block (Frontera 50% W.I. and non-operator), the Company expects to drill two exploration wells, targeting the Lower U Ss and M1 Ss.
In 2024, Frontera anticipates investing
- VIM-1 block (Frontera 50% non-operator): the Company anticipates spudding the high-impact Hydra-1 exploration well mid-2024. The Hydra-1 well will be drilling using new seismic processing technology and will target gas and condensate.
-
Espejo Block (Frontera 50% non-operated): the Company will drill two exploratory wells which target plays successfully tested in nearby areas. - LLA119 block (Frontera 100%): the Company plans to complete 80 sqkm of 3D seismic data, complete pre-drilling activities and commence civil works.
- LLA99 and VIM46 block (Frontera 100%): the Company intends to complete pre-seismic and pre-drilling activities ahead of 3D seismic acquisition.
Frontera has investments in certain significant infrastructure and midstream assets seeking to capture stable and long-term revenue streams, including storage, port, and other facilities in
The Company's Infrastructure Colombia Segment income increased by
Cash provided by operating activities of the Infrastructure Colombia Segment for three months ended
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Three months ended |
Year ended |
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($M) |
2023 |
2022 |
2023 |
2022 |
Revenue |
10,954 |
12,209 |
48,263 |
46,883 |
Liquids port facility |
7,591 |
6,750 |
32,082 |
29,550 |
|
1,719 |
2,096 |
7,379 |
7,261 |
Third party liquids port facility |
5,872 |
4,654 |
24,703 |
22,289 |
|
3,363 |
5,459 |
16,181 |
17,333 |
Cost |
(5,864) |
(5,685) |
(23,133) |
(21,376) |
General administrative expenses |
(951) |
(1,376) |
(5,148) |
(5,375) |
Depletion, depreciation, and amortization |
(1,570) |
(1,233) |
(5,562) |
(5,617) |
Restructuring, severance, and other costs |
(446) |
(1,116) |
(1,547) |
(2,229) |
|
2,123 |
2,799 |
12,873 |
12,286 |
Share of Income from associates ODL |
14,833 |
12,135 |
56,476 |
42,043 |
Segment income |
16,956 |
14,934 |
69,349 |
54,329 |
Segment cash flow from operating activities |
7,639 |
12,796 |
54,516 |
46,898 |
|
Three months ended |
Year ended |
||
($M) |
2023 |
2022 |
2023 |
2022 |
Adjusted Infrastructure Revenue (1) |
43,951 |
38,355 |
169,142 |
113,583 |
Adjusted Infrastructure Operating Cost (1) |
(10,287) |
(8,950) |
(38,216) |
(29,720) |
Adjusted Infrastructure General and Administrative (1) |
(2,973) |
(2,847) |
(11,105) |
(8,970) |
Adjusted Infrastructure EBITDA (1) |
30,691 |
26,558 |
119,821 |
74,893 |
(1) |
Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures''. |
The following table shows the volumes pumped per injection point in ODL:
|
Three months ended |
Year ended |
||
(bbl/d) |
2023 |
2022 |
2023 |
2022 |
At |
173,888 |
150,634 |
169,701 |
140,393 |
At Jagüey and |
78,922 |
72,221 |
73,916 |
72,666 |
Total |
252,810 |
222,855 |
243,617 |
213,059 |
The following table shows throughput for the liquids port facility at Puerto Bahia:
|
Three months ended |
Year ended |
||
(bbl/d) |
2023 |
2022 |
2023 |
2022 |
|
11,971 |
13,575 |
12,863 |
13,292 |
Third party volumes |
40,783 |
53,142 |
47,855 |
49,130 |
Total |
52,754 |
66,717 |
60,718 |
62,422 |
Frontera anticipates breaking ground on the connection construction during the first quarter of 2024 and connection start-up by the end of 2024. Frontera has secured an additional
As disclosed in the
On
As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40-60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio. Consistent with this strategy, the Company entered new put hedges totaling 2,574,826 bbls to protect a portion of the Company's production through
Term |
Type of Instrument |
Open Positions (bbl/d) |
Strike Prices Put/Call |
|
Put |
13,823 |
80.00 |
|
Put |
13,601 |
72.00 |
|
Put |
13,497 |
72.00 |
1Q-2024 |
Total Average |
13,641 |
74.76 |
|
Put |
14,711 |
72.00 |
|
Put |
14,586 |
72.00 |
|
Put |
14,667 |
72.00 |
2Q-2024 |
Total Average |
14,653 |
72.00 |
The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of
Term |
Type of Instrument |
Open Interest (US$ MM) |
Strike Prices Put/ Call |
Hedging Ratio |
|
1Q-2024 |
Zero-cost Collars |
60 |
4,125 / 4,763 |
40 % |
|
2Q-2024 |
Zero-cost Collars |
60 |
4,125 / 4,763 |
40 % |
|
Oct, 2024 |
Forward |
17 |
4,386 |
|
|
The following tables provide a summary of the Company's oil and natural gas reserves based on forecast prices and costs effective
2023 2P Reserves Reconciliation
|
Oil Equivalent |
|
174.8 |
Discoveries(3) |
4.6 |
Extensions & Improved Recovery |
0.0 |
Technical Revisions(4) |
2.4 |
Acquisitions |
0.0 |
Dispositions(5) |
(0.1) |
Economic Factors(6) |
(2.7) |
Production(7) |
(14.9) |
|
164.1 |
|
|
|
(1) See "Boe Conversion" section in the "Advisories", at the end of this press release. |
|
(2) Gross refers to Frontera's W.I. before royalties. Net refers to Frontera's W.I. after royalties. |
|
(3) Includes U reservoir in Perico fields and |
|
(4) Includes technical revisions mainly in the Hamaca field (in the CPE-6 block) and Copa trend fields (Cubiro block) |
|
(5) Adjustments in Arauco field returned to ANH and Dina Terciarios (Neiva field) for contract end. |
|
(6) Evaluation prices impact in the economic limit/reserves of several fields, mainly Jaspe field in the Quifa block |
|
(7) Production represents the Company's production for the twelve-month period ended |
Gross Reserve Life Index ("RLI")(1)
(US$/bbl) |
|
|
Total Proved (1P) |
7.4 years |
7.3 years |
Total Proved Plus Probable (2P) |
11.6 years |
11.0 years |
Total Proved Plus Probable Plus Possible (3P) |
14.5 years |
13.5 years |
|
|
|
(1) RLI does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. |
|
(2) Calculated by dividing the total relevant gross reserves category by the 2022 production of 15.1 MMboe. |
|
(3) Calculated by dividing the total relevant gross reserves category by the 2023 production of 14.9 MMboe. |
Net Present Value of Future Net Revenue Before Tax Summary - D&M Reserves Report (2023 Brent Forecast)(1)
Reserves Category |
|
|
|
$ (000's), except per share data |
NPV10 ( |
NPV10 ( |
NPV10 (C$/share)(4) |
Proved Developed Producing (PDP) |
1,118,382 |
981,636 |
15.27 |
Proved Developed Non-Producing (PDNP) |
288,281 |
226,047 |
3.52 |
Proved Undeveloped |
1,029,911 |
1,124,358 |
17.49 |
Total Proved (1P) |
2,436,575 |
2,332,041 |
36.27 |
Probable |
1,277,388 |
1,212,175 |
18.85 |
Total Proved Plus Probable (2P) |
3,713,962 |
3,544,216 |
55.13 |
Possible (5) |
1,064,195 |
862,919 |
13.42 |
Total Proved Plus Probable Plus Possible (3P) |
4,778,157 |
4,407,135 |
68.55 |
|
|
|
(1) See "Advisories" at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ, McDaniel and Sproule. The full |
|
(2) Includes future development costs ("FDC") as at |
|
(3) Includes FDC as at |
|
(4) Calculated by dividing the |
|
(5) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. |
Future Development Costs (FDC) - Based on Forecast Prices and Costs(1)
( |
Total Proved (1P) |
Total Proved Plus Probable (2P) |
2024 |
138,997 |
160,116 |
2025 |
193,534 |
268,669 |
2026 |
162,586 |
230,232 |
2027 |
141,061 |
187,939 |
2028 |
136,062 |
223,370 |
Beyond 2027 |
40,193 |
142,760 |
Total undiscounted |
812,432 |
1,213,087 |
|
(1) Does not include |
The Company's 2023 year-end estimated reserves were evaluated by D&M in their report dated
Additional reserves information as required under NI 51-101 will be included in the Company's statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on
Fourth Quarter and Year-end 2023 Conference Call Details
A conference call for investors and analysts will be held on
Analysts and investors are invited to participate using the following dial-in numbers:
Participant Number ( |
1-888-644-6383 |
Participant Number (Toll Free Colombia): |
01-800-518-4036 |
Participant Number (International): |
1-416-764-8650 |
Conference ID: |
01718743 |
Webcast Audio: |
A replay of the conference call will be available until
Encore Toll free Dial-in Number: |
1-888-390-0541 |
International Dial-in Number: |
1-416-764-8677 |
Encore ID: |
718743 |
If you would like to receive news releases via email as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.
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This news release contains forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to activities, events, or developments that the Company believes, expects, or anticipates will or may occur in the future. Forward-looking information in this news release includes, without limitation, statements regarding the Company's continued commitment to enhancing shareholder returns and its efforts to unlock shareholder value; statements regarding the payment of dividends, statements regarding expected reductions in grid power consumption and offset emissions stemming from the Company's solar farm; statements regarding the Company's intended investment in the SAARA project, including expectations regarding the results of such investment; anticipated exploration, activities in the Company's core upstream
Forward-looking information reflects the current expectations, assumptions and beliefs of the Company based on information currently available to it and considers the Company's experience and its perception of historical trends, including expectations and assumptions relating to commodity prices and interest and foreign exchange rates; the current and expected impacts of the COVID-19 pandemic, actions of the
Although the Company believes that the assumptions inherent in the forward-looking information are reasonable, forward-looking information is not a guarantee of future performance and accordingly undue reliance should not be placed on such information. Forward-looking information is subject to a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to the Company. The actual results may differ materially from those expressed or implied by the forward-looking information, 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. The Company's annual information form dated
This news release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52-112), "non-IFRS ratios" (equivalent to "non-GAAP ratios", as such term is defined in NI 52-112), "supplementary financial measures" (as such term is defined in NI 52-112), and "capital management measures" (as such term is defined in NI 52-112), which are described in further detail below. Such financial measures do not have standardized IFRS definitions. The Company's determination of these financial measures may differ from other reporting issuers, and they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these financial measures differently than we do, limiting their usefulness as comparative measures.
The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company's core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company's underlying operating performance. The Company's management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company's ability to finance its ongoing operations and obligations.
Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in this news release.
EBITDA is a commonly used non-IFRS financial measure that adjusts net (loss) income as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA is a non-IFRS financial measure that represents the operating results of the Company's primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.
Since the three and six months ended
The following table provides a reconciliation of net income to Operating EBITDA:
|
Three months ended
|
Year ended
|
||
($M) |
2023 |
2022 |
2023 |
2022 |
Net income (1) |
92,038 |
197,796 |
193,497 |
286,615 |
|
|
|
|
|
Finance income |
(2,270) |
(2,323) |
(9,984) |
(5,505) |
Finance expenses |
16,865 |
14,239 |
64,185 |
52,991 |
Income tax (recovery) expense |
(39,007) |
68,599 |
4,130 |
249,275 |
Depletion, depreciation and amortization |
68,411 |
49,198 |
278,269 |
195,419 |
Minimum work commitment paid |
358 |
— |
358 |
919 |
Expense (recovery) of asset retirement obligation |
(1,621) |
3,235 |
(25,622) |
(1,823) |
Expenses (recovery) of impairment |
1,417 |
(211,130) |
25,236 |
(205,833) |
Post-termination obligation |
11,160 |
5,229 |
18,814 |
12,299 |
Share-based compensation |
(745) |
3,213 |
96 |
7,777 |
Restructuring, severance and other costs |
3,744 |
2,624 |
8,548 |
4,463 |
Share of income from associates |
(14,833) |
(12,135) |
(56,476) |
(42,043) |
Foreign exchange loss (income) |
(2,724) |
28,230 |
(12,275) |
76,413 |
Other (income) loss |
(4,554) |
5,381 |
(8,936) |
10,800 |
Unrealized gain on risk management contracts |
(7,000) |
(6,600) |
(11,880) |
(4,310) |
Non-controlling interests |
(203) |
(562) |
(741) |
4,420 |
Operating EBITDA |
121,036 |
144,994 |
467,219 |
641,877 |
|
(1) Refers to net income attributable to equity holders of the Company. |
Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by the Company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration and evaluation assets expenditures which are items reconciled to the Company's Statements of Cash Flows for the period.
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Consolidated Statements of Cash Flows |
|
|
|
|
Additions to oil and gas properties, infrastructure port, and plant and equipment |
70,294 |
85,074 |
241,185 |
261,144 |
Additions to exploration and evaluation assets |
5,171 |
46,281 |
195,210 |
154,516 |
Total additions in Consolidated Statements of Cash Flows |
75,465 |
131,355 |
436,395 |
415,660 |
Non-cash adjustments (1) |
6,827 |
2,810 |
6,339 |
1,903 |
Total Capital Expenditures |
82,292 |
134,165 |
442,734 |
417,563 |
|
|
|
|
|
Capital Expenditures attributable to Infrastructure Colombia Segment |
7,867 |
718 |
11,407 |
2,573 |
Capital Expenditures attributable to other segments different to Infrastructure Colombia Segment |
74,425 |
133,447 |
431,327 |
414,990 |
Total Capital Expenditure |
82,292 |
134,165 |
442,734 |
417,563 |
|
(1) Related to material inventory movements, capitalized non-cash items and other adjustments. In addition, CPE-6 solar plant project is included as part of the Capital Expenditures, according to Guidance 2023. In the Consolidated Statements of Cash Flows is considered as non-cash adjustment. |
Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Cost and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL's revenue direct participation interest. Adjusted Infrastructure Operating Cost includes costs of the Infrastructure Colombia Segment including ODL's cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of Infrastructure Colombia Segment including ODL's general and administrative direct participation interest. A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Cost and Adjusted Infrastructure General and Administrative is provided below.
|
Three months ended
|
Year ended
|
||
($M) (1) |
2023 |
2022 |
2023 |
2022 |
Revenue Infrastructure Colombia Segment |
10,954 |
12,209 |
48,263 |
46,883 |
Revenue from ODL |
94,277 |
74,702 |
345,370 |
268,040 |
Direct participation interest in the ODL (1) |
35.00 % |
35.00 % |
35.00 % |
35.00 % |
Equity adjustment participation of ODL (2) |
32,997 |
26,146 |
120,879 |
66,700 |
Adjusted Infrastructure Revenues |
43,951 |
38,355 |
169,142 |
113,583 |
|
|
|
|
|
Operating cost Infrastructure Colombia Segment |
(5,864) |
(5,685) |
(23,133) |
(21,376) |
Operating Cost from ODL |
(12,637) |
(9,329) |
(43,094) |
(33,541) |
Direct participation interest in the ODL (1) |
35.00 % |
35.00 % |
35.00 % |
35.00 % |
Equity adjustment participation of ODL (2) |
(4,423) |
(3,265) |
(15,083) |
(8,344) |
Adjusted Infrastructure Operating Costs |
(10,287) |
(8,950) |
(38,216) |
(29,720) |
|
|
|
|
|
General and administrative Infrastructure Colombia Segment |
(951) |
(1,376) |
(5,148) |
(5,375) |
General and administrative from ODL |
(5,776) |
(4,204) |
(17,019) |
(14,329) |
Direct participation interest in the ODL (1) |
35.00 % |
35.00 % |
35.00 % |
35.00 % |
Equity adjustment participation of ODL (2) |
(2,022) |
(1,471) |
(5,957) |
(3,595) |
Adjusted Infrastructure General and Administrative |
(2,973) |
(2,847) |
(11,105) |
(8,970) |
|
(1) On |
|
(2) Revenues and expenses related to the ODL are accounted for using the equity method described in the Note 15 of the 2023 Annual Consolidated Financial Statements. |
Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company's production after subtracting all 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 and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its midstream segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the "Operating Netback" section on page 13 of the MD&A.
The following is a description of each component of the Company's operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining cost. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases divided by the total sales volumes, net of purchases.
A reconciliation of this calculation is provided below:
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Produced crude oil and gas sales ($M) (1) |
247,134 |
262,430 |
932,977 |
1,121,344 |
Purchased crude oil and products sales ($M) |
48,324 |
63,375 |
208,069 |
201,534 |
(-) Cost of purchases ($M) (2) |
(55,353) |
(64,981) |
(235,797) |
(217,375) |
Oil and gas sales, net of purchases ($M) |
240,105 |
260,824 |
905,249 |
1,105,503 |
Sales volumes, net of purchases - (boe) |
3,169,346 |
3,157,716 |
12,411,825 |
12,096,465 |
Oil and gas sales, net of purchases ($/boe) |
75.76 |
82.60 |
72.93 |
91.39 |
|
(1) Excludes sales from port services as they are not part of the oil and gas segment. For further information, refer to the "Infrastructure Colombia" section on page 24 of the MD&A. |
|
(2) Cost of third-party volumes purchased for use and resale in the Company's oil operations, including its transportation and refining costs. |
Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. 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 oil risk management activities. The deduction of cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the "Sales" section on page 14 of the MD&A.
Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes.
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Produced crude oil sales ($M) |
245,123 |
258,365 |
921,573 |
1,104,808 |
Purchased crude oil and products sales ($M) |
48,324 |
63,375 |
208,069 |
201,534 |
(-) Cost of purchases ($M) |
(55,353) |
(64,981) |
(235,797) |
(217,375) |
Conventional natural gas sales ($M) |
2,011 |
4,065 |
11,404 |
16,536 |
Oil and gas sales, net of purchases ($M) (1) |
240,105 |
260,824 |
905,249 |
1,105,503 |
Sales volumes, net of purchases - (bbl) |
3,118,407 |
3,003,102 |
12,042,019 |
11,456,143 |
Conventional natural gas sales volumes - (mcf) |
289,993 |
881,402 |
2,107,707 |
3,655,102 |
Realized oil price, net of purchases ($/bbl) |
76.35 |
85.50 |
74.23 |
95.06 |
Realized conventional natural gas price ($/mcf) |
6.93 |
4.61 |
5.41 |
4.52 |
|
(1) Non-IFRS financial measure. |
Net sales realized price
Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below:
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Oil and gas sales, net of purchases ($M) (1) |
240,105 |
260,824 |
905,249 |
1,105,503 |
(-) Premiums paid on oil price risk management contracts ($M) |
(2,198) |
(4,182) |
(9,903) |
(14,733) |
(-) Royalties ($M) |
(5,683) |
(19,076) |
(36,949) |
(94,709) |
Net sales ($M) |
232,224 |
237,566 |
858,397 |
996,061 |
Sales volumes, net of purchases - (boe) |
3,169,346 |
3,157,716 |
12,411,825 |
12,096,465 |
Oil and gas sales, net of purchases ($/boe) |
75.76 |
82.60 |
72.93 |
91.39 |
Premiums paid on oil price risk management contracts (2) |
(0.69) |
(1.32) |
(0.80) |
(1.22) |
Royalties ($/boe) (2) |
(1.79) |
(6.04) |
(2.98) |
(7.83) |
Net sales realized price ($/boe) |
73.28 |
75.24 |
69.15 |
82.34 |
|
(1) Non-IFRS financial measure. |
|
(2) Supplementary financial measure. |
Production costs (excluding energy cost), net of realized FX hedge impact is a non-IFRS financial measure that mainly includes lifting costs, activities developed in the blocks, and processes to put the crude oil and gas in sales condition and the realized gain or loss on foreign exchange risk management contracts attributable to production costs. Production cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using production cost (excluding energy cost), net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:
|
Three months ended |
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Production costs (excluding energy cost) ($M) |
37,122 |
32,628 |
139,917 |
132,758 |
(-)Realized gain on FX hedge attributable to production costs (excluding energy cost)($M)(1) |
(2,101) |
— |
(9,075) |
— |
Production costs (excluding energy cost), net of realized FX hedge impact ($M) (2) |
35,021 |
32,628 |
130,842 |
132,758 |
Production (boe) |
3,612,564 |
3,846,152 |
14,935,435 |
15,104,430 |
Production costs (excluding energy cost), net of realized FX hedge impact ($/boe) |
9.69 |
8.48 |
8.76 |
8.79 |
|
(1) See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A. |
|
(2) Non-IFRS financial measure. |
Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that described the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using e cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Energy costs ($M) |
19,005 |
11,837 |
69,294 |
50,644 |
(-) Realized gain on FX hedge attributable to production costs ($M) (1) |
(738) |
— |
(2,900) |
— |
Energy costs, net of realized FX hedge impact ($M) (2) |
18,267 |
11,837 |
67,024 |
50,644 |
Production (boe) |
3,612,564 |
3,846,152 |
14,935,435 |
15,104,430 |
Energy costs, net of realized FX hedge impact ($/boe) |
5.06 |
3.08 |
4.49 |
3.35 |
|
(1) See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A. |
|
(2) Non-IFRS financial measure. |
Transportation costs, net of realized FX hedge impact is a non-IFRS financial measure that includes all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline and the realized gain or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below:
|
Three months ended
|
Year ended
|
||
|
2023 |
2022 |
2023 |
2022 |
Transportation costs ($M) |
34,750 |
35,660 |
151,416 |
137,554 |
(-) Realized gain on FX hedge attributable to transportation costs ($M) (1) |
(753) |
— |
(3,264) |
— |
Transportation costs, net of realized FX hedge impact ($M) (2) |
33,997 |
35,660 |
148,152 |
137,554 |
Net production (boe) |
3,084,338 |
3,380,908 |
13,210,810 |
13,175,770 |
Transportation costs, net of realized FX hedge impact ($/boe) |
11.02 |
10.55 |
11.21 |
10.44 |
|
(1) See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A. |
|
(2) Non-IFRS financial measure. |
Realized gain (loss) on oil risk management contracts includes the gain or loss during the period, as a result of the Company's exposure in derivative contracts of crude oil. Realized gain (loss) on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized gain (loss) on risk management contracts divided by total sales volumes, net of purchases.
Restricted cash (short and long term) is a capital management measure, that sum the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement.
Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available and consists of the cash and cash equivalents and the restricted cash short and long-term.
Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company, and comprises the debt of unsecured notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.
This news release includes non-standardized measures, including reserves life index and reserves replacement ratio. Reserves life index is calculated as the gross reserves in the referenced category divided by the net production of the last year. It is a measure of how long the booked reserves will last if the production rate is maintained and no additional reserves are added. Reserves replacement ratio is calculated as the net reserves added in the referenced category divided by the net production of the last year. It is a measure of the capacity to replace the production. These measures should not be construed as alternative measures of financial performance. Such measures have been included to provide readers with additional means to evaluate the Company's performance but these non-standardized measures are not reliable indicators of the Company's future performance and therefore must not be relied upon unduly. The Company's method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Readers are cautioned that the information provided or derived by these measures should not be relied upon for investment purposes.
The reserves information contained in this press release has been prepared in accordance with NI 51-101, but only presents a portion of the disclosure required thereunder. Complete reserves disclosure required in accordance with NI 51-101 will be available on SEDAR at www.sedar.com on or around
The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.
The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.
Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially prospective from undiscovered accumulations by application of future development projects. Prospective resources are not, and should not be confused with, reserves or contingent resources.
The prospective resource estimates were made based on separate reviews by two independent, third-party qualified reserves evaluators, effective as of
The resource estimates presented above are subject to certain risks and uncertainties, including those associated with the drilling and completion of future wells, limited available geological and geophysical data and uncertainties regarding the actual production characteristics of the reservoirs, all of which have been assumed for the preparation of the resource estimates. In addition, significant positive and negative factors related to the prospective resource estimate include the high exploration success rate of, and frequency of development projects by, operators in the
Definitions :
bbl(s) |
Barrel(s) of oil |
bbl/d |
Barrels of oil per day |
boe |
Refer to "Boe Conversion" disclosure above |
boe/d |
Barrel of oil equivalent per day |
Mcf |
Thousand cubic feet |
W.I. |
Working Interest |
Net Production |
Net production represents the Company's working interest volumes, net of royalties and internal consumption |
- "Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been in production, and the date of resumption of production must be known with reasonable certainty.
- "Proved Developed Non-Producing Reserves" are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
- "Proved Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
- "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 are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Certain information in this presentation may constitute "analogous information" as defined in NI 51-101. Such information includes reservoir information retrieved from the continuous disclosure record of certain industry participants from www.sedarplus.ca or other publicly available sources. The Joint Venture believes the information is relevant as it may help to define the reservoir characteristics of certain lands in which the Joint Venture holds an interest. The Joint Venture is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is unable to confirm that the analogous information was prepared in accordance with NI 51-101. Such information is not an estimate of the resources attributable to lands held by the Joint Venture and there is no certainty that the resources data and commercial viability for the lands held by the Joint Venture will be similar to the information presented herein. The reader is cautioned that the data relied upon by the Joint Venture may be in error and/or may not be analogous to such lands held by the Joint Venture
For further information, please contact Investor Relations, at 1 403 705 8827, ir@fronteraenergy.ca, www.fronteraenergy.ca
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