Recorded Net Loss of $8.5 Million
Generated Operating EBITDA of $97.2 Million
Generated Adjusted Infrastructure EBITDA of $25.7 Million and Segment Income of $12.6 Million
Delivered Average Daily Production of 38,193 Boe/d, Affected by Light & Medium Oil Performance, Partially Offset by Resilient Heavy Oil Operations Despite Community Blockades and Delays Related to Strategic Water Disposal Initiatives
Achieved Record Average Daily Production of 6,228 bbl/d at CPE-6
Achieved an Agreement in Principle with Ecopetrol Related to SAARA for a 2-year Water Treatment Contract for the Quifa Block
ODL Declared $179.6 million in Capital Distributions ($62.8 million, Net to Frontera), a 99% 2023 Payout Ratio, Payable in 2024
Announces Strategic Alternatives Process for Infrastructure Business
Declared Quarterly Dividend of CAD$0.0625 Per Share, or $3.9 Million in Aggregate, Payable on July 17, 2024
Recognized for Fourth Time by Ethisphere As One of the World’s Most Ethical Companies
CALGARY, AB, May 8, 2024 /PRNewswire/ – Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company”) today reported financial and operational results for the first quarter ended March 31, 2024. All financial amounts in this news release are in United States dollars, unless otherwise stated.
Gabriel de Alba, Chairman of the Board of Directors, commented:
“Frontera’s focus remains centered on delivering on its strategic objectives and generating value for its stakeholders. Operationally, the Company generated $97.2 million in quarterly Operating EBITDA, produced $25.7 million of Adjusted Infrastructure EBITDA, and maintained a robust balance sheet, finishing the quarter with a total cash balance of $182 million.
During the quarter, ODL declared a $157 million dividend ($54.9 million, net to Frontera), highlighting the strong cash generation capacity of this strategic infrastructure investment. The Company also achieved an agreement in principle with Ecopetrol for the use of the Company’s reverse osmosis water treatment facility (“SAARA”) under a two-year contract, a significant ESG and strategic milestone, for driving greater water disposal and crude oil production capacity at the Quifa block.
So far this year, the Company has returned nearly $13 million of capital to our stakeholders, including $7.8 million in declared dividends, $4.1 million of common share repurchases and $1.5 million in buybacks of its 2028 unsecured notes. Moreover, the Company, with support from Goldman Sachs, has launched a strategic alternatives process for its standalone and growing Colombian Infrastructure business, which may include a spin-off, a total or partial sale or other business combination.
The Company will continue to consider future shareholder initiatives in 2024 and beyond, including potential additional dividends, distributions, or bond buybacks, based on the overall results of our businesses and the Company’s strategic goals.”
Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:
“Frontera’s first quarter results were in-line with our expectations despite some unforeseen challenges. First quarter production declined approximately 3% on a quarter over quarter basis, impacted primarily by natural declines and well failures in our light and medium, and natural gas assets, temporary community blockades and delays related to strategic water disposal initiatives in the heavy oil assets partially offset by positive performance from our heavy oil assets.
Supported by another average daily production record at the CPE-6 block, we grew our heavy crude oil production during the quarter to approximately 23,400 bbls/d, a 2% increase over the prior quarter. Our heavy asset growth was driven primarily by higher field activity and investment as well as increasing oil production and water disposal capacity at both our Quifa and CPE-6 blocks and it could have been higher if community blockades and delays related to our strategic water disposal initiatives, including SAARA, had not taken place.
On the exploration side, we are excited about the spudding of our high impact Hydra-1 prospect on the VIM-1 block scheduled for June 2024.
We reiterate our production and capital guidance for 2024. Our 2024 drilling campaign started strong and continues to meet expectations. We expect improved production and profitability throughout the rest of the year as we advance our development portfolio in Colombia and Ecuador and increase water-handling infrastructure and facilities in CPE-6, as well as in Quifa after the agreement reached with Ecopetrol on SAARA.”
First Quarter 2024 Operational and Financial Summary:
|
Q1 2024 |
Q4 2023 |
Q1 2023 |
|||
|
Operational Results |
|||||
|
Heavy crude oil production (1) |
(bbl/d) |
23,398 |
23,002 |
22,270 |
|
|
Light and medium crude oil combined production (1) |
(bbl/d) |
12,580 |
13,795 |
16,518 |
|
|
Total crude oil production |
(bbl/d) |
35,978 |
36,797 |
38,788 |
|
|
Conventional natural gas production (1) |
(mcf/d) |
3,283 |
4,760 |
8,590 |
|
|
Natural gas liquids production (1) |
(boe/d) |
1,639 |
1,635 |
1,291 |
|
|
Total production (2) |
(boe/d) (3) |
38,193 |
39,267 |
41,586 |
|
|
Total inventory balance |
(bbl) |
1,278,763 |
1,076,394 |
1,611,201 |
|
|
Brent price reference |
($/bbl) |
81.76 |
82.85 |
82.10 |
|
|
Oil and gas sales, net of purchases (4) |
($/boe) |
73.71 |
75.76 |
69.07 |
|
|
Premiums paid on oil price risk management contracts (5) |
($/boe) |
(1.27) |
(0.69) |
(1.16) |
|
|
Royalties (5) |
($/boe) |
(1.64) |
(1.79) |
(3.36) |
|
|
Net sales realized price (4) |
($/boe) |
70.80 |
73.28 |
64.55 |
|
|
Production costs (excluding energy cost), net of realized FX hedge impact (4) |
($/boe) |
(10.21) |
(9.69) |
(8.12) |
|
|
Energy costs, net of realized FX hedge impact (4) |
($/boe) |
(5.29) |
(5.06) |
(3.95) |
|
|
Transportation costs, net of realized FX hedge impact (4) |
($/boe) |
(11.33) |
(11.02) |
(11.20) |
|
|
Operating netback per boe (4) |
($/boe) |
43.97 |
47.51 |
41.28 |
|
|
Financial Results |
|||||
|
Oil & gas sales, net of purchases (6) |
($M) |
202,469 |
240,105 |
189,120 |
|
|
Premiums paid on oil price risk management contracts |
($M) |
(3,489) |
(2,198) |
(3,175) |
|
|
Royalties |
($M) |
(4,506) |
(5,683) |
(9,213) |
|
|
Net sales (6) |
($M) |
194,474 |
232,224 |
176,732 |
|
|
Net (loss) income (7) |
($M) |
(8,503) |
92,038 |
(11,330) |
|
|
Per share – basic |
($) |
(0.10) |
1.08 |
(0.13) |
|
|
Per share – diluted |
($) |
(0.10) |
1.04 |
(0.13) |
|
|
General and administrative |
($M) |
13,556 |
16,891 |
12,669 |
|
|
Outstanding Common Shares |
Number |
84,693,416 |
85,151,216 |
85,188,573 |
|
|
Operating EBITDA (6) |
($M) |
97,248 |
121,036 |
91,922 |
|
|
Cash provided by operating activities |
($M) |
65,616 |
73,432 |
845 |
|
|
Capital expenditures (6) |
($M) |
69,381 |
82,292 |
131,452 |
|
|
Cash and cash equivalents – unrestricted |
($M) |
154,907 |
159,673 |
162,272 |
|
|
Restricted cash short and long-term (8) |
($M) |
27,058 |
30,300 |
30,877 |
|
|
Total cash (8) |
($M) |
181,965 |
189,973 |
193,149 |
|
|
Total debt and lease liabilities (8) |
($M) |
537,151 |
536,822 |
519,471 |
|
|
Consolidated total indebtedness (excluding Unrestricted Subsidiaries) (9) |
($M) |
429,556 |
430,170 |
400,361 |
|
|
Net debt (excluding Unrestricted Subsidiaries) (9) |
($M) |
305,821 |
318,092 |
279,843 |
|
(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 the press 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. |
|
(2) Represents W.I. production before royalties. Refer to the “Further Disclosures” section on page 38 of the Company’s management’s discussion and analysis for the three months ended March 31, 2024 (“MD&A”). |
|
(3) Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the “Further Disclosures – Boe Conversion” section on page 38 of the MD&A. |
|
(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 24 of the MD&A. |
|
(5) Supplementary financial measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 23 of the MD&A. |
|
(6) 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 24 of the MD&A. |
|
(7) Net (loss) income attributable to equity holders of the Company. |
|
(8) Capital management measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 24 of the MD&A. |
|
(9) “Unrestricted Subsidiaries” include CGX, listed on the TSX Venture Exchange under the trading symbol “OYL”, Frontera ODL Holding Corp., including its subsidiary Pipeline Investment Ltd. (“PIL”), Frontera BIC Holding Ltd. and Frontera Bahía Holding Ltd. (“Frontera Bahia”), including Puerto Bahia. On April 11, 2023, Frontera Energy Guyana Holding Ltd. and Frontera Energy Guyana Corp. were designated as unrestricted subsidiaries. Refer to the “Liquidity and Capital Resources” section on page 30 of the MD&A. |
First Quarter Operational and Financial Results:
The Company recorded a net loss of $8.5 million or $0.10/share in the first quarter of 2024, compared to net income of $92.0 million or $1.08/share in the prior quarter and a net loss of $11.3 million or $0.13/share in the first quarter of 2023. The Company recorded $29.7 million in operating income, and $13.9 million from share of income from associates (Oleoducto de los Llanos Orientales (“ODL”)) offset by a $26.6 million in income tax expenses (which assumed an income tax rate of 50%, inclusive of the 15% surtax associated to the 2022 Colombian tax reform and included $21.6 million of deferred income tax expenses primarily due to the impact of non-deductible expenses and foreign currency fluctuations), $17.3 million in finance expenses and $8.8 million in losses related to risk management contracts.
Production averaged 38,193 boe/d in the first quarter of 2024 (consisting of 23,398 bbl/d of heavy crude oil, 12,580 bbl/d of light and medium crude oil combined, 3,283 mcf/d of natural gas and 1,639 boe/d of natural gas liquids) compared to 39,267 boe/d in the prior quarter and 41,586 boe/d in the first quarter of 2023. Production declined approximately 3% on a quarter over quarter basis, primarily as a result of natural field declines and well failures at the Company’s light and medium, and natural gas assets, as well as community blockades and delays associated with our strategic water disposal initiatives (including SAARA) in our heavy oil assets. These declines were partially offset by positive performance in our heavy assets due to higher activity and production.
Operating EBITDA was $97.2 million in the first quarter of 2024 compared to $121.0 million in the prior quarter and $91.9 million in the first quarter of 2023. The decrease in operating EBITDA quarter-over-quarter was mainly due to lower sales volumes and higher energy and production costs.
Cash provided by operating activities in the first quarter of 2024 was $65.6 million, compared to $73.4 million in the prior quarter and $0.8 million in the first quarter of 2023. The decrease in cash provided by operating activities quarter over quarter was primarily due to changes in working capital related to lower sales volumes offset partially by lower income taxes withheld.
The Company reported a total cash position of $182.0 million on March 31, 2024, compared to $190.0 million on December 31, 2023, and $193.1 million on March 31, 2023. During the quarter, the Company invested $69.4 million in capital expenditures, $2.7 million in share buybacks through its normal course issuer bid program (“NCIB”) and $1.2 million in repurchases of its senior unsecured notes due in 2028 (the “2028 Unsecured Notes”).
As of March 31, 2024, the Company had total crude oil inventory balances of 1,278,763 bbls compared to 1,076,394 bbls on December 31, 2023. As of March 31, 2024, the Company had a total inventory balance in Colombia of 683,335 barrels, including 353,226 crude oil barrels and 330,109 barrels of diluent and others. This compares to 551,715 barrels on December 31, 2023, and 1,032,876 barrels on March 31, 2023. Inventory balances in the first quarter related to Ecuador and Peru were 115,228 barrels and 480,200 barrels, respectively.
Capital expenditures were approximately $69.4 million in the first quarter of 2024, compared to $82.3 million in the prior quarter and $131.5 million in the first quarter of 2023, which included investments in the Guyana Wei-1 well. During the first quarter of 2024, the Company drilled 21 development wells at its Quifa, Cajua, CPE-6 and Perico blocks.
The Company’s net sales realized price was $70.80/boe in the first quarter of 2024, compared to $73.28/boe in the prior quarter and $64.55/boe in the first quarter of 2023. The decrease in the Company’s quarter-over-quarter net sales realized price was due to a decrease in the Brent benchmark oil price, higher oil price differentials and higher premiums paid on crude oil risk management contracts, partially offset by lower royalties.
The Company’s operating netback was $43.97/boe in the first quarter of 2024, compared to $47.51/boe in the prior quarter and $41.28/boe in the first quarter of 2023. The Company’s operating netback decreased quarter-over-quarter mainly due to the Company’s lower net sales realized price and higher energy and production costs, net of realized FX hedging impacts, as well as higher transportation costs.
Production costs (excluding energy costs), net of realized FX hedging impacts, averaged $10.21/boe in the first quarter of 2024, compared to $9.69/boe in the prior quarter and $8.12/boe in the first quarter of 2023. The increase quarter over quarter was primarily driven by higher well service activity, inflationary pressures on services and wage indexation.
Energy costs, net of realized FX hedging impacts, averaged $5.29/boe in the first quarter of 2024, compared to $5.06/boe in the prior quarter and $3.95/boe in the first quarter of 2023. The increase during the quarter was due to sustained high energy prices and higher activity in the heavy oil assets.
Transportation costs, net of realized FX hedging impacts, averaged $11.33/boe in the first quarter of 2024, compared to $11.02/boe in the prior quarter and up from $11.20/boe in the first quarter of 2023. The increase in transportation costs quarter over quarter was primarily due to annual transportation tariff increases.
Total ODL volumes transported during the first quarter of 2024 were 246,042 bbl/d compared to 252,810 bbl/d in the prior quarter and 225,792 bbl/d in the first quarter of 2023.
During the first quarter 2024, ODL declared $157.0 million in dividends ($54.9 million net to Frontera), and a return of capital of $22.6 million ($7.9 million net to Frontera), payable in installments during 2024. In April 2024, PIL received the first installment equal to 50% of the total capital distributions declared for the year.
Total Puerto Bahia liquids volumes handled during the first quarter of 2024 were 53,360 bbl/d compared to 52,754 bbl/d in the prior quarter and 63,008 bbl/d in the first quarter of 2023. Puerto Bahia liquids revenues were $7.1 million during the first quarter of 2024, compared to $6.8 million in the prior quarter and $7.2 million during the first quarter of 2023. For the general cargo terminal sales decreased to $2.6 million in the first quarter versus $3.4 million in the previous quarter.
Adjusted Infrastructure EBITDA in the first quarter of 2024 was $25.7 million, compared with $27.3 million in the prior quarter and $27.4 million during the first quarter of 2023. The quarter over quarter change resulted from lower Puerto Bahía’s general cargo revenues, lower ProAgrollanos palm oil sales for the Company’s palm oil Plantation, Promotora Agricola de Los Llanos S.A (“Proagrollanos”) as a result of lower palm oil prices and higher Puerto Bahia operating costs, due to inflationary pressures on services and negative impact from foreign exchange rates.
During the first quarter of 2024, the Company repurchased 457,800 common shares for cancellation at a cost of approximately $2.7 million. The Company also repurchased $1.2 million of its 2028 Unsecured Notes.
Frontera’s Sustainability Strategy
During the first quarter of 2024, Frontera offset nearly 50% of its CO2 emissions from the production and consumption of energy in our operations through carbon credits.
The Colombian Safety Council recognized the Company with its Culture Award for the Company’s extensive and robust model of safety and health culture. During the first quarter of 2024, the company also achieved a Total Recordable Incident Rate (“TRIR”) of 0.72 and reused 20% of its water production and 37% of its operating waste.
The Company also invested $0.5 million in social projects in communities near its operations in Colombia, Ecuador and Guyana.
On February 22, 2024, Frontera was recognized by Ethisphere as one of the World’s Most Ethical Companies. This is the fourth consecutive year that the Company has received this distinction from Ethisphere, a global leader in defining and advancing the standards of ethical business practices. In 2024, 136 honorees were recognized from 20 countries and 44 industries. Frontera was one of only two honorees from the oil and gas industry.
Frontera was also recognized for the second time as one of the 20 Best Workplaces for Women in Colombia by the Great Place to Work® Institute (“GPTW”).
Enhancing Shareholder Returns
NCIB
Under the Company’s current NCIB, Frontera is authorized to repurchase up to 3,949,454 common shares for cancellation during the twelve-month period commencing on November 21, 2023, and ending on November 20, 2024. As of May 8, 2024, the Company has repurchased approximately 949,600 common shares for cancellation for approximately $5.8 million.
Dividends
On March 7, 2023, Frontera’s Board of Directors (the “Board”) approved the declaration and payment of a CAD$0.0625 per share dividend, for a total of approximately $3.9 million, which was paid on April 16, 2024.
Additionally, pursuant to Frontera’s dividend policy, the Board has declared a dividend of CAD$0.0625 per common share to be paid on or around July 17, 2024, to shareholders of record at the close of business on July 3, 2024. This dividend payment to shareholders is designated as an “eligible dividend” for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company’s Dividend Reinvestment Plan to provide shareholders of Frontera who are resident in Canada with the option to have the cash dividends declared on their common shares reinvested automatically back into additional common shares, without the payment of brokerage commissions or services charges.
Bond Buybacks
During the three months ended March 31, 2024, the Company repurchased in the open market $1.5 million of its 2028 Unsecured Notes for a cash consideration of $1.2 million including interest payable of $0.1 million. As a result, the Company recognized a gain of $0.3 million. The outstanding balance for the 2028 Unsecured Notes as of March 31, 2024, is $398.5 million.
The Company will continue to consider future shareholder initiatives in 2024 and beyond, including potential additional dividends, distributions, or bond buybacks, based on the overall results of our businesses and the Company’s strategic goals.
Strategic Review Processes
In May 2024, the Company launched a strategic alternatives review for its standalone and growing Colombian Infrastructure Business, which could result in a potential spin-off to Frontera shareholders, a total or partial sale or other business combination of Frontera’s Colombian Infrastructure Business, and/or a strategic investment, therein by a third party. Frontera has retained Goldman Sachs & Co. LLC as financial advisor and may retain other advisors to assist the Board in evaluating the various strategic, business, and financial alternatives.
The Company, with support from Houlihan Lokey, continues to actively pursuing strategic alternatives for its interests in the Corentyne block in Guyana, including a possible farm down.
These processes are central to the Company’s efforts to streamline the business and unlock the value from sum of its parts. Frontera believes the value of these assets is not reflected in the current stock price and these processes aim to drive value for shareholders. There can be no guarantee that these strategic review processes will result in a transaction.
Frontera’s Three Core Businesses
Frontera’s three core businesses include: (1) its Colombia and Ecuador Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana.
Colombia & Ecuador Upstream Onshore
Colombia
During the first quarter of 2024, Frontera produced 36,715 boe/d from its Colombian operations (consisting of 23,398 bbl/d of heavy crude oil, 11,102 bbl/d of light and medium crude oil, 3,283 mcf/d of conventional natural gas and 1,639 boe/d of natural gas liquids). During the quarter, the Company drilled 20 development wells at its Quifa SW, Cajua and CPE-6 blocks and well interventions at 23 other wells.
The Company currently has 3 drilling rigs active at its Quifa SW, Cajua and CPE-6 blocks in Colombia.
Quifa Block: Quifa SW and Cajua
At Quifa, quarterly production averaged approximately 16,858 bbl/d of heavy crude oil (including Quifa SW, Cajua and Jaspe). During the quarter, the Company drilled 13 wells on the block. The Company also invested in building the platform for a new 100,000 bwpd injector well.
Production during the quarter was negatively impacted by temporary blockades and road closures affecting both the Quifa and CPE-6 blocks. As a result of the blockades, certain wells had to be shut impacting the quarter’s production by approximately 435 bbl/d. Additionally, reduced water disposal capacity associated with SAARA, was reduced due to the temporary suspension of the project following the conclusion of the project’s pilot program, impacting production by an additional 290 bbl/d.
In March 2024, Frontera achieved an agreement in principle with Ecopetrol for the use of the Company’s reverse osmosis water treatment facility (“SAARA”) under a two-year contract, with the objective to process 250,000+ barrels of water per day for the Quifa block.
The Company’s current water handling capacity in Quifa is approximately 1.5 million bwpd (flat as compared to the fourth quarter of 2023).
CPE-6
At CPE-6, the Company delivered another average daily production record of 6,228 bbl/d of heavy crude oil. The Company drilled 7 development wells on the block. Additionally, the Company invested additional storage and water handling capacity at the block.
Other Colombia Developments
At Guatiquia, production averaged 5,610 bbl/d of light and medium crude during the quarter, compared to 6,206 bbl/d in the fourth quarter of 2023.
In the Cubiro Block, production averaged 1,461 bbl/d of light and medium crude oil during the quarter, compared to 1,535 bbl/d in the fourth quarter 2023.
At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,579 boe/d of light and medium crude oil during the first quarter of 2024, compared to 1,775 boe/d of light and medium crude oil in the fourth quarter of 2023. During the quarter, the Company invested in the expansion of gas compression facilities on the VIM-1 block.
Colombia Exploration Assets
At the VIM-1 block (Frontera 50% W.I., non-operator), the Company completed certain civil works activities including platform and road construction in advance of drilling the Hydra-1 exploration well. The Company anticipates spudding the well in June 2024.
At the Llanos 119 block, Frontera’s 80sqkm 3D seismic acquisition campaign is underway and is expected to be completed in the second quarter of 2024. At the Llanos-99 and VIM-46 blocks, pre-seismic and pre-drilling activities related to social and environmental studies are underway.
Ecuador
In Ecuador, first quarter 2024 production averaged approximately 1,478 bbl/d of light & medium crude oil compared to 1,453 bbl/d in the prior quarter. Production slightly increased due to the completion of Perico Norte A-5 at the end of February 2024, partially offset by natural decline.
At the Espejo block the two remaining exploration wells committed are expected to be drilled during 2024, targeting one opportunity for Lower U Sand in the southern area and one opportunity for M1 Sand in the central area of the block.
Infrastructure Colombia
Frontera has investments in various significant infrastructure and midstream assets seeking to capture stable and long-term revenue streams, including storage, port, and other facilities in Colombia which comprise its standalone and growing Infrastructure Colombia business. Frontera’s Infrastructure Colombia Segment includes the Company’s 35% equity interest in the ODL pipeline through Frontera’s wholly owned subsidiary, PIL and the Company’s 99.97% interest in Puerto Bahia. Starting in 2024, the Infrastructure Colombia Segment will also include the Company’s reverse osmosis water treatment facility (SAARA) and its palm oil plantation (ProAgrollanos).
Infrastructure Colombia Segment Results
Adjusted Infrastructure EBITDA in the first quarter of 2024 was $25.7 million, compared with $27.4 million during the first quarter of 2023. The year over year change resulted mainly from lower Puerto Bahía’s general cargo revenues, lower palm oil prices and higher operating costs due to inflationary pressures on services and wages across the segment and negative impact from foreign exchange rates, partially offset by higher transported volumes at ODL.
|
Three months ended March 31 |
||
|
($M) (1) |
2024 |
2023 |
|
Adjusted Infrastructure Revenue (1) |
40,907 |
39,550 |
|
Adjusted Infrastructure Operating Costs (1) |
(12,138) |
(9,760) |
|
Adjusted Infrastructure General and Administrative (1) |
(3,082) |
(2,427) |
|
Adjusted Infrastructure EBITDA (1) |
25,687 |
27,363 |
|
(1)Non-IFRS financial measure. |
Segment capital expenditures for the three months ended March 31, 2024, were $4.6 million mainly related to investments in the SAARA project and investments at Puerto Bahia consisting of: (i) dry terminal equipment purchases and terminal upgrading, (ii) tank maintenance, and (iii) right of way and engineering expenditures associated to the Reficar Connection Project.
|
Three months |
||
|
($M) |
2024 |
2023 |
|
Revenue |
10,528 |
12,465 |
|
Costs |
(8,149) |
(7,136) |
|
General and administrative expenses |
(1,479) |
(1,455) |
|
Depletion, depreciation and amortization |
(1,816) |
(1,354) |
|
Restructuring, severance and other costs |
(426) |
(103) |
|
Infrastructure (loss) income from operations |
(1,342) |
2,417 |
|
Share of Income from associates – ODL |
13,894 |
13,572 |
|
Infrastructure Colombia Segment income |
12,552 |
15,989 |
|
Infrastructure Colombia Segment cash flow from operating activities |
643 |
5,635 |
|
Capital Expenditures Infrastructure Colombia segment (1) |
4,556 |
1,177 |
|
(1)Non-IFRS financial measures (equivalent to a “non-GAAP financial measures”, as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 24 of the MD&A. |
The following table shows the volumes pumped per injection point in ODL:
|
Three months |
||
|
(bbl/d) |
2024 |
2023 |
|
At Rubiales Station |
167,378 |
154,817 |
|
At Jagüey and Palmeras Station |
78,664 |
70,975 |
|
Total |
246,042 |
225,792 |
The following table shows throughput for the liquids port facility at Puerto Bahia:
|
Three months |
||
|
(bbl/d) |
2024 |
2023 |
|
FEC volumes |
16,647 |
11,408 |
|
Third party volumes |
36,713 |
51,600 |
|
Total |
53,360 |
63,008 |
The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for ProAgrollanos:
|
Three months |
||||
|
2024 |
2023 |
|||
|
Fresh fruit bunch from palm oil (produced – sold) |
(Tons) |
5,095 |
5,661 |
|
|
Production per hectare |
(Tons/ ha) |
1.69 |
1.87 |
|
|
Palm oil fruit price |
($/Ton) |
160 |
290 |
|
|
Volumes of reverse osmosis water treated |
(bwpd) |
33,272 |
22,304 |
|
|
Volumes of water irrigated in palm oil cultivation |
(bwpd) |
23,613 |
16,162 |
|
Hedging Update
As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company’s strategy aims to protect 40-60% of its estimated net after royalties’ production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio.
The following table summarizes Frontera’s 2024 hedging position as of May 7, 2024.
|
Term |
Type of |
Positions (bbl/d) |
Strike Prices Put/Call |
|
Apr 24 |
Put |
14,711 |
72.00 |
|
May 24 |
Put |
14,586 |
72.00 |
|
Jun 24 |
Put |
14,667 |
72.00 |
|
2Q-2024 |
Total Average |
72.00 |
|
|
Jul 24 |
Put |
14,581 |
75.00 |
|
Aug 24 |
Put |
13,871 |
76.50 |
|
Sep 24 |
Put |
3,667 |
78.00 |
|
3Q-2024 |
Total Average |
75.98 |
The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD.
As of May 7, 2024, the Company had the following foreign currency derivatives contracts:
|
Term |
Type of |
Open Interest (US$ MM) |
Strike Prices Put/Call |
Hedging Ratio |
|
2Q-2024 |
Zero Cost Collars |
60 |
4,125/ 4,763 |
40 % |
|
3Q-2024 |
Zero Cost Collars |
30 |
3,970/4,056 |
20 % |
|
Aug 2024 |
Forward* |
12 |
4,044 |
|
|
Oct 2024 |
Forward** |
17 |
4,386 |
|
|
Oct 2024 |
Forward* |
9 |
4,078 |
|
|
Dec 2024 |
Forward* |
9 |
4,115 |
|
|
* Hedges associated with ODL’s declared capital distributions ** Hedge associated with the repayment of the Bancolombia COP working capital loan |
||||
First Quarter 2024 Conference Call Details
A conference call for investors and analysts will be held on Thursday, May 9, 2024, at 2:30 p.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, René Burgos, Chief Financial Officer, and other members of the senior management team.
Analysts and investors are invited to participate using the following dial-in numbers:
|
RapidConnect URL: |
|
|
Participant Number (Toll Free North America): |
1-888-644-6383 |
|
Participant Number (Toll Free Colombia): |
01-800-518-4036 |
|
Participant Number (International): |
1-416-764-8650 |
|
Conference ID: |
850717 |
|
Webcast Audio: |
A replay of the conference call will be available until 11:59 p.m. Eastern Time on May 16, 2024.
|
Encore Toll free Dial-in Number: |
1-888-390-0541 |
|
International Dial-in Number: |
1-416-764-8677 |
|
Encore ID: |
850717 |
About Frontera:
Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 24 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner.
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.
Social Media
Follow Frontera Energy social media channels at the following links:
Twitter: https://twitter.com/fronteraenergy?lang=en
Facebook: https://es-la.facebook.com/FronteraEnergy/
LinkedIn: https://co.linkedin.com/company/frontera-energy-corp.
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, the Company’s strategic alternatives process for its Colombian Infrastructure business and the Company’s strategic review process of the farm down of its interests in the Corentyne block in Guyana, the Company’s belief that the value of its assets is not reflected in the current stock price and the ability of such strategic processes to drive value for shareholders, the Company’s goal of enhancing shareholder value by returning capital to securityholders, the Company’s intent to consider future shareholder initiatives, the Company’s exploration and development plans and objectives, including its drilling plans and seismic acquisition campaign and the timing thereof, estimates and/or assumptions in respect of the Company’s capital expenditure program (including Company’s guidance), production levels, profitability, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, the impact of shut-ins and other work in the field on future field performance, and the Company’s hedging program and its ability to mitigate the impact of changes in oil prices) 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: the ability of the Company to successfully conclude on a timely basis or at all one or both of its strategic review processes; volatility in market prices for oil and natural gas; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company’s ability to raise capital and to continually add reserves through acquisition and development; the Company’s ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility and the other risks disclosed under the heading “Risk Factors” and elsewhere in the Company’s annual information form dated March 7, 2024 filed on SEDAR+ at www.sedarplus.ca. 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 average production), 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.
Non-IFRS Financial Measures
This press 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 measures do not have standardized IFRS definitions. The Company’s determination of these non-IFRS 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 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 the MD&A.
Operating EBITDA
EBITDA is a commonly used non-IFRS financial measure that adjusts net 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.
A reconciliation of Operating EBITDA to net loss is as follows:
|
Three Months |
||||
|
($M) |
2024 |
2023 |
||
|
Net loss (1) |
(8,503) |
(11,330) |
||
|
Finance income |
(1,592) |
(4,301) |
||
|
Finance expenses |
17,270 |
15,221 |
||
|
Income tax expense |
26,585 |
7,520 |
||
|
Depletion, depreciation and amortization |
65,812 |
66,713 |
||
|
(Recovery) expense of asset retirement obligation |
(1,042) |
13,081 |
||
|
Expenses of impairment |
1,027 |
16,815 |
||
|
Post-termination obligation |
550 |
157 |
||
|
Share-based compensation |
286 |
(499) |
||
|
Restructuring, severance and other costs |
1,803 |
1,572 |
||
|
Share of income from associates |
(13,894) |
(13,572) |
||
|
Foreign exchange loss |
1,097 |
11,760 |
||
|
Other loss (income) |
359 |
(6,305) |
||
|
Unrealized loss (gain) on risk management contracts |
7,939 |
(4,825) |
||
|
Non-controlling interests |
(155) |
(85) |
||
|
Gain on repurchased 2028 Unsecured Notes |
(294) |
— |
||
|
Operating EBITDA |
97,248 |
91,922 |
||
|
(1)Refers to net loss attributable to equity holders of the Company. |
Capital Expenditures
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 March 31 |
||
|
2024 |
2023 |
|
|
Consolidated Statements of Cash Flows |
||
|
Additions to oil and gas properties, infrastructure port, and plant and equipment |
62,849 |
42,980 |
|
Additions to exploration and evaluation assets |
2,487 |
88,946 |
|
Total additions in Consolidated Statements of Cash Flows |
65,336 |
131,926 |
|
Non-cash adjustments (1) |
4,045 |
(474) |
|
Total Capital Expenditures |
69,381 |
131,452 |
|
Capital Expenditures attributable to Infrastructure Colombia Segment |
4,556 |
1,177 |
|
Capital Expenditures attributable to other segments different to Infrastructure Colombia Segment |
64,825 |
130,275 |
|
Total Capital Expenditure |
69,381 |
131,452 |
|
(1) Related to material inventory movements, capitalized non-cash items and other adjustments. |
Infrastructure Colombia Calculations
Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs 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 Costs 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 the Infrastructure Colombia Segment including ODL’s general and administrative direct participation interest.
A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below.
|
Three months ended March 31 |
||
|
($M) (1) |
2024 |
2023 |
|
Revenue Infrastructure Colombia Segment |
10,528 |
12,465 |
|
Revenue from ODL |
86,797 |
77,387 |
|
Direct participation interest in the ODL |
35.00 % |
35.00 % |
|
Equity adjustment participation of ODL (1) |
30,379 |
27,085 |
|
Adjusted Infrastructure Revenues |
40,907 |
39,550 |
|
Operating cost Infrastructure Colombia Segment |
(8,149) |
(7,136) |
|
Operating Cost from ODL |
(11,396) |
(7,496) |
|
Direct participation interest in the ODL |
35.00 % |
35.00 % |
|
Equity adjustment participation of ODL (1) |
(3,989) |
(2,624) |
|
Adjusted Infrastructure Operating Costs |
(12,138) |
(9,760) |
|
General and administrative Infrastructure Colombia Segment |
(1,479) |
(1,455) |
|
General and administrative from ODL |
(4,581) |
(2,778) |
|
Direct participation interest in the ODL |
35.00 % |
35.00 % |
|
Equity adjustment participation of ODL (1) |
(1,603) |
(972) |
|
Adjusted Infrastructure General and Administrative |
(3,082) |
(2,427) |
|
(1) Revenues and expenses related to the ODL are accounted for using the equity method described in the Note 12 of the Interim Financial Statements. |
Adjusted Infrastructure EBITDA
The Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Colombia Segment business. Refer to the calculation in the “Non-IFRS Results of Infrastructure Segment” section on page 21.
|
Three months ended March 31 |
||
|
($M) (1) |
2024 |
2023 |
|
Adjusted Infrastructure Revenue (1) |
40,907 |
39,550 |
|
Adjusted Infrastructure Operating Costs (1) |
(12,138) |
(9,760) |
|
Adjusted Infrastructure General and Administrative (1) |
(3,082) |
(2,427) |
|
Adjusted Infrastructure EBITDA (1) |
25,687 |
27,363 |
|
(1) Non-IFRS financial measure. |
Net Sales
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 12 of the MD&A.
Operating Netback in Oil and Gas Sales, Net of Purchases
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 Infrastructure Colombia 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 11.
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 costs. 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 March 31 |
||
|
2024 |
2023 |
|
|
Produced crude oil and gas sales ($M) (1) |
209,043 |
197,091 |
|
Purchased crude oil and products sales ($M) |
51,285 |
51,316 |
|
(-) Cost of purchases ($M) (2) |
(57,859) |
(59,287) |
|
Oil and gas sales, net of purchases ($M) |
202,469 |
189,120 |
|
Sales volumes, net of purchases – (boe) |
2,746,835 |
2,738,160 |
|
Oil and gas sales, net of purchases ($/boe) |
73.71 |
69.07 |
|
(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 (formerly Midstream Colombia)” section on page 20. |
|
(2) Cost of third-party volumes purchased for use and resale in the Company’s oil operations, including its transportation and refining costs. |
Non-IFRS Ratios
Realized oil price, net of purchases, and realized gas price per boe
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 March 31 |
||
|
2024 |
2023 |
|
|
Produced crude oil sales ($M) |
207,177 |
193,334 |
|
Purchased crude oil and products sales ($M) |
51,285 |
51,316 |
|
(-) Cost of purchases ($M) |
(57,859) |
(59,287) |
|
Conventional natural gas sales ($M) |
1,866 |
3,757 |
|
Oil and gas sales, net of purchases ($M) (1) |
202,469 |
189,120 |
|
Sales volumes, net of purchases – (bbl) |
2,694,482 |
2,607,363 |
|
Conventional natural gas sales volumes – (mcf) |
298,144 |
745,794 |
|
Realized oil price, net of purchases ($/bbl) |
74.45 |
71.09 |
|
Realized conventional natural gas price ($/mcf) |
6.26 |
5.04 |
|
(1) Non-IFRS financial measure. |
Net sales realized price
Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below:
|
Three months ended March 31 |
||
|
2024 |
2023 |
|
|
Oil and gas sales, net of purchases ($M) (1) |
202,469 |
189,120 |
|
(-) Premiums paid on oil price risk management contracts ($M) |
(3,489) |
(3,175) |
|
(-) Royalties ($M) |
(4,506) |
(9,213) |
|
Net sales ($M) |
194,474 |
176,732 |
|
Sales volumes, net of purchases – (boe) |
2,746,835 |
2,738,160 |
|
Oil and gas sales, net of purchases ($/boe) |
73.71 |
69.07 |
|
Premiums paid on oil price risk management contracts (2) |
(1.27) |
(1.16) |
|
Royalties ($/boe) (2) |
(1.64) |
(3.36) |
|
Net sales realized price ($/boe) |
70.80 |
64.55 |
|
(1) Non-IFRS financial measure. |
|
(2) Supplementary financial measure. |
Production costs (excluding energy cost), net of realized FX hedge impact, and production cost (excluding energy cost), net of realized FX hedge impact per boe
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, 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 March 31 |
||
|
2024 |
2023 |
|
|
Production costs (excluding energy cost) ($M) |
36,839 |
30,387 |
|
(-) Realized gain on FX hedge attributable to production costs (excluding energy cost) ($M) (1) |
(1,337) |
— |
|
Production costs (excluding energy cost), net of realized FX hedge impact ($M) (2) |
35,502 |
30,387 |
|
Production (boe) |
3,475,563 |
3,742,740 |
|
Production costs (excluding energy cost), net of realized FX hedge impact ($/boe) |
10.21 |
8.12 |
|
(1) See “Gain (Loss) on Risk Management Contracts” on page 15. |
|
(2) Non-IFRS financial measure. |
Energy costs, net of realized FX hedge impact, and production cost, net of realized FX hedge impact per boe
Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that describes 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 energy cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:
|
Three months ended March 31 |
||
|
2024 |
2023 |
|
|
Energy costs ($M) |
18,968 |
14,770 |
|
(-) Realized gain on FX hedge attributable to energy costs ($M) (1) |
(581) |
— |
|
Energy costs, net of realized FX hedge impact ($M) (2) |
18,387 |
14,770 |
|
Production (boe) |
3,475,563 |
3,742,740 |
|
Energy costs, net of realized FX hedge impact ($/boe) |
5.29 |
3.95 |
|
(1) See “Gain (Loss) on Risk Management Contracts” on page 15. |
|
(2) Non-IFRS financial measure. |
Transportation costs, net of realized FX hedge impact, and transportation costs, net of realized FX hedge impact per boe
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 March 31 |
||
|
2024 |
2023 |
|
|
Transportation costs ($M) |
35,195 |
37,370 |
|
(-) Realized gain on FX hedge attributable to transportation costs ($M) (1) |
(409) |
— |
|
Transportation costs, net of realized FX hedge impact ($M) (2) |
34,786 |
37,370 |
|
Net production (boe) |
3,070,613 |
3,336,120 |
|
Transportation costs, net of realized FX hedge impact ($/boe) |
11.33 |
11.20 |
|
(1) See “Gain (Loss) on Risk Management Contracts” on page 15. |
|
(2) Non-IFRS financial measure. |
Supplementary Financial Measures
Realized (loss) gain on oil risk management contracts per boe
Realized (loss) gain 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 (loss) gain on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized (loss) gain on risk management contracts divided by total sales volumes, net of purchases.
Royalties per boe
Royalties includes royalties and amounts paid to previous owners of certain blocks in Colombia and cash payments for PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases.
NCIB weighted-average price per share
Weighted-average price per share under the 2023 NCIB is a supplementary financial measure that corresponds to the weighted-average price of common shares purchased under the 2023 NCIB during the period. It is calculated using the total amount of common shares repurchased in U.S. dollars divided by the number of common shares repurchased.
Capital Management Measures
Restricted cash short- and long-term
Restricted cash (short- and long-term) is a capital management measure, that sums 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
Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term.
Total debt and lease liabilities
Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.
Definitions:
|
bbl(s) |
Barrels) of oil |
|
bbl/d |
Barrel of oil per day |
|
boe |
Refer to “Boe Conversion” disclosure above |
|
boe/d |
Barrel of oil equivalent per day |
|
Mcf |
Thousand cubic feet |
|
Net Production |
Net production represents the Company’s working interest volumes, net of royalties and internal |
SOURCE Frontera Energy Corporation