CALGARY, AB, Dec. 12, 2024 /PRNewswire/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today provided an operational update and announced its full year 2025 capital and production guidance. All values in this news release and the Company's financial disclosures are in United States dollars, unless otherwise noted.
Q4 2024 Operational Update
- Colombia and Ecuador Upstream: Q4 2024 production to date is approximately 42,450 boe/d, with a year-to-date average of approximately 40,200 boe/d, within the Company's 2024 production guidance range. CPE-6 achieved another daily production record with close to 9,000 boe/d in December and Q4 2024 production to date for the CPE-6 Block is approximately 8,400 boe/d.
- Infrastructure: Puerto Bahia has received the final $10 million disbursement of the accordion related to the construction of the Reficar connection. The Company expects construction for the connection to be completed by year-end 2024. In November 2024, the Company received its final installment of the Oleoducto de los Llanos S.A. ("ODL") declared distributions. The Company received $61.0 million in total distributions in 2024 from its 35% interest in the ODL pipeline.
The Company's strategic alternatives review for its Infrastructure business is ongoing. Since its launch in May 2024, the Company has prepared a virtual data room, held management presentations and engaged in discussions with several interested third parties. The Company is working diligently to conclude its review process and believes that the process is nearing its final stages. Frontera has retained Goldman Sachs & Co. LLC as financial advisor in connection with the strategic alternatives review. There can be no guarantee that this strategic alternative review process will result in a transaction.
- Guyana: Notwithstanding recent comments from certain Government officials, Frontera and its joint venture partner CGX Energy Inc. (jointly, "the JV") are firmly of the view that the Corentyne block Petroleum Agreement remains in place. These comments have created confusion amongst stakeholders which have materially affected the JV and caused harm to the JV's efforts to develop the Corentyne block. The JV is reviewing all alternatives to safeguard its interest in the Corentyne block and Guyana and has sent the Government of Guyana a letter activating a sixty (60) day period for the parties to the Corentyne block Petroleum Agreement to make all reasonable efforts to amicably resolve all disputes via negotiation, as provided for in the Corentyne block Petroleum Agreement.
Key 2025 Capital and Production Guidance Highlights:
- Frontera expects to deliver a full year production of 41,000 - 43,000 boe/d for 2025, an increase of 2% in production at the midpoint compared to 2024 levels and anticipates generating consolidated Operating EBITDA of $370 - $415 million at $75 /bbl and $420 - $465 million at $80 /bbl average Brent prices.
- The Company plans to invest $200 - $245 million, including $30 - $40 million exploration investments, in the Company's core Colombia and Ecuador Upstream business, a 13% decrease at the midpoint compared to 2024.
- Frontera expects to deploy $30 - $40 million to drill three exploration wells, the high-impact Hidra-1 exploration well in the VIM-1 block, one well in the Llanos 99 block, and one well in the Cachicamo block and to complete additional seismic and pre-drilling activities in Colombia.
- The Company will invest $15 - $20 million in the Company's standalone and growing Colombia Infrastructure business to complete and commission the Reficar connection, perform maintenance activities in Puerto Bahia and make investments related to the SAARA water management project.
- Total production costs, including both production and energy costs, are expected to average $14.00 - $15.00 per boe, a decrease of 3% at the midpoint compared to 2024. Transportation costs for 2025 are forecasted to average $12.50 - $13.00 per boe, an increase of 11% at the midpoint compared to 2024 mainly due to the increase of trucking and pipeline tariffs.
- Frontera expects to generate consolidated 2025 Free Cash Flow of $79 - $122 million and $124 - $167 million at a $75 /bbl and $80 /bbl average Brent, respectively. 2025 Upstream Free Cash Flow is projected to be between $65 - $95 million and $110 - $140 million at a $75 /bbl and $80 /bbl average Brent, respectively.
- The Company will consider future additional stakeholder value enhancing initiatives, including additional dividends, distributions, or bond buybacks, based upon overall results of our businesses and the Company's strategic goals.
Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:
"Frontera's production has maintained its positive momentum in the second half of 2024, averaging over 42,450 boe/d so far in the fourth quarter. The Company has delivered average production of approximately 40,200 boe/d year to date in 2024 within the Company's Full Year 2024 production guidance range.
Moving on to 2025, Frontera's 2025 capital and production guidance continues to build on the Company's foundational strategy of delivering value over volumes. For 2025, the Company expects to deliver 41,000 to 43,000 boe/d of full year production, generating between $370 to $415 million and $420 to $465 million in consolidated Operating EBITDA at $75 /bbl and $80 /bbl average Brent price, respectively.
The Company plans to invest between $216 to $268 million in total capital in 2025, a 20% reduction compared at the midpoint of our 2024 guidance. Our 2025 capital and production plan focuses on the most productive and profitable assets in the portfolio, building on the Company's successful heavy asset drilling campaign in 2024 in the Quifa and CPE-6 blocks. Our capital plan is fully funded from our operations and partially protected by our proactive hedging strategy.
We will also invest in our exploration portfolio, led by the drilling of our high-impact Hidra-1 exploration well in the VIM-1 block - originally postponed from our 2024 plan, one well in the Cachicamo block and one well in the Llanos 99 block. This approach aims to unlock growth potential in near field reserves.
Our 2025 Infrastructure business is expected to generate Operating EBITDA between $20 to $35 million, a 38% increase compared at the midpoint of our 2024 guidance, reflecting the positive impact of our investments in Puerto Bahia, including from the ramp-up of the Reficar connection in 2025, and the ramp-up of facilities related to the SAARA reverse osmosis water treatment project reaching our 250,000 barrels of water handled per day target.
Frontera expects to generate between $79 to $122 million in consolidated Free Cash Flow at $75 /bbl average Brent prices, an 18% increase compared at the midpoint of our 2024 guidance at $80 /bbl. Despite lower expected oil prices, Frontera projects strong cash flow generation driven by higher production, lower capital expenditures and a focus on cost control.
With respect to Guyana, Frontera and its JV partner are firmly of the view that the Corentyne block Petroleum Agreement remains in place. However, the JV recognizes that recent comments from certain Government officials have materially affected the JV and caused harm to JV efforts to develop the Corentyne block. The JV is reviewing all alternatives to safeguard its interest in the Corentyne block and in Guyana.
Frontera remains committed to enhancing stakeholder value initiatives for 2024 and beyond, including the possibility of additional dividends, share buybacks, bond buybacks or other initiatives, based on the overall results of the business, cash flow generation, oil prices and the Company's strategic goals."
Operational Update
Colombia and Ecuador Upstream
Frontera's Q4 2024 production to date is approximately 42,450 boe/d, with a year-to-date average of approximately 40,200 boe/d - within Frontera's full year 2024 production guidance range.
In November 2024, Frontera increased the water handling capacity at its CPE-6 block to 360,000 bwpd, and as a result, in December, the Company achieved a new daily production record of close to 9,000 boe/d from the block.
With respect to our SAARA water management project, Frontera processed an average of 135,000 barrels of water per day in November and peaked at 185,000 barrels of water per day. The Company remains focused on reaching the Company's goal of processing 250,000 barrels supporting higher production levels in the Quifa block.
On the exploration front, 2024 remained a challenging year for the Company's Colombia and Ecuador Upstream business. Due to social issues, the spudding of the high-impact Hidra-1 well on the VIM-1 block, while drill-ready, was paused and the well is now slated to be drilled in the first half of 2025. Preliminary results from our seismic activities related to the LLA-119 block were below the Company's expectations and the Company is currently reviewing its alternatives related to this block. Additionally, the Company expects to drill its final exploration well for 2024, the Papilio-1 well, targeting near field targets on the Cachicamo block in Colombia in December with results expected during the first quarter of 2025.
Infrastructure
Puerto Bahia has drawn the final $10 million disbursement of the $30 million accordion of the Pipeline Investment Limited ("PIL") loan facility to fund the construction of the connection project between Puerto Bahia's liquids port facility and the Cartagena refinery operated by Refineria de Cartagena S.A.S. ("Reficar"). The connection construction is 73% complete and is scheduled for completion by the end of 2024. The Reficar connection is expected to be operational in early 2025. Puerto Bahia expects the first crude oil import vessel to reach Reficar through the connection in February 2025.
On November 21, 2024, PIL received the final 2024 ODL distribution payment of $8.9 million. The Company has received total full year 2024 distributions of $61.0 million from its 35% interest in the ODL pipeline. The Company expects the total debt outstanding at PIL, inclusive of the $30 million Reficar connection project accordion, to be $101 million on December 31, 2024, following its scheduled amortization payment and cash flow sweep on December 15, 2024. This represents a $30 million debt reduction during fiscal year 2024 and a total $50 million debt reduction since the PIL loan facility first closed in March 2023.
Guyana
As highlighted during Frontera's Q3 2024 conference call, the Company and its joint venture partner CGX Energy Inc. remain committed to the potential development of the Corentyne block as supported by the JV's recent discoveries at Kawa-1 and Wei-1.
The JV has engaged in ongoing constructive communications with the Government of Guyana regarding the Corentyne Block with the latest one occurring on September 25 th, 2024. To date, the JV has not received any formal communications from the Government of Guyana regarding the status of the license. The JV is firmly of the view that the Corentyne block Petroleum Agreement remains in place. The JV recognizes that recent comments from certain Government officials have created confusion amongst stakeholders which have materially affected the JV and caused harm to the JV's efforts to develop the Corentyne block.
The JV is reviewing all alternatives to safeguard its interest in the Corentyne block and Guyana and has sent the Government of Guyana a letter activating a sixty (60) day period for the parties to the Corentyne block Agreement to make all reasonable efforts to amicably resolve all disputes via negotiation, as provided for in the Corentyne block Petroleum Agreement.
2025 Guidance
Summary of Frontera's 2025 Capital and Production Guidance
Guidance Metrics | Unit | 2024 Guidance | 2025 Full Year Guidance |
Average Daily Production (1). | boe/d | 40,000 - 42,000 | 41,000 - 43,000 |
Production Costs (excl. energy costs) (2)(4) | $/boe | $8.50 - $9.50 | $8.75 - $9.25 |
Energy Costs (2)(4) | $/boe | $5.75 - $6.25 | $5.25 - $5.75 |
Transportation Costs (3)(4) | $/boe | $11.00 - $12.00 | $12.50 - $13.00 |
Operating EBITDA (5) at $75/bbl (6) | $MM | $370 - $415 | |
Upstream Operating EBITDA | $MM | $350 - $380 | |
Infrastructure Operating EBITDA(7) | $MM | $20 - $35 | |
Operating EBITDA (5) at $80/bbl (6) | $MM | $400 - $450 | $420 - $465 |
Upstream Operating EBITDA | $MM | $400 - $430 | $400 - $430 |
Infrastructure Operating EBITDA(7) | $MM | $15 - $25 | $20 - $35 |
Adjusted Infrastructure EBITDA (8) | $MM | $95 - $115 | $115 - $130 |
Development Drilling | $MM | $85 - $95 | $100 - $110 |
Development Facilities | $MM | $95 - $115 | $60 - $80 |
Colombia and Ecuador Development | $MM | $180 - $210 | $160 - $190 |
Colombia and Ecuador Exploration | $MM | $35 - $45 | $30 - $40 |
Other(9) | $MM | $15 - $25 | $10 - $15 |
Total Colombia & Ecuador Upstream Capex | $MM | $230 - $280 | $200 - $245 |
Colombia Infrastructure | $MM | $40 - $50 | $15 - $20 |
Guyana Exploration | $MM | $2 - $5 | $1 - $3 |
Total Capital Expenditures (10) | $MM | $272 - $335 | $216 - $268 |
Notes:
1 | The Company's 2025 average production guidance range does not include in-kind royalties, operational consumption, quality volumetric compensation or potential production from successful exploration activities planned in 2025. |
2 | Per-bbl/boe metric on a share before royalties' basis. |
3 | Calculated using net production after royalties. |
4 | Supplementary financial measure (as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures ("NI 52-112")). See "Advisories - Non-IFRS Financial and Other Measures". |
5 | Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). "Operating EBITDA" represents the operating results of the Company's Upstream business, excluding the following items: restructuring, severance and other costs, certain non-cash items and gains or losses arising from the disposal of capital assets. See "Advisories - Non-IFRS Financial and Other Measures". |
6 | Current Guidance Operating EBITDA calculated at Brent between $75/bbl and $80/bbl, and COP/USD exchange rate of 4,250:1. |
7 | Includes Puerto Bahia, SAARA and Proagrollanos. |
8 | Reported Adjusted Infrastructure EBITDA (previously referred to as Adjusted Midstream EBITDA) is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure business, including the proportional consolidation of the 35% equity investment in the ODL pipeline. |
9. | Other includes HSEQ activities and new field production technologies |
10 | Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). See "Advisories - Non-IFRS Financial and Other Measures". Capital expenditures excludes decommissioning. |
About Frontera's 2025 Capital, Production and Cash Flow Guidance
Frontera's 2025 capital and production guidance is based on an average Brent price of $75 - $80 /bbl, an average sales price oil differential of $4.50 /bbl, and an exchange rate of 4,250 Colombian Pesos per US dollar in 2025.
Other key 2025 guidance highlights include:
- Estimated $50 - $60 million in distributions to be received for the Company's interest in the ODL pipeline.
- Debt service payments are estimated to be approximately $45 - $55 million for 2025, including a payment of approximately $32 million for interest associated with the Company's 2028 senior notes.
- PIL debt service payments include $40 - $45 million of amortization payments as well as interest payments on the facility, reaching an estimated 2025 year-end balance range of $65 - $70 million (and down from just over $100 million at year-end 2024).
Upstream Business ($millions) | $75/Brent | $80/Brent |
Upstream Operating EBITDA | $350 - $380 | $400 - $430 |
Cash Taxes(1) | $(10) - $(15) | $(15) - $(20) |
Debt Service(2) | $(45) - $(55) | $(45) - $(55) |
Upstream Capex | $(200) - $(245) | $(200) - $(245) |
2025 Upstream Free Cash Flow | $65 - $95 | $110 - $140 |
Infrastructure Business | ($millions) |
Infrastructure Operating EBITDA(3) | $20 - $35 |
ODL Dividends, net of taxes | $50 - $60 |
PIL Debt Service, net | $(40) - $(45) |
Infrastructure Capex | $(15) - $(20) |
2025 Infrastructure Free Cash Flow | $15 - $30 |
Notes:
1 | Cash taxes paid including withholding taxes, VAT payments and estimated tax recoveries. |
2 | Debt service includes interest on the 2028 senior notes, Agrocascada working capital loans debt service payments, prepayment financing expenses, LC fees and operational leases. |
3 | Includes Puerto Bahia, SAARA and Proagrollanos. |
Colombia and Ecuador Upstream Production and Operating Costs Guidance
In the Company's core Colombia and Ecuador Upstream business, Frontera plans to produce 41,000-43,000 boe/d while reducing capital investment by 13% to $200 - $245 million compared to 2024.
The Company's 2025 average daily production guidance range does not include in-kind royalties, operational consumption, volumetric compensation or, potential production from successful exploration activities planned in 2024. The Company anticipates delivering between $350 to $380 million and $400 to $430 million in Operating EBITDA in 2025 from its Upstream operations at $75 /bbl and $80 /bbl average Brent prices, respectively.
See below for additional details on the Company's key operating cost drivers:
In USD per barrel | 2024 | 2025 | Midpoint |
Production Costs (ex. Energy Cost) | $8.50 - $9.50 | $8.75 - $9.25 | - |
Energy Costs | $5.75 - $6.25 | $5.25 - $5.75 | (8) % |
Total Production Costs | $14.25 - $15.75 | $14.00 - $15.00 | (3) % |
Transportation Costs | $11.00 - $12.00 | $12.50 - $13.00 | 11 % |
Total Production & Transportation Costs | $25.25 - $27.75 | $26.50 - $28.00 | 3 % |
The Company estimates 2025 production costs to remain flat compared to 2024 levels and to average $8.75 - $9.25 per boe, excluding energy costs reflecting the positive impact of implemented cost savings initiatives partially offset by incremental costs associated with additional water handling and treatment volumes (primarily associated to SAARA) and continued inflationary pressures.
Energy costs, which include electricity consumption and the costs of in-situ power generation, are expected to average $5.25 - $5.75 per boe, driven by higher energy use associated with increasing heavy crude oil production.
Transportation costs for 2025 are forecasted to average $12.50 - $13.00 per boe reflecting primarily increases in trucking tariffs resulting from changes to Colombian diesel subsidies starting in 2024 and stepping up in 2025 as well as inflation-related pipeline tariffs increases.
2025 Additional Estimates Sensitivities
Brent Crude Oil Price ($/bbl) | $65 | $75 | $85 |
Consolidated Operating EBITDA ($MM) | $270 - $315 | $370 - $415 | $460 - $505 |
Cash Taxes ($MM)(1) | $(0) - $(5) | $(10) - $(15) | $(20) - $(25) |
Note:
1 Cash taxes paid including withholding taxes, VAT payments and estimated tax recoveries. |
About Frontera's 2025 Upstream Spending
Frontera's anticipates its total 2025 Colombia and Ecuador Upstream capital expenditures will be $200 - $245 million which represents an approximately 13% decrease at the midpoint compared to the Company's 2024 capital budget. 2025 Capital expenditures will support development and exploration activities as shown below.
Development Activities
Frontera anticipates spending approximately $100 - $110 million to drill up to 62 wells (60 producer wells and 2 injector wells) in 2025 and approximately $60 - $80 million on development facilities primarily supporting activities in CPE-6 and Quifa.
Colombia
- Quifa block: Frontera plans to drill 26 wells (25 producer wells and 1 injector well) in the Quifa SW field and install additional production and injection facilities. At the Cajua field, Frontera plans to drill 15 producer wells and facilities for the field.
- CPE-6 block: The Company plans to drill 20 wells (19 producer wells and 1 injector well) and install additional flow handling and injector line facilities.
Ecuador
- Perico block (Frontera 50% W.I. and operator): The Company intends to drill the Perico Centro 3 well in 2025 (subject to regulatory and partner approval).
Other capital expenditures include plans to invest in regulatory and HSEQ activities and in field production technologies looking to enhance production efficiency and reduce water production.
Exploration:
In 2025, the Company anticipates investing $30 - $40 million on various exploration activities including:
- Drilling the high-impact Hidra-1 exploration well in the VIM-1 Block (Frontera 50% W.I., non-operator). The well is expected to spud during the first half of 2025.
- Drilling the Greta Norte-1 well in the Cachicamo block in January 2025, a follow up to the Papilio-1 well.
- Drilling the Llanera-1 well in the Llanos 99 block.
- Carrying out pre-seismic and pre-drilling activities in the VIM-46 block in Colombia.
About Frontera's 2025 Colombian Infrastructure Spending
In the Company's Colombia infrastructure business, Frontera expects to generate between $20 - $35 million in segment Operating EBITDA and between $115 - $130 million in Adjusted Infrastructure EBITDA. The expected year over year increase is driven by additional EBITDA generated from the Reficar connection start up and additional revenues from SAARA. Frontera anticipates investing $15 - $20 million primarily for:
- Puerto Bahia : Commissioning and completion works related to the Reficar connection and maintenance activities for the port.
- SAARA & Proagrollanos: Investments related to palm oil plantation biological asset maintenance, water handling infrastructure and the SAARA facility.
2025 Hedging Program
Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40-60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, allowing the Company to take a more dynamic approach to the management of its hedging portfolio. The following table summarizes Frontera's 2025 hedging position as of December 10, 2024.
Term | Type of Instrument | Open Positions (bbl/d) | Strike Prices Put/Call |
Jan 25 | Put | 11,000 | 70.00 |
Feb 25 | Put | 18,786 | 70.00 |
Mar 25 | Put | 16,935 | 70.00 |
1Q-2025 | Total Average | 15,467 | 70.00 |
The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of December 10, 2024, the Company had entered into new positions of foreign currency derivatives contracts as follows:
Term | Type of Instrument | Open Interest (US$ MM) | Strike Prices Put/ Call | Hedging Ratio | |
1Q-2025 | Zero-cost Collars | 60 | 4,150 / 4,618 | 40 % | |
2Q-2025 | Zero-cost Collars | 60 | 4,200 / 4,626 | 40 % | |
3Q-2025 | Zero-cost Collars | 60 | 4,200 / 4,795 | 40 % | |
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 infrastructure facilities. The Company has a diversified portfolio of assets with interests in 22 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.
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Advisories:
Cautionary Note Concerning Forward-Looking Information
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 relating to the Company's expectations regarding operational and financial progress throughout the year; estimates and/or assumptions in respect of corporate strategy, statements relating to the Company's guidance and objectives for 2025 (including production levels, intended capital investments, production costs, energy costs, transportation costs, operating EBITDA, average Brent prices, capital expenditures and certain income taxes payable by the Company); statements regarding the Company's debt service payments; statements regarding the Company's water handling capacity and anticipated growth in production, including expectations regarding expected impacts of the Company's reverse osmosis water treatment facility (SAARA); anticipated exploration, development and drilling activities and seismic acquisition; statements regarding the construction of the Company's Reficar connection project; statements regarding expected production and cash flows; expectations regarding possible shareholder enhancement initiatives; including additional dividends, distributions and bond buybacks; the expectation that the Corentyne block JV's license will be validated and steps that may be taken to safeguard its interest in the Corentyne block and Guyana; and expectations with respect to the Company's hedging strategy. All information other than historical fact is forward-looking information.
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 actions of the Organization of Petroleum Exporting Countries ("OPEC") and the impact of the Russia - Ukraine conflict and the Israel -Palestine conflict, and the expected impact of measures that the Company has taken and continues to take in response to these events; expectations regarding the Company's ability to manage its liquidity and capital structure and generate sufficient cash to support operations, capital expenditures and financial commitments; the performance of assets and equipment; the Company's ability to achieve the increased oil and water handling capacity at Quifa in the time frames indicated; the availability and cost of labor, services and infrastructure; the execution of exploration and development projects; advice obtained with respect to the Corentyne block JV's license; the receipt of any required regulatory approvals and outcome of discussions with governmental authorities; and the success of the Company's hedging strategy.
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 March 7, 2024, its annual management's discussion and analysis for the year ended December 31, 2023, and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to the company's profile on SEDAR+ at www.sedarplus.ca. All forward-looking information 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 information, whether as a result of new information, future events, or results or otherwise.
Certain information included in this news release may constitute future oriented financial information and/or financial outlook (collectively, "FOFI") within the meaning of applicable Canadian securities laws. Such FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. Management believes that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments; however, actual results of the Company's operations and the resulting financial outcome may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it was made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or otherwise, unless required by applicable laws.
Non-IFRS Financial and Other Measures
This news release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52-112) and "supplementary financial 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 and supplementary financial measures used in this news release.
Operating EBITDA
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 June 30, 2022, the Company changed the composition of its Operating EBITDA calculation to exclude certain unusual or non-recurring items as post-termination obligations and payments of minimum work commitments, which could distort future projections as they are not considered part of the Company's normal course of operations.
The equivalent historical non-GAAP financial measure to 2025 operating EBITDA guidance is operating EBITDA for the year ended December 31, 2023. The most recent period for which financial results are available is the nine months ended September 30, 2024. Net income (loss) is the most directly comparable financial measure to operating EBITDA.
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.
Production Cost Per Boe, Energy Cost Per Boe, Transportation Cost Per Boe
Production costs mainly include lifting costs, activities developed in the blocks, and processes to put the crude oil and gas in sales condition and excludes energy costs. Production cost per boe is a supplementary financial measure that is calculated using production cost divided by production (before royalties).
Energy costs mainly include electricity consumption and the costs of localized energy generation. Energy cost per boe is a supplementary financial measure that is calculated using energy cost divided by production (before royalties).
Transportation costs include all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline. Transportation cost per boe is a supplementary financial measure that is calculated using transportation cost divided by net production after royalties.
Adjusted Infrastructure EBITDA
Adjusted Infrastructure EBITDA refers to the Adjusted EBITDA for the Infrastructure segment including the proportional consolidation of the 35% equity investment in the ODL pipeline accounted for using the equity method for consolidated financial statement purposes. Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Segment business.
Oil and Gas Information Advisories
Reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.
The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy.
Definitions
bbl(s) | Barrel(s) of oil |
bbl/d | Barrel of oil per day |
boe | Refer to "Boe conversion" disclosure above |
boe/d | Barrel of oil equivalent per day |
Mcf | Thousand cubic feet |
W.I. | Working Interest |
SOURCE Frontera Energy Corporation
