Frontera Announces 2023 Capital And Production Guidance
Frontera Provides Update on Estimated 2022 Full-Year Daily Average Production
CALGARY, AB, Feb. 1, 2023 /PRNewswire/ - Frontera Energy Corporation (TSX: FEC) ("Frontera"' or the "Company") announces its full year 2023 capital and production guidance and provides an update on its normal course issuer bid ("NCIB"), its 2023 hedging program and its estimated fourth quarter and 2022 full year average daily production. All values in this news release and the Company's financial disclosures are in United States dollars, unless otherwise noted.
Summary of Frontera's 2023 Capital and Production Guidance
2023 Full Year Guidance Frontera Consolidated
Average Daily Production(1)
40,000 - 43,000
Production Costs (2)
$12.50 - $13.50
Transportation Costs (3)
$10.50 - $11.50
2023 Cash Income Taxes at $80/bbl
$40 - $60
Operating EBITDA(4) at $75/bbl (5)
$375 - $425
Operating EBITDA(4) at $80/bbl (5)
$425 - $475
Operating EBITDA(4) at $85/bbl (5)
$475 - $525
$110 - $130
$75 - $85
Colombia and Ecuador Exploration
$50 - $60
Colombia Infrastructure (6)
Total Colombia & Ecuador Capex
$265 - $315
$120 - $140
Total Capital Expenditures (8)
$385 - $455
1 The Company's 2023 average production guidance range does not include in-kind royalties, operational consumption, quality volumetric compensation or potential production from successful exploration activities planned in 2023.
2 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." Per-barrel metric on a share before royalties basis; excludes costs related to ProAgrollanos, Peru and SAARA expansion in 2023.
3 Supplementary financial measure (as defined in NI 52-112). See "Advisories – Non-IFRS Financial and Other Measures." Calculated using net production after royalties.
4 Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). On August 11, 2022, the Company issued updated guidance for full year 2022, including operating EBITDA guidance of $675-$700 million at $100/bbl. The equivalent historical non-GAAP financial measure to 2023 operating EBITDA guidance is operating EBITDA for the year ended December 31, 2021, which was $373.2 million. Operating EBITDA for the nine months ended September 30, 2022, the most recent period for which financial results are available, was $496.9 million. Net income (loss) is the most directly comparable financial measure to operating EBITDA. A reconciliation of net income (loss) to operating EBITDA for the year ended December 31, 2021 and the nine months ended September 30, 2022 is set forth under "Advisories – Non-IFRS Financial and Other Measures".
5 Current Guidance Operating EBITDA calculated at Brent $80/bbl and COP/USD exchange rate of 4600:1.
6 Colombian Infrastructure refers to Puerto Bahia capital expenditures.
7 Other includes the CPE-6 solar plant project, investment in equipment covered by insurance proceeds, investment in new technologies and HSEQ.
8 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 expenses (approximately $14 million).
Orlando Cabrales, Chief Executive Officer, Frontera, commented:
"Frontera's 2023 capital program aims to deliver stable cash flow and $425-$475 million operating EBITDA at $80/bbl average Brent prices from the Company's proven and diverse asset base while also investing for future growth through facilities expansion and both near-field and high-impact exploration. Frontera anticipates investing approximately $185-$205 million to deliver approximately 40-43,000 boe/d, a 13% decrease in development spending as compared to 2022. The 2023 program is fully funded from existing cash and 2023 cash flows, features balanced capital allocation across our most productive and prospective blocks, basins, and countries, supports our ongoing efforts to diversify our production mix and lays the foundation for the Company's path to grow production to 50,000 boe/d.
In 2023, we will advance the Company's exciting development and lower-risk exploration portfolio in Colombia and Ecuador, invest in infrastructure and facilities at Quifa and CPE-6 to increase production, leverage our advantaged transportation and logistics structure to maximize realized prices, mature our self-sustaining and growing midstream business including Puerto Bahia and ODL, execute our hedging program to protect our revenue generation and manage our exposure to price volatility, and seek to build on our Kawa-1 light oil and condensate discovery with the Wei-1 well, our second exploration well offshore Guyana."
About Frontera's 2023 Capital and Production Guidance
The Company developed its 2023 capital and production guidance using an average 2023 Brent price of $80/bbl and an exchange rate of approximately 4,600 Colombian Pesos per US dollar. The Company's 2023 Plan for Colombia and Ecuador is self-funded. The Company expects to fund its Guyana exploration program from existing resources.
$425 - $475
Cash Income Taxes
($40) - ($60)
Debt Service (1)
($45) - ($50)
Total Colombia & Ecuador Capex
($265) - ($315)
Colombia & Ecuador Free Cash Flow
1. Excludes non-recourse debt to Frontera
The Company anticipates total capital spending of approximately $385 to $455 million in 2023, which is approximately 10% lower at the midpoint compared to Frontera's 2022 Guidance. Frontera's anticipated total Colombia and Ecuador capital expenditures of $265-$315 million represents approximately 70% at the midpoint of the Company's 2023 capital budget. Capital expenditures will be divided between development and exploration activities as shown below.
The Company anticipates directing approximately $215-$255 million towards the Company's base Colombia and Ecuador upstream activities. Frontera anticipates spending approximately $110-$130 million to drill 55 gross production wells, mainly in Quifa SW, CPE-6, Cajua and Copa fields, complete 24 gross well interventions and drill two injector wells, and approximately $75-$85 million on development facilities primarily to increase oil and water handling capacity at CPE-6 and Quifa.
Quifa: Frontera plans to drill 27 production wells, complete 18 well workovers and install additional flow lines in 2023. Frontera will also continue developing its SAARA water treatment project, which if successful is expected to increase water disposal capacity. Frontera's SAARA water treatment facility will diversify produced water disposal options from the Quifa field for irrigation use at the ProAgrollanos palm oil plantation.
CPE-6: The Company plans to drill 18 production wells and two injector wells and install additional flow lines in 2023. As part of its multi-year development plan, Frontera also plans to increase water-handling capacity by 100% from approximately 120,000 bbls/day to 240,000 bbls/day by year-end, supporting additional future growth for this field.
Other fields: Frontera plans to drill five production wells at Cajua, two producer wells in the Copa field at Cubiro, two production wells and one production well at the Perico block in Ecuador.
Colombian Infrastructure: Puerto Bahia plans to invest approximately $5-10 million in expanding its container business capabilities as well as in maintenance activities related to its hydrocarbon terminal.
Other Capex: Frontera plans to invest $25-30 million primarily on a 9MW solar plant at CPE-6, investment in equipment covered under existing insurance policies and new well technologies. These Other capital expenditures will be offset by $10-15 million in insurance proceeds.
Frontera intends to invest $170-$200 million on its Colombia, Ecuador, and Guyana exploration programs.
Colombia and Ecuador: In 2023, the Company anticipates spending $50-$60 million on various exploration activities in Colombia and Ecuador including drilling the Chimi-1, Winner-1 and Tubara South-1 exploration wells in VIM-22 block in Colombia and the Yin Sur-1 well in Ecuador; complete civil works on the VIM-1 block at the Hydra well location; carry out initial seismic activities at VIM-46 block; complete an 80-kilometre seismic acquisition program and begin civil works at the Sol Nor-1 and Sol Nor-2 locations at the LLA-119 block; and complete an 164-kilometre seismic acquisition program and Environmental Impact Assessment at LLA-99.
Guyana: On the Corentyne block, offshore Guyana, Frontera anticipates spending approximately $120-$140 million on the Wei-1 well, which will be funded from existing resources. The total cost of the Wei-1 well (including 2022 pre-drill costs and costs related to drilling delays) are forecast to be approximately $160-$170 million. The Wei-1 well is located approximately 14 kilometres northwest of the Joint Venture's previous Kawa-1 light oil and condensate discovery and will target Maastrichtian, Campanian and Santonian aged stacked sands within channel and fan complexes in the northern section of the Corentyne block. The Wei-1 well will appraise both the Kawa-1 discovery as well as explore additional opportunities within the Corentyne block.
Operating EBITDA Sensitivities
Every one-dollar average annual change to the Company's $80/bbl Brent price assumption for 2023 impacts operating EBITDA by approximately $10 million including hedging. See the table below for illustrative Brent pricing sensitivities.
2023 Full Year Guidance Frontera Consolidated
At $75/bbl (2)
$375 - $425
At $80/bbl (2)
$425 - $475
At $85/bbl (2)
$475 - $525
1 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."
2 Current Guidance Operating EBITDA calculated at Brent $80/bbl and COP/USD exchange rate of 4600:1.
Relative to 2022 Guidance, forecast Operating EBITDA for 2023 is expected to be impacted largely by a decrease in average commodity prices, higher inflation and partially offset by a weaker Colombian Peso exchange rate. Frontera's 2022 updated financial and operating guidance was developed using an average Brent price of $100/bbl while Frontera's 2023 financial and operating guidance was developed using an $80/bbl average Brent price. The Company's 2023 forecast sales volumes are expected to be similar to 2022 Guidance, however lower revenues are anticipated in 2023 due to lower expected average Brent prices for the year. In addition, the Company is working to partially offset the Operating EBITDA impact of higher inflation in Colombia (13.1% in 2022) to its operating costs through a number of cost savings initiatives and an expected weaker Colombian Peso exchange rate relative to the US dollar.
Enhancing Shareholder Returns
Since 2018, Frontera has returned approximately $300 million to shareholders while maintaining a strong credit profile. Under its current NCIB that expires on March 16, 2023, Frontera is authorized to repurchase for cancellation up to 4,787,976 common shares. To date under its current NCIB, the Company has repurchased approximately 4.1 million common shares, or over 85% of its approved NCIB amount, with approximately 700,000 additional common shares available for repurchase under its current NCIB.
Frontera remains committed to returning capital to shareholders. As part of its 2023 plan, the Company shall continue to consider future shareholder value enhancement initiatives.
2023 Hedging Program
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. Consistent with this strategy, the Company entered into new put hedges totaling 2,160,000 bbls to protect a portion of the Company's production through May 2023. The following table summarizes Frontera's 2023 hedging position as of February 1, 2023.
Colombian Tax Reform
In November 2022, the Colombian government approved tax reforms that will increase costs from 2023 onwards for Colombian oil and gas producers. The tax reform has two main impacts on the oil and gas industry. First, a 5 to 15% tax surcharge when current average oil prices exceed by 30% or more the average oil price over the last 10 years. Second, the tax reform makes royalties non-deductible. Treatment of high price participation (PAP) payments is not affected. Under the tax reform, oil and gas companies will not be permitted to deduct operating costs and capital expenditures associated with royalties paid whether in-kind or in-cash.
2023 Cash Income Taxes(1)
2023 Full Year Guidance Frontera Consolidated
$35 - $50
$40 - $60
$45 - $75
12023 cash income taxes under the new tax reform including withholding taxes.
2Average Brent prices for the year.
Estimated 2022 Production
Frontera's estimated 2022 average daily production of approximately 41,400 boe/d was in-line with the Company's 2022 increased and tightened production guidance of 41,000 to 43,000 boe/d and represents an approximately 9.5% increase compared to the Company's 2021 average production. Frontera's estimated average daily production for the fourth quarter was approximately 41,800 boe/d and Frontera's estimated average daily production in December was approximately 42,200 boe/d. See the table below for production by product type.
Heavy crude oil production (1)
Light and medium crude oil production (1)
Total crude oil production
Conventional natural gas production (1)
Natural gas liquids (1)
Total production (2)
1. References to heavy crude oil, light and medium crude oil combined, natural gas liquids and conventional natural gas production in the above table and elsewhere in this press release refer to the heavy crude oil, light and medium crude oil combined, natural gas liquid, and conventional natural gas, respectively, product types as defined in National Instrument ("NI") 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 30 of the Company's management's discussion and analysis for the three and nine months ended September 30, 2022 (the "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 30 of the MD&A.
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 32 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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Cautionary Note Concerning Forward-Looking Statements
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 the Company's operational and financial progress throughout the year; estimates and/or assumptions in respect of corporate strategy; the Company's guidance for 2023 (including production levels, production costs, transportation costs, operating EBITDA and capital expenditures); expectations regarding the Company's current NCIB; expectations with respect to the Company's hedging strategy; expectations with respect to certain income taxes payable by the Company; expectations regarding possible shareholder enhancement initiatives; and the Company's exploration and development plans and objectives, including its drilling plans and the timing thereof. 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 potential impacts of the COVID-19 pandemic, actions of the Organization of Petroleum Exporting Countries, the impact of the Russia-Ukraine conflict, and the expected impact of measures that the Company has taken and continues to take in response to these events; the performance of assets and equipment; reforms that may be undertaken by the Government of Colombia; the availability and cost of labour, services and infrastructure; the development and execution of exploration and development projects; 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 2, 2022, its annual management's discussion and analysis for the year ended December 31, 2021, 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.sedar.com. 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 financial outlook information (collectively, "FOFI") within the meaning of applicable Canadian securities laws. The 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 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 and supplementary financial measures used in this news release.
EBITDA is a commonly used non-IFRS financial measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and depletion, depreciation, and amortization expense.
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 obligations and 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. In addition, the Company excludes 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 2023 operating EBITDA guidance is operating EBITDA for the year ended December 31, 2021. The most recent period for which financial results are available is the nine months ended September 30, 2022. Net income (loss) is the most directly comparable financial measure to operating EBITDA. The following table provides a reconciliation of net income (loss) to operating EBITDA for the year ended December 31, 2021 and the nine months ended September 30, 2022.
Nine months ended
Net income (loss)
Income tax expense (recovery)
Depletion, depreciation, and amortization
Impairment (reversal) expense and others
Cost under terminated pipeline contracts
Share-based compensation non cash portion
Restructuring, severance, and other costs
Share of income from associates
Foreign exchange loss (gain)
Other (income) loss, net
Unrealized gain (loss) on risk management contracts
Loss on extinguishment of debt
Reclassification of currency translation adjustments
Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by a company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration, and evaluation assets.
Production 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. Production cost per boe is a supplementary financial measure that is calculated using production 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, pipeline and refining processing fees. Transportation cost per boe is a supplementary financial measure that is calculated using transportation cost divided by net production after royalties.
Oil and Gas Information Advisories
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.
bbl(s): Barrel(s) of oil
bbls/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
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SOURCE Frontera Energy Corporation