Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks, including the effects of adverse changes in foreign exchange rates and commodity prices as described below.
Foreign Exchange Rate Risk
Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of December 31, 2024, we had net monetary assets of $35 million (XAF 22.0 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $3.2 million reduction in the value of these net assets. For the year ended December 31, 2024, we had expenditures of approximately $64 million denominated in XAF.
Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. We estimate that a 10% increase in the value of the Canadian dollar against the US dollar would decrease net earnings for the year ended December 31, 2024 by approximately $0.5 million. Conversely, a 10% decrease in the value of the Canadian dollar against the US dollar would increase net earnings for the year ended December 31, 2024 by approximately $0.4 million.
We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates at December 31, 2024, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase net earnings for the year ended December 31, 2024 by approximately $0.2 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease net earnings for the year ended December 31, 2024 by approximately $0.1 million.
In Cote d'Ivoire, our currency exchange risk also relates primarily to certain cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities denominated in Swedish Krona. We estimate that a 10% decrease in the value of the Swedish Krona against the US dollar would decrease the value of the net liabilities for the year ended December 31, 2024 by approximately $2.1 million. Conversely, a 10% increase in the value of the Swedish Krona against the US dollar would decrease the value of the net liabilities for the year ended December 31, 2024 by approximately $2.6 million.
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We do not utilize derivative instruments to manage foreign exchange risk. We maintain nominal balances of British Pounds Sterling to pay in-country costs incurred in operating our London office. Foreign exchange risk on these funds is not considered material.
Commodity Price Risk
Our major market risk exposure continues to be the prices received for our crude oil, natural gas and NGLs production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil, natural gas and NGLs have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low crude oil, natural gas and NGLs prices or a presumption of the decreases in crude oil, natural gas and NGLs prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.
Oil and gas properties are assessed for impairment annually as well as whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital and operating expenditures, using a commensurate discount rate. Unfavorable changes in any of these assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertainties related to the primary assumptions could affect the timing of an impairment. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future oil and gas prices. We observed a decline in commodity prices during the year ended December 31, 2024 which prompted us to evaluate the recoverability of the carrying value of our assets and whether an other than temporary impairment occurred for certain oil and gas properties. As a result of these tests, no impairments were recorded during the year ended December 31, 2024; however, certain oil and gas properties may be at risk for impairment if the estimates of future cash flows decline.
It is also reasonably possible that prolonged low or further decline in commodity prices, negative reserve revisions, changes to the Company's drilling plans in response to lower prices or increases in drilling or operating costs could result in material future impairment charges.
If crude oil sales were to remain constant at the most recent annual sales volumes, a $5 per Bbl decrease in crude oil price would decrease our revenues and operating income or increase our operating loss for the year as follows:
2024 Sales Volumes (Mbls) Decrease in Revenues (In Millions) Decrease in Operating Income (Increase in Operating Loss) (In Millions)
Gabon 2,584 $ 12.9 $ 11.6
Egypt 2,585 $ 12.9 $ 7.7
Cote d'Ivoire 1,223 $ 6.1 $ 3.2
Canada 870 $ 4.3 $ 3.3
Consolidated 7,262
With respect to our crude oil sales in Gabon, Egypt and Cote d'Ivoire the price received is based on Dated Brent prices plus or minus a differential. With respect to our crude oil and NGLs sales in Canada, the prices received is based on NYMEX WTI (West Texas Intermediate) prices plus or minus a differential. Natural gas sales are based on Canadian index price that whose price is based, in part, on the NYMEX Henry Hub Natural Gas futures contracts.
Egypt production is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (Cost Oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company’s recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as “excess”. In Egypt, depending on the PSCs, our share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically, maximum Cost Oil ranges from 25% to 40% in Egypt. The balance of the production after maximum
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cost recovery is shared with the government as Profit Oil. Depending on the contract, the Egyptian government receives 67% to 84% of the Profit Oil. Production sharing splits are set in each contract for the life of the contract. Typically, the government’s share of Profit Oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less Cost Oil and may receive more Profit Oil. During times of lower oil prices, the Company receives more Cost Oil and may receive less Profit Oil.
Outstanding derivative contracts at December 31, 2024 are as follows:
Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average Put Price Weighted Average Call Price
(Bbls) (per Bbl) (per Bbl)
January 2025 - March 2025 Collars Dated Brent 70,000 $ 65.00 $ 85.00
April 2025 - June 2025 Collars Dated Brent 70,000 $ 65.00 $ 81.00
Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average SWAP Price in CAD
(GJ) (a)
(per GJ)
January 2025 - March 2025 Swap AECO (7A) 67,000 $ 2.80
(a) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is about 25.5 cubic metres at standard conditions.
Subsequent to December 31, 2024, the Company entered into the following additional derivative contracts to cover its future anticipated production:
Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average Put Price Weighted Average Call Price
(Bbls) (per Bbl) (per Bbl)
July 2025 - September 2025 Collars Dated Brent 60,000 $ 65.00 $ 80.00
Interest Rate Risk
At both December 31, 2024 and on the filing date of this Annual Report, we had a zero balance outstanding on our Facility. Subsequent to December 31, 2024, we entered into the 2025 Facility Agreement, which governs the 2025 Facility. Loans under the 2025 Facility will bear interest at a rate equal to Term SOFR (as defined in the 2025 Facility Agreement) plus the applicable margin (the “Applicable Margin”) of (i) 6.50%, from the date of the 2025 Facility Agreement until the date on which the renovation and repair of the floating production storage and offloading tanker facility named Baobab Ivorian MV10 FPSO for use in connection with the development of the Baobab field meets certain completion tests defined in the 2025 Facility Agreement and (ii) thereafter, 6.00% until the Final Maturity Date (as defined in the 2025 Facility Agreement). Any increases in these interest rates can have an adverse impact on our results of operations and cash flows. For additional information on the 2025 Facility Agreements terms and conditions, see Part IV, Item 15., Note 13. Debt and Note 20. Subsequent Events to the Consolidated Financial Statements.
Item 8. Consolidated Financial Statements and Supplementary Data
The information required here begins on page F-1 as described in “ Item 15. Exhibits and Financial Statement Schedules — Index to Consolidated Financial Information ”.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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