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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

2025-03-17 compared with 2024-03-15 · 49 added, 26 removed, 47 unchanged (61% of the section changed)

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in foreign exchange rates and commodity prices as described below.

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

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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.

We do not utilize derivative instruments to manage foreign exchange risk.

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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 resumption 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.

If crude oil sales were to remain constant at the most recent annual sales volumes of 6,832 MBoe, a $5 per Bbl decrease in crude oil price would be expected to cause a $34.2 million decrease per year in revenues and operating income (loss) and a $25.4 million decrease per year in net income (loss).

With respect to our crude oil sales in Gabon, the price received is based on Dated Brent prices plus or minus a differential.

If crude oil sales were to remain constant at the most recent annual sales volumes of 3,196 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $16.0 million decrease per year in revenues and operating income (loss) and a $14.3 million decrease per year in net income (loss).

Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs.

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 VAALCO’s recognition of costs and their recovery as VAALCO accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis.

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”.

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Typically, maximum Cost Oil ranges from 25% to 40% in Egypt.

The balance of the production after maximum cost recovery is shared with the government (profit oil).

The balance of the production after maximum

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.

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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-sharing oil.

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.

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.

If Canadian BOE sales were to remain constant at the most recent yearly sales volumes of 865 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $4.3 million decrease per year in revenues and operating income (loss) and a $3.3 million decrease per year in net income (loss).

As of December 31, 2023, we had unexpired derivative instruments outstanding covering approximately 450 MBbls of production through June of 2024.

To date in 2024, we added costless collars covering 240 MBbls covering a portion of our production from July 2024 - September 2024.

During the year ended December 31, 2022, we had derivative instruments outstanding.

These instruments were intended to be an economic hedge against declines in crude oil prices;

however, they were not designated as hedges for accounting purposes.

See “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operation s – Derivative instruments and hedging activities ” above.

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

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, 2023 and on the filing date of this Annual Report, we had a zero balance on our Facility.

Loans under the Facility will bear interest at a rate equal to SOFR plus the Applicable Margin of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date.

On October 3, 2023, the Company signed an Amended and Restated Facility Agreement to replace the LIBOR component in the original Facility Agreement, with a SOFR plus credit adjustment spread rate.

The SOFR plus credit adjustment spread rate is intended to approximate the LIBOR component in the original Facility Agreement.

The LIBOR component was replaced due to the phase out of LIBOR as a global reference rate.

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 Facility Agreements terms and conditions, see “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity—RBL Facility Agreement and Available Credit ” above.

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.

Consolidated Financial Statements and Supplementary Data

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7A. Quantitative and Qualitative Disclosures About Market Risk