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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1.ORGANIZATION AND ACCOUNTING POLICIES
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids (“NGLs”) properties. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and holds interests in two production sharing contracts (“PSCs”) in Egypt and holds a non-operator interest in Cote d’Ivoire. The Company has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa and Nigeria.
These unaudited condensed consolidated financial statements (“Financial Statements”) reflect the opinion of management and all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.
These unaudited interim condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, which includes a summary of the significant accounting policies.
Allowance for credit losses and other – The Company estimates the current expected credit losses based primarily using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected.
The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Allowance for credit losses and other
Balance at beginning of period
$
(12,604)
$
(13,519)
$
(6,029)
$
(8,704)
Credit loss charges and other, net of receipts
(69)
(822)
(5,222)
(2,437)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023
—
—
—
(3,120)
Reversal of allowance resulting from the settlement of the related receivable
In August 2023, the Financial Accounting Standards Board (“FASB”) issued new guidance to provide specific guidance on how a joint venture, upon formation, should recognize and initially measure assets contributed to and liabilities assumed by such joint venture. The rules become effective prospectively for all joint venture formations occurring on or after January 1, 2025.VAALCO is currently assessing the impact of this guidance on the consolidated financial statements.
In November 2023, FASB issued new guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The rules become effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024.The standard requires additional disclosures about operating segments. VAALCO is currently evaluating the impact of adopting this guidance on the consolidated financial statements.
In December 2023, FASB issued new guidance to improve income tax disclosures to provide information to assess how an entity’s operations and related tax risks and tax planning and operational opportunities affect its tax rate and prospects for future cash flows. The rules become effective for annual periods beginning afterDecember 15, 2024. The standard modifies required income tax disclosures. VAALCO is currently evaluating the impact of adopting this guidance on the consolidated financial statements.
In November 2024, the FASB issued ASU 2024-03, Accounting Standards Update 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. VAALCO is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements and processes.
3. ACQUISITION
On February 29, 2024, the Company entered into a Share Purchase Agreement (the “Share Purchase Agreement”) to purchase all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for $66.5 million in cash (the “Purchase Price”), subject to certain adjustment as described in the Share Purchase Agreement (the “Svenska Acquisition”). The Company subsequently closed the Svenska Acquisition for
the net purchase price of $40.2 million, onApril 30, 2024after certain regulatory and government approvals were received. The Purchase Price was funded with $40.2 million of VAALCO’s cash-on-hand. Cash acquired in the business combination included $31.8 million of cash and cash equivalents as well as restricted cash of $8.8 million which nets to $0.4 million cash received on the business combination as disclosed within the unaudited condensed consolidated statements of cash flows.
April 30, 2024
(in thousands)
Purchase Consideration
Cash
$
40,166
Total purchase consideration
$
40,166
April 30, 2024
(in thousands)
Assets acquired:
Cash and cash equivalents
$
31,789
Other receivables, net
830
Crude oil inventory
14,981
Prepayments and other
409
Crude oil, natural gas and NGLs properties and equipment, net
100,188
Restricted cash
8,788
Other LT receivables
33
Deferred tax asset
28,153
Total assets acquired
185,171
Liabilities assumed:
Accounts payable
(2,506)
State oil liability
(19,447)
Accrued tax settlement
(8,788)
Accrued accounts payable invoices
(21,692)
Accrued liabilities and other
(19,083)
Asset retirement obligations
(15,694)
Deferred tax liability
(37,897)
Total liabilities acquired
(125,107)
Bargain purchase gain
(19,898)
Total purchase price
$
40,166
All assets and liabilities associated with Svenska’s interest in the producing Baobab field as well as the non-producing discovery located offshore of Nigeria, including crude oil and natural gas properties, asset retirement obligations and working capital items, were recorded at their estimated fair value. The Company used estimated future crude oil prices as of the closing date, April 30, 2024, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other estimates were used by the Company to determine the fair value of certain assets and liabilities. The fair value of the acquired identifiable assets and liabilities is provisional pending the final valuations for crude oil, natural gas and NGLs properties and equipment, net, asset retirement obligations, accrued liabilities and other and deferred tax assets and liabilities. Svenska is subject to the legal and regulatory requirements, including but not limited to those related to environmental matters and taxation, in each of the jurisdictions in countries in which it operates.
VAALCO has conducted a preliminary assessment of liabilities arising from these matters in each of these jurisdictions and has recognized provisional amounts in its initial accounting for the Svenska Acquisition for all identified liabilities in
accordance with the requirements of Accounting Standards Codification (“ASC”) Topic 805. However, VAALCO is continuing its review of these matters during the measurement period, and if new information obtained about facts and circumstances that existed at the acquisition date identifies adjustments to the assets and liabilities initially recognized, as well as any additional assets and liabilities that existed at the acquisition date, the acquisition accounting will be revised to reflect the resulting adjustments to the provisional amounts initially recognized. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, a $19.9 million bargain purchase gain was recognized and is included in “Bargain purchase gain” under “Other income (expense)” in the unaudited condensed consolidated statements of operations and comprehensive income. The bargain purchase gain is primarily attributable to a stronger forward pricing curve for oil reserves than was used for the purposes of calculating the price paid for the business.
Post-Acquisition Operating Results. The table below summarizes amounts contributed by the Cote d’Ivoire assets acquired in the Svenska Acquisition to the Company's consolidated results for the period from April 30, 2024throughSeptember 30, 2024.
April 30, 2024 through September 30, 2024
(in thousands)
Crude oil, natural gas and natural gas liquids sales
$
67,035
Net income
$
5,589
The unaudited pro forma results presented below have been prepared to give effect to the Svenska Acquisition discussed above on the Company’s results of operations for the three and nine months endedSeptember 30, 2024and 2023, as if the acquisition had been consummated onJanuary 1, 2023.The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the Svenska Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
(in thousands)
Pro forma (unaudited)
Crude oil, natural gas and natural gas liquids sales
$
140,334
$
167,634
$
388,792
$
437,181
Operating income
$
44,083
$
54,759
$
82,174
$
139,595
Net income (loss) (a)
$
10,990
$
10,976
$
20,306
$
43,158
Basic net income (loss) per share:
Income (loss) from continuing operations
$
10,990
$
10,976
$
20,306
$
43,158
Net income (loss) per share
$
0.11
$
0.10
$
0.20
$
0.40
Basic weighted average shares outstanding
$
103,743
$
106,289
$
103,644
$
106,876
Diluted net income (loss) per share:
Income (loss) from continuing operations
$
10,990
$
10,976
$
20,306
$
43,158
Net income (loss) per share
$
0.11
$
0.10
$
0.20
$
0.40
Diluted weighted average shares outstanding
$
103,842
$
106,433
$
103,728
$
107,072
(a)The unaudited pro forma net income (loss) for the nine months ended September 30, 2024excludes a nonrecurring pro forma adjustment directly attributable to the Svenska Acquisition, consisting of a bargain purchase gain of $19.9 million.
4. SEGMENT INFORMATION
The Company’s operations are based in Gabon, Egypt, Canada, Equatorial Guinea and Cote d'Ivoire. Each of the reportable operating segments are organized and managed based upon geographic location. The Company’s Chief Executive Officer,
who is the chief operating decision maker, evaluates the operational results of each geographic segment separately, primarily based on operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and Other category is primarily corporate and operations support costs that are not allocated to the reportable operating segments.
Segment activity of continuing operations for the three and nine months ended September 30, 2024and 2023 as well as long-lived assets and segment assets at September 30, 2024 and December 31, 2023 are as follows:
Three Months Ended September 30, 2024
(in thousands)
Gabon
Egypt
Canada
Equatorial Guinea
Cote d'Ivoire
Corporate and Other
Total
Revenues:
Crude oil, natural gas and natural gas liquids sales
Crude oil, natural gas and natural gas liquids sales
$
171,936
$
106,399
$
27,577
$
—
$
—
$
305,912
Operating costs and expenses:
Production expense
59,077
38,239
8,136
1,007
301
106,760
FPSO demobilization and other costs
5,647
—
—
—
—
5,647
Exploration expense
51
1,208
—
—
—
1,259
Depreciation, depletion and amortization
43,885
37,519
13,406
—
148
94,958
General and administrative expense
1,284
435
—
310
14,806
16,835
Credit losses and other
2,137
—
—
300
—
2,437
Total operating costs and expenses
112,081
77,401
21,542
1,617
15,255
227,896
Other operating income (loss), net
(57)
(241)
—
—
—
(298)
Operating income (loss)
59,798
28,757
6,035
(1,617)
(15,255)
77,718
Other income (expense):
Derivative instruments loss, net
—
—
—
—
(2,268)
(2,268)
Interest income (expense), net
(4,254)
(1,581)
(4)
—
464
(5,375)
Bargain purchase gain
—
—
—
—
(1,412)
(1,412)
Other income (expense), net
9
—
1
(4)
(103)
(97)
Total other expense, net
(4,245)
(1,581)
(3)
(4)
(3,319)
(9,152)
Income (loss) before income taxes
55,553
27,176
6,032
(1,621)
(18,574)
68,566
Income tax expense
36,002
10,141
—
—
6,060
52,203
Net income (loss)
$
19,551
$
17,035
$
6,032
$
(1,621)
$
(24,634)
$
16,363
Consolidated capital expenditures
$
15,173
$
32,084
$
16,008
$
—
$
36
$
63,301
(in thousands)
Gabon
Egypt
Canada
Equatorial Guinea
Cote d'Ivoire
Corporate and Other
Total
Long-lived assets:
As of September 30, 2024
$
158,256
$
153,636
$
110,474
$
10,038
$
94,387
$
4,798
$
531,589
As of December 31, 2023
$
171,787
$
171,224
$
105,189
$
10,000
$
—
$
1,586
$
459,786
(in thousands)
Gabon
Egypt
Canada
Equatorial Guinea
Cote d'Ivoire
Corporate and Other
Total
Total assets:
As of September 30, 2024
$
205,649
$
319,955
$
116,455
$
14,689
$
157,357
$
123,798
$
937,903
As of December 31, 2023
$
309,394
$
263,015
$
114,215
$
11,327
$
—
$
125,265
$
823,216
5.EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of
vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.
A reconciliation of reported net income to net income used in calculating EPS as well as a reconciliation from basic to diluted shares follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Net income (loss) (numerator):
Net Income
$
10,990
$
6,141
$
46,827
$
16,363
Income attributable to unvested shares
(145)
(66)
(491)
(122)
Numerator for basic
10,845
6,075
46,336
16,241
Loss attributable to unvested shares
—
(8)
—
(49)
Numerator for dilutive
$
10,845
$
6,067
$
46,336
$
16,192
Weighted average shares (denominator):
Basic weighted average shares outstanding
103,743
106,289
103,644
106,876
Effect of dilutive securities
99
144
84
196
Diluted weighted average shares outstanding
103,842
106,433
103,728
107,072
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive
734
530
437
336
6. REVENUE
Gabon
The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPA” or “COSPAs”) or crude oil sales and marketing agreements ("COSMA” or “COSMAs"). The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the Etame PSC.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues from customer contracts:
(in thousands)
Sales under the COSPA or COSMA
$
54,933
$
64,100
$
182,048
$
194,179
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment
652
1,378
1,826
3,590
Royalties
(7,977)
(8,203)
(25,088)
(25,833)
Net revenues
$
47,608
$
57,275
$
158,786
$
171,936
With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the unaudited consolidated statements of operations and comprehensive income, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. As ofSeptember 30, 2024 and December 31, 2023, the Company had a $35.7 million and $18.9 million, respectively, of foreign income tax payable, respectively.
The following table presents revenues in Egypt from contracts with customers:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues from customer contracts:
(in thousands)
Gross sales
$
63,432
$
88,748
$
191,938
$
193,570
Royalties
(28,714)
(37,944)
(84,550)
(86,176)
Selling costs
(174)
(497)
(402)
(995)
Net revenues
$
34,544
$
50,307
$
106,986
$
106,399
Canada
The following table presents revenues in Canada from contracts with customers:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues from customer contracts:
(in thousands)
Oil revenue
$
8,039
$
7,832
21,739
$
22,811
Gas revenue
224
988
1,429
2,649
NGL revenue
2,008
2,073
5,905
6,421
Royalties
(1,533)
(2,206)
(3,801)
(4,304)
Selling costs
(351)
—
(812)
—
Net revenues
$
8,387
$
8,687
24,460
$
27,577
Cote d'Ivoire
The following table presents revenues in Cote d'Ivoire from contracts with customers:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues from customer contracts:
(in thousands)
Revenues
$
49,795
$
—
$
67,035
$
—
Information about the Company’s most significant customers
For the three months ended September 30, 2024,the Company had one customer each that comprised 100% of its sales for Gabon, Egypt and Cote d'Ivoire. In Canada, three separate customers made up approximately 59%, 22% and 16% of its sales.
For the nine months ended September 30, 2024, the Company had one customer each that comprised 100% of its sales for Gabon, Egypt and Cote d'Ivoire. In Canada, three separate customers made up approximately 44%, 30% and 21% of its sales.
7.CRUDE OIL, NATURAL GAS AND NGLS PROPERTIES AND EQUIPMENT
The Company’s crude oil, natural gas and NGLs properties and equipment is comprised of the following:
As of September 30, 2024
As of December 31, 2023
(in thousands)
Crude oil, natural gas and NGLs properties and equipment - successful efforts method:
Wells, platforms and other production facilities
$
1,606,047
$
1,468,542
Work-in-progress
12,242
4,183
Undeveloped acreage
53,780
52,109
Equipment and other
67,239
47,794
Total crude oil, natural gas and NGLs properties, equipment and other
1,739,308
1,572,628
Accumulated depreciation, depletion, amortization and impairment
(1,207,719)
(1,112,842)
Net crude oil, natural gas and NGLs properties, equipment and other
$
531,589
$
459,786
8. DERIVATIVES AND FAIR VALUE
The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil and gas production by reducing the Company’s exposure to price fluctuations. See the table below for the list of outstanding contracts as ofSeptember 30, 2024:
Settlement Period
Type of Contract
Index
Average Monthly Volumes
Weighted Average Put Price
(Bbls)a
(per Bbl)
October 2024 - December 2024
Put Options
Dated Brent
125,000
$
65.00
a)The premium for these options was $4.01 per barrel and was paid in October 2023.
Settlement Period
Type of Contract
Index
Average Monthly Volumes
Weighted Average SWAP Price in CAD
(GJ)b
(per GJ)
November 2024 - March 2025
Swap
AECO (7A)
67,000
$
2.80
b)One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is about 25.5 cubic metres at standard conditions.
The following table sets forth the gain (loss) on derivative instruments on the Company’s unaudited condensed consolidated statements of operations and comprehensive income:
Three Months Ended September 30,
Nine Months Ended September 30,
Derivative Item
Statements of Operations Line
2024
2023
2024
2023
(in thousands)
(in thousands)
Commodity derivatives
Cash settlements paid on matured derivative contracts, net
Accrued liabilities and other balances were comprised of the following:
As of September 30, 2024
As of December 31, 2023
(in thousands)
Accrued accounts payable invoices
$
38,720
$
21,225
Gabon contractual obligations
8,081
15,794
State oil liability
22,145
—
Capital expenditures
8,551
10,136
Egypt modernization payments
9,742
9,933
Accrued wages and other compensation
6,725
3,746
Seismic data
2,455
—
Other
7,429
6,763
Total accrued liabilities and other
$
103,848
$
67,597
10.COMMITMENTS AND CONTINGENCIES
Abandonment funding
Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. At September 30, 2024, $10.7 million ($6.3 million, net to VAALCO) of the abandonment fund has been funded on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
Share Buyback Program
OnNovember 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provided for an aggregate purchase of currently outstanding common stock up to $30 million over a maximum period of 20 months. Payment for shares repurchased under the share buyback program were funded using the Company's cash on hand and cash flow from operations. The share buyback program was completed onMarch 12, 2024.Under the share buyback program, we purchased a total of 6,797,711 shares at an average price of $4.41 per share.
Merged Concession Agreement
The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). In accordance with the Merged Concession Agreement, the Company is required to make a $10.0 million annual modernization payment to EGPC each year through February 1, 2026.The $10.0 million modernization payment dueFebruary 1, 2024was offset against receivables owed to the Company from EGPC. On the unaudited condensed consolidated balance sheet as of September 30, 2024, $9.7 million of the remaining modernization payment liability was recorded in the line item “Accrued liabilities and other” and $9.0 million was recorded in “Other long-term liabilities.”
The Company also has minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing onFebruary 1, 2020for a total of $150 million over the 15-year license contract term. Through September 30, 2024, the Company's financial work commitments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.
As the Merged Concession Agreement was signed inJanuary 2022and became effective as ofFebruary 1, 2020 (the “Merged Concession Effective Date”), there was an effective date adjustment owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date. The Company recognized a receivable in connection with the Merged Concession Effective Date adjustment of $67.5 million as ofOctober 13, 2022, based on historical realized prices (the "Backdated Receivable"). Subsequent to the determination of the Merged Concession Effective Date adjustment, VAALCO and EGPC have agreed to offset outstanding payables owed to EGPC against the Backdated Receivable balance. In June 2024, EGPC confirmed the final settlement amount of $40.5 million owed to the Company. The remaining net receivable is recorded in the “Egypt receivables and other” line item in the unaudited condensed consolidated balance sheet as of September 30, 2024.
11.DEBT
As ofSeptember 30, 2024 andDecember 31, 2023, the Company had no outstanding debt.
RBL Facility
On May 16, 2022, the Company entered into an agreement with Glencore Energy UK Ltd. (“Glencore”), and other lenders, to provide a senior secured reserve-based revolving credit facility (the “RBL Facility”) for a maximum principal amount of up to $50.0 million. BeginningOctober 1, 2023and thereafter onApril 1andOctober 1of each year during the term of the RBL Facility, the $50 million initial commitment, will be reduced by $6.3 million. AtSeptember 30, 2024, the amount available to be drawn under the RBL Facility was $37.5 million.
The RBL Facility agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the RBL Facility agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million at any time. The amount the Company can borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the RBL Facility agreement. Regarding the requirements, the Company must deliver its annual financial statements to Glencore within 90 days of the end of each fiscal year. AtSeptember 30, 2024, the Company was in compliance with all debt covenants and had no outstanding borrowings under the RBL Facility.
VAALCO and its domestic subsidiaries file a consolidated U.S. federal income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions that include Canada, Egypt, Equatorial Guinea, Gabon and Cote d'Ivoire.
The foreign taxes payable are attributable to Gabon and Cote d'Ivoire as of September 30, 2024, and to Gabon as of September 30, 2023.
The Company’s effective tax rate for the three months ended September 30, 2024 and 2023, excluding the impact of discrete items, was 64.85% and 63.85%, respectively. The Company’s effective tax rate for the nine months ended September 30, 2024 and 2023, excluding the impact of discrete items, was 59.10% and 63.57%, respectively. For the three and nine months ended September 30, 2024 and 2023, the Company’s overall effective tax rate was primarily impacted by tax rates in foreign jurisdictions higher than the US statutory rate and by non-deductible items associated with operations. The overall effective tax rate for the three and nine months ended September 30, 2024 was additionally impacted by the cost oil settlement recorded in Gabon.
For the three months ended September 30, 2024, the income tax expense of $32.6 million includes a $1.8 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $34.4 million for the period. For the nine months ended September 30, 2024, the income tax expense of $64.1 million includes a $1.2 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $65.3 million for the period.
As of September 30, 2024, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.
The Company’s other comprehensive loss was $1.7 million for the three months ended September 30, 2024 and $1.9 million for the nine months ended September 30, 2024. The functional currency of our Canadian segment is the Canadian Dollar. All of the Company’s other comprehensive income arises from the currency translation of our Canadian segment to USD.
The components of accumulated other comprehensive income are as follows:
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and may also include forward-looking information within the meaning defined under applicable Canadian securities laws (collectively, "forward-looking statements"), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:
•the impact of world health events, including any related impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity, when and if needed, disruptions in global supply chains and disruptions to our workforce;
•the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries with respect to crude oil production levels;
•volatility of, and declines and weaknesses in crude oil, natural gas and natural gas liquids (“NGLs”) prices, as well as our ability to offset volatility in prices through the use of hedging transactions;
•the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves;
•impairments in the value of our crude oil, natural gas and NGLs assets;
•future capital requirements;
•our ability to maintain sufficient liquidity in order to fully implement our business plan;
•our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;
•the ability of the BWE Consortium to successfully execute its business plan;
•our ability to attract capital or obtain debt financing arrangements;
•our ability to pay the expenditures required in order to develop certain of our properties;
•operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs;
•difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs;
•the impact of competition;
•our ability to identify and complete complementary opportunistic acquisitions;
•our ability to effectively integrate assets and properties that we acquire into our operations;
•weather conditions;
•the uncertainty of estimates of crude oil, natural gas and NGLs reserves;
•currency exchange rates and regulations;
•unanticipated issues and liabilities arising from non-compliance with environmental regulations;
•our limited control over the assets we do not operate;
•our ability to extend the Block CI-40 Petroleum Production Sharing Contract in Cote d'Ivoire;
•the impact and duration of scheduled maintenance of the floating, production, storage and offloading vessel in Cote d'Ivoire;
•the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon that was conducted by the government of Gabon;
•the timing of the payment(s) from the Egyptian General Petroleum Corporation ("EGPC") to us for the difference in the historic commercial terms and the revised commercial terms applied against the production since February 1, 2020 (the “Merged Concession Effective Date”);
•the availability and cost of seismic, drilling and other equipment;
•difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets;
•timing and amount of future production of crude oil, natural gas and NGLs;
•hedging decisions, including whether or not to enter into derivative financial instruments;
•general economic conditions, including any future economic downturn, the impact of inflation, and disruption in financial credit and other disruptions resulting from geo-political events such as the Russian invasion of Ukraine, the conflict in the Middle East, and trade tensions between the U.S. and China;
•our ability to enter into new customer contracts;
•changes in customer demand and producers’ supply;
•actions by the governments and other significant actors with respect to events occurring in the countries in which we operate;
•actions by our joint venture owners;
•compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;
•the outcome of any governmental audit; and
•actions of operators of our crude oil, natural gas and NGLs properties.
The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Form 10-K”) and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2024 (the “Q1 2024 Form 10-Q”) and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2024 (the “Q2 2024 Form 10-Q”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report, the Q1 2024 Form 10-Q, the Q2 2024 Form 10-Q and the 2023 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.
Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this “Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.
INTRODUCTION
VAALCO is a Houston, Texas-based, African-focused independent energy company with strong production and reserve portfolio of assets in Gabon, Egypt, Equatorial Guinea, Canada, Nigeria and Cote d'Ivoire, currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.
On August 6, 2024, VAALCO issued a press release announcing its quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2024 ($0.25 annualized), which was paid on September 20, 2024 to stockholders of record at the close of business on August 23, 2024. On November 11, 2024, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on December 20, 2024 to stockholders of record at the close of business on November 22, 2024.
Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Recent Operational Updates
Gabon
VAALCO completed its last drilling campaign in the fourth quarter of 2022. We are currently evaluating locations and planning for the next drilling campaign at Etame that is expected to occur early in 2025. In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) and related field reconfiguration processes. This project provides a lower cost FSO solution that increases the storage capacity for the Etame block and improves operational performance. The Company continues to focus on operational excellence, production uptime and enhancement in 2024 to minimize decline until the next drilling campaign.
Preventative maintenance activities on facilities and facility equipment remained at scheduled levels. Planned maintenance shutdown activities and piping external corrosion repairs were carried out on Avouma platform. Equipment reliability and availability remain at high levels.
Egypt
We have deferred 2024 drilling to work up a robust drilling program which is expected to commenced in late November 2024. We currently have a workover rig in place which has allowed us to slow decline during 2024.
We completed the K-81 recompletion at the start of the first quarter which was a carry-over from our 2023 drilling activity. The EA-55 well, drilled in October 2023, was completed and put online in January 2024. The planned workover program for 2024 was completed for 12 wells as shown in the table below. Both wells H-22 and K-65 ST1 had sanding issues and may need sand screens fitted to achieve peak production; whereas K-85 and K-80 have come on with very strong production. Well K-84 was initially tested on Asl-G, however no notable enhancement was observed. Hence the layer was temporarily isolated for further study and the well was recompleted to Asl-D to achieve peak production from the well. The well was recently recompleted and showed significant improvement in the rate.
Water shutoff was successful in well K-74, which improved production results. In July 2024, well K-72A was successfully recompleted, transitioning production from Asl-B formation to Asl-A2 formation. Following the recompletion, the well demonstrated an average IP-30 oil production rate of 150 (bopd) contributing to improved field performance.
The testing of the Asl-D zone in well K-65ST was postponed, and the well was recompleted on the Asl-B zone to enhance production efficiency. Following the recompletion, well K-65ST demonstrated an average IP-30 oil production rate of 100 (bopd) highlighting its production potential.
A summary of the Egyptian workover campaign's impact in the quarter ended September 30, 2024 is presented below:
VAALCO Egypt 2024 Workover Wells
Well
Workover Date
Type
Completion Zone
Perforation Interval (ft)
IP-30 Rate (BOPD)(a)
K-81
1-Jan-24
Recompletion
Asl-D
13.1
154
EA-55
10-Jan-24
Frac & Complete
Redbed
Hydraulic Frac
143
H-22
7-Feb-24
Recompletion
Yusr-A
9.8
82
K-65_ST1
14-Feb-24
Recompletion
Asl-D
13.1
43*
K-85
16-Mar-24
Recompletion
Asl-D
13.1
420
K-84
27-Mar-24
Recompletion
Asl-G
16.4
58*
K-74
3-Apr-24
Water Shut-off Recompletion
Asl-A
8.2
108
K-77
7-Apr-24
Recompletion
Asl-A
26.2
100
K-84
13-Jun-24
Recompletion
Asl-D
19.7
430
K-80
19-Jun-24
Recompletion
Asl-D
13.1
188
K-72A
24-Jul-24
Recompletion
Asl-A
9.8
150
HE-04
27-Jul-24
ALS Change to SRP
Asl-B2
0.0
170
K-65ST1
31-Aug-24
Recompletion
Asl-B
6.6
100
a) Initial Production; 30 day duration
*Production – impacted by sand production.Possible workover with sand screen required.
Canada
The 2024 drilling campaign commenced in January 2024 and our four planned wells in the north of the license have since been drilled. Completion of the wells was initiated in late March 2024, and were completed in April 2024. The wells were equipped and tied-in in April 2024 and early May 2024 followed by well start-up. As of September 30, 2024, all four wells were producing. A summary of the 2024 drilling campaign in Canada is presented below:
VAALCO Canada 2024 Wells
Well
Spud Date
Net Pay (ft)
Penetrated Pay Zones
Completion Zone
Perforation Interval (ft)
Drilling Depth (ft)
IP-30 Rate (BOEPD)
09-12-30-4W5
1/17/2024
2.75-Mile Hz (4,400m, 14,430ft)
Upper Bioturbated Cardium
Cardium
115 Stg x 15T Hydraulic Fracture Treatment
22,732
479
10-12-30-4W5
2/22/2024
2.75-Mile Hz (4,400m, 14,430ft)
Upper Bioturbated Cardium
Cardium
100 Stg x 15T Hydraulic Fracture Treatment
21,736
469
11-12-30-4W5
2/23/2024
2.75-Mile Hz (4,400m, 14,430ft)
Upper Bioturbated Cardium
Cardium
108 Stg x 15T Hydraulic Fracture Treatment
21,624
444
1-18-30-3W5
9/3/2024
2.75-Mile Hz (4,400m, 14,430ft)
Upper Bioturbated Cardium
Cardium
106 Stg x 15T Hydraulic Fracture Treatment
20,669
182
Cote d'Ivoire
During the three months ended September 30, 2024, three shared liftings took place in Cote d'Ivoire. In July 2024, 612,773 gross barrels were lifted or 197,474 net barrels to VAALCO. In August 2024, 681,584 gross barrels were lifted in Cote d'Ivoire or 219,630 net barrels to VAALCO. And in September, 667,880 gross barrels were lifted or 215,211 net barrels to VAALCO.
As VAALCO has a non-operated position, the operator continues to work with Modec International, Inc. (“Modec”), the operator of the floating production storage and offloading vessel (the “FPSO”), on the FPSO dry dock project (off station 2025) throughout the third quarter of 2024. Negotiations with key vendors have matured for the critical path activities for the dry dock project which remains on target for 2025.This includes selection of the disconnect and reconnect contractor, and support for the revised yard bid from Dubai dry docks among other activities.
ACTIVITIES BY ASSET
Gabon
We operate the Etame Marin Block on behalf of a consortium of companies. As of September 30, 2024, production operations in the Etame Marin block included fifteen platform wells, plus two subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery and processing at the Etame platform. From the Etame platform, the crude oil is pumped through a riser system to the FSO where it is stored and ultimately offloaded. The leased FSO is anchored to the seabed on the block. During the three months ended September 30, 2024 and 2023, production from the block was 1,377 million barrels ("MBbls") (696 MBbls, net) and 1,506 MBbls (761 MBbls, net), respectively, as discussed below in "Results of Operations". During the nine months ended September 30, 2024 and 2023, production from our Etame assets was 4,138 MBbls (2,108 MBbls, net) and 4,740 MBbls (2,425 MBbls, net), respectively.
Egypt
In Egypt, our interests are spread across two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions, and the Western Desert, which contains the South Ghazalat concession. Both of our Egyptian blocks are production sharing contracts (“PSC”) among the Egyptian General Petroleum Corporation (“EGPC”), the Egyptian government and us. We have an equal ownership interest, with EGPC owning the other portion, in the joint venture that has a 100% working interest in both PSCs. During the three months ended September 30, 2024 and 2023, production from the Eastern Desert was 965 MBbls (657 MBbls, net) and 1,076 MBbls (732 MBbls, net), respectively, as discussed below in “Results of Operations”. The third quarter 2024 saw a slight increase in the production from the Eastern Desert compared to the second quarter 2024 which had production of 953 MBbls (643 MBbls, net). During the nine months ended September 30, 2024 and 2023, production from our Eastern Desert assets was 2,867 MBbls (1,941 MBbls, net) and 3,032 MBbls (2,074 MBbls, net), respectively.
Canada
In Harmattan, Canada, we own production and working interests in the Cardium light oil and Mannville liquids-rich gas assets. This property produces oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 2,000 to 2,600 meters. All gas is delivered to a third party non-operated gas plant for processing. During the three months ended September 30, 2024 and 2023, production from our Canadian assets was 269 MBoe (229 MBoe, net) and 261 MBoe (210 MBoe, net), respectively, as discussed below in “Results of Operations”. During the nine months ended September 30, 2024 and 2023, production from our Canadian assets was 761 MBoe (658 MBoe, net) and 775 MBoe (672 MBoe, net), respectively.
Equatorial Guinea
As of September 30, 2024, we have $10.0 million of undeveloped leasehold costs associated with the Block P license. In February of 2023, we acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.8 million at first commercial production of the Block. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus development plan (the “Venus POD”), the Venus Development was initiated.
In March 2024, all partners signed the final documents, and the Government of Equatorial Guinea has approved the Joint Operating Agreement (“JOA”) related to the previously approved Venus-Block P plan of development.
The 2024 amended budget was approved by all partners on May 10, 2024, and then approval was requested from the Ministry of Mines and Hydrocarbons. At the end of the 30-day waiting period, the budget was deemed to be approved, and the corresponding Authorization for Expenditures was sent to all partners. It was unanimously approved on June 18, 2024, and the implementation of the FEED phase was initiated. The project is on schedule and focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review. The ultimate objective is to obtain an FID determination by the end of the first quarter of 2025.
The Block P PSC provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development. The PSC also includes the portions of Block P not associated with the Block P - Venus development.
Cote d'Ivoire
CI-40 Baobab field was discovered in 2001 and is located in the western half of the CI-40 license, 30km offshore Côte d’Ivoire. VAALCO holds a 27.4% non-operated working interest (30.4% paying interest) in CI-40. The license is operated by Canadian Natural Resources.
The field has been developed with 24 subsea production wells and 5 water injector wells tied back to a leased FPSO operated by Modec. Third quarter production was stable with three water injectors and nine production wells online. Gross production for the third quarter 2024 was 1,489 MBoe (415 MBoe, net).
The FPSO is planned to go to dry dock in 2025 to undergo maintenance and is expected to return to service in 2026.
The PSC license has an initial term until April 11, 2028 with a ten-year extension option until April 2038.
CAPITAL RESOURCESAND LIQUIDITY
Cash Flows
Our cash flows for the nine months ended September 30, 2024 and 2023 are as follows:
Nine Months Ended September 30,
Increase
2024
2023
(Decrease) in 2024 over 2023
(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities
$
134,521
$
117,343
$
17,178
Net change in operating assets and liabilities
(65,336)
54,468
(119,804)
Net cash provided by (used in) operating activities
69,185
171,811
(102,626)
Net cash provided by (used in) investing activities
(61,118)
(77,365)
16,247
Net cash provided by (used in) in financing activities
(32,264)
(42,382)
10,118
Effects of exchange rate changes on cash
(4)
(321)
317
Net change in cash, cash equivalents and restricted cash
$
(24,201)
$
51,743
$
(75,944)
The $102.6 million decrease in net cash provided by operating activities during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, was driven primarily by changes in operating assets and liabilities during the period. The net decrease in changes provided by operating assets and liabilities of $119.8 million for the nine months ended September 30, 2024 compared to the same period of 2023 was related to a decrease in cash provided by trade receivable and receivables accounts with joint venture owners (collectively $88.6 million). In addition, cash used by operating assets and liabilities increased due to decreases in the foreign income taxes payable balance that was reduced with proceeds generated from the lifting of crude oil for the Gabon Oil Company as well as a decrease in the accrued liabilities other balances (collectively $43.1 million). Partially offsetting these changes were increases in cash provided by changes in crude oil inventory of $18.1 million.
The $16.2 million decrease in net cash used in investing activities during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, was due to capital spending costs associated with the development drilling programs in Egypt and Canada not exceeding prior year expenditures along with reduced current year expenditures for Gabon. In addition, VAALCO used $40.2 million in cash for the Svenska Acquisition which is offset by the cash received from Svenska in the amount of $40.6 million. See Note 3 to the unaudited condensed consolidated
financial statements for further discussion of the acquisition. For the nine months ended September 30, 2023, cash used in investing activities was due to the Etame field reconfiguration and other items to support the 2021/2022 drilling campaign.
Net cash used in financing activities during the nine months ended September 30, 2024 included $19.6 million for dividend distributions, $6.8 million for treasury stock repurchases made under our stock repurchase plan and as a result of tax withholding on options exercised and on vested restricted stock, and $6.3 million of principal payments on our finance leases partially offset by $0.4 million in proceeds from options exercised. For the nine months ended September 30, 2023, cash used in financing activities included $20.2 million for dividend distributions, $17.5 million for treasury stock repurchased under our stock repurchase plan, and $5.2 million of principal payments on our finance leases partially offset by $0.6 million in proceeds from options exercised.
Capital Expenditures
For the nine months ended September 30, 2024, we had accrual basis capital expenditures of $73.1 million compared to $63.3 million accrual basis capital expenditures for the same period in 2023. For the nine months ended September 30, 2024, our cash spending primarily related to the new wells drilled as part of the drilling campaign in Canada as well as expenditures associated with the preparation of the FPSO dry dock project in Cote d'Ivoire. During the same period in 2023, our cash spending primarily related to the payments for the 2023 drilling campaigns in both Egypt and Canada.
See discussion below in “Capital Resources, Liquidity and Cash Requirements” for further information.
Regulatory and Joint Interest Audits
We are subject to periodic routine audits by various government agencies, including audits of our petroleum cost account (the “Cost Account”), customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.
Commodity Price Hedging
The price we receive for our crude oil significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Crude oil and natural gas commodities and therefore their prices, can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future.
Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps, costless collars and put options to hedge price risk associated with a portion of our anticipated crude oil and gas production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil and gas prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. The counterparty to our derivative swap transactions was a major oil company’s trading subsidiary, and our costless collars are with Glencore. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the unaudited condensed consolidated statements of operations and other comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheets.
Cash on Hand
At September 30, 2024, we had unrestricted cash of $89.1 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.
We currently sell our crude oil production from Gabon under a crude oil sales and marketing agreement ("COSMA") with Glencore. Under the COSMA, all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the final maturity date of the RBL Facility, expected to be May 15, 2027, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. Sales with Glencore are normally settled 30 days from the delivery date.
Revenues associated with the sales of our crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. For reporting purposes, we record the EGPC’s share of production as royalties which are netted against revenue. With respect to taxes in Egypt, our income taxes under the terms of the Merged Concession Agreement are the liability of TransGlobe Petroleum International ("TGPI"), a wholly-owned indirect subsidiary of VAALCO. TGPI's income taxes are paid by EGPC on behalf of TGPI out of EGPC’s production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of TGPI are recognized as oil and gas sales revenue and income tax expense for reporting purposes. Terms of settlement for sales to EGPC are within 30 days from the delivery date.
Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are recognized net of royalties and transportation costs. Settlement of accounts receivable in Canada occur on the 25th of the following month after production.
Revenues associated with the sales of our crude oil in Cote d’Ivoire are recognized by reference to actual volumes sold and prices in active markets that are quoted against world crude benchmarks, e.g. Brent and adjusted according to specific terms and conditions as applicable per the sales contracts. The payment terms include settlement of accounts receivable in Cote d’Ivoire is typically 30 days after bill of lading, commercial invoice and original certificates of quantity, quality and origin are received and accepted by the customer.
Capital Resources, Liquidity and Cash Requirements
Our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in each of our operating segments and earlier in the year 2024, the Svenska Acquisition. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations as well as the ability to extend our RBL Facility to support our current cash requirements during the next 12 months and beyond, including the FSO charter in Gabon and drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends or other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable or acceptable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.
Merged Concession Agreement
For information on the Merged Concession Agreement, see Note 10 to the unaudited condensed consolidated financial statements.
RBL Facility Agreement and Available Credit
For information on our RBL Facility agreement and available credit, see Note 11 to the unaudited condensed consolidated financial statements.
Cash Requirements
Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects, dividend payments, the Merged Concession Agreement, future lease payments and abandonment funding, each of which is discussed in further detail below.
Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the extension of the
Etame PSC, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. At September 30, 2024, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
Leases - We are a party to several operating and financing lease arrangements, including operating leases for the corporate office, a drilling rig, rental of marine vessels and a helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, generators and turbines used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The annual costs of these leases are significant to us.
Merged Concession Agreement - On January 20, 2022, the Merged Concession Agreement was executed with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. As part of the agreement, the Company is required to make an annual modernization payment of $10.0 million per year to EGPC through February 2026. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024 payments and issue two $10.0 million credits against receivables owed from EGPC. We will make two further annual modernization payments of $10.0 million on February 1, 2025 and February 1, 2026. For information on the Merged Concession Agreement, see Note 10 to the unaudited condensed consolidated financial statements.
Financial Work Commitments - We also have financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 for a total of $150 million over the 15 year license contract term. Through September 30, 2024, our financial work commitments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.
BWE Consortium – On October 11, 2021, we announced our entry into a consortium with BW Energy and Panoro Energy (the “BWE Consortium”) and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. Negotiations to finalize the commercial terms were held in 2023. In early February 2024, the BWE Consortium and the government came to an agreement on the fiscal terms on February 9, 2024. The other parties to the BWE Consortium signed the PSC on October 30, 2024, while VAALCO is expected to sign the PSC pending the determination of an agreed upon signing date with the Gabonese Government. Pursuant to the terms of the PSC, BW Energy will be the operator with a 37.5% working interest, and VAALCO will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, Niosi Marin Block (previously G12-13) and the Guduma Marin Block (previously H12-13), are adjacent to our Etame PSC, as well as BW Energy and Panoro Energy’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.
Trends and Uncertainties
Geopolitical Conflict and Other Market Forces – The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The ongoing conflict has caused, and could continue to intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.
For example, shortly after the outbreak of the conflict through the year ended December 31, 2023 and on-going into 2024, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities has lengthened, leading to delays and, in most cases, prices for materials have increased. Management believes the ongoing war between Russia and Ukraine, the Houthis attacks on maritime vessels in the Red Sea region, conflicts in the Middle East and the related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy, as well as destabilizing impacts on the global oil and natural gas market. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.
Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC.
ESG and Climate Change Effects – Sustainability matters continue to attract considerable public, political, regulatory and scientific attention. In particular, we expect continued required reporting attention on climate change issues and emissions of greenhouse gases (“GHG”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use. This increased attention to climate change and environmental stewardship coupled with increasing government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against the oil and gas industry, including VAALCO. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, voluntary efforts to reduce routine flaring, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on environmental, social and governance “ESG” matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental stewardship by monitoring our adherence to ESG reporting requirements, including establishing and communicating short and long-term goals and targets, furthering the reduction of our carbon footprint and measurement of GHG emissions. Sustainability remains an important topic to us, and we are in the process of developing a multi-year plan to establish targets to reduce emissions and document our progress in achieving goals we set for ourselves. Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.
Climate-Related Disclosures – On March 6, 2024, the SEC adopted a new set of rules that require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant’s business, results of operations, or financial condition, Scope 1 and Scope 2 greenhouse gas emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the SEC’s new climate rules, which have been consolidated and will be heard in the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC issued an order staying the final rules until judicial review is complete.
For the past three years, the Company has refined its reporting in line with the recommendations of the Task force on Climate-related Financial Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting. The full TCFD report was included within the Company's 2023 Sustainability Report (rather than in the Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the Sustainability Report details environmental, social and governance matters which the TCFD report forms an important part of The 2023 Sustainability Report is available on the Company's website.
The Company considers itself aligned with both the TCFD's Governance and Strategy pillars and the recommendations therein. It does not consider itself aligned with Risk Management nor Metrics and Targets but has made meaningful progress against certain of the underlying recommendations and provides statements of intent to address these recommendations during 2024, including communicating its short-, mid- and long-range goals for emission reductions, beginning with its operated assets.
VAALCO also is participating in the Carbon Disclosure Project (“CDP”) voluntary reporting for its 2023 performance. This is the first year VAALCO has submitted to CDP and the Company intends to continue to do so in the future.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
There have been no material changes to our critical accounting policies and estimates subsequent to December 31, 2023. For a discussion of the Company's critical accounting policies for the fiscal year-ended December 31, 2023, please see our 2023 Form 10-K.
NEW ACCOUNTING STANDARDS
See Note 2 to the unaudited condensed consolidated financial statements.
Three Months Ended September 30, 2024 Compared to the Three Months Ended September 30, 2023
Net income for the three months ended September 30, 2024 was $11.0 million compared to net income of $6.1 million during the same period of 2023. See the discussion below for changes in revenue and expense.
Crude oil, natural gas and NGLs revenues increased $24.1 million, or approximately 21%, to $140.3 million during the three months ended September 30, 2024 from $116.3 million during the same period in 2023. The revenue increase is attributable to higher volumes sold in Gabon, Egypt and Canada segments partially offset by lower realized sales prices compared to the prior period. In addition, revenue was recognized within the Cote d'Ivoire segment during the three months ended September 30, 2024, that were not present in the prior period.
Three Months Ended September 30,
Increase/(Decrease)
2024
2023
(in thousands except per Boe information)
Net crude oil, natural gas and NGLs sales volume (MBoe)
2,134
1,812
322
Average crude oil, natural gas, and NGLs sales price (per Boe)
$
65.41
$
63.41
$
2.00
Net crude oil, natural gas, and NGLs revenue
$
140,334
$
116,269
$
24,065
Operating costs and expenses:
Production expense
42,324
39,956
2,368
Exploration expense
—
1,194
(1,194)
Depreciation, depletion and amortization
47,031
32,538
14,493
General and administrative expense
6,929
6,216
713
Credit losses and other
69
822
(753)
Total operating costs and expenses
96,353
80,726
15,627
Other operating expense, net
102
5
97
Operating income
$
44,083
$
35,548
$
8,535
The revenue changes in the three months ended September 30, 2024 compared to the same period in 2023 identified as related to changes in price or volume, are shown in the table below:
(in thousands)
Price(1)
$
4,268
Volume
20,418
Other
(621)
$
24,065
(1)The price in the table above excludes revenues attributed to carried interests.
The table below shows net production, sales volumes and realized prices for both periods.
Three Months Ended September 30,
2024
2023
Net crude oil, natural gas and NGLs production (MBoe)
2,004
1,734
Net crude oil, natural gas, and NGL sales (MBoe)
2,134
1,812
Average realized crude oil, natural gas and NGLs price ($/Boe)
$
65.41
$
63.41
Average Dated Brent spot price* ($/Bbl)
$
80.01
$
86.65
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $47.6 million of revenue to the Company’s total revenue during the three months ended September 30, 2024. This compares to the $57.3 million of revenue contributed by the Gabon segment during the three months ended September 30, 2023. The total sales volume in Gabon for the three months ended September 30, 2024 was 617 MBbls or 48 MBbls lower than the sales volumes of 665 MBbls in the same period in 2023. Further, we had a decrease in the Gabon average realized price per barrel received during the three months ended September 30, 2024 of $77.16 per barrel (Bbl) compared to the price received in 2023 of $86.19 per Bbl. Our share of crude oil inventory, excluding royalty barrels, was approximately 217,124 barrels and 333,396 barrels at September 30, 2024 and 2023, respectively.
Egypt
Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the three months ended September 30, 2024, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $34.5 million of revenue to the Company’s total revenue for the three months ended September 30, 2024. This compares to the $50.3 million of revenue contributed by the Egypt segment during the three months ended September 30, 2023. At September 30, 2024, the Company’s Egypt segment had no barrels in oil inventory. The decrease in sales was primarily due to the decrease in sales volumes during three months ended September 30, 2024 to 657 MBbls compared 938 MBbls during the same period in the prior year. The average realized price received in Egypt was $52.58 per Bbl during the three months ended September 30, 2024, which was also lower compared to the $53.61 per Bbl received in the third quarter of 2023.
Canada
Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $8.4 million of revenue to the Company’s total revenue for the three months ended September 30, 2024. This compares to the $8.7 million of revenue contributed by the Canadian segment during the three months ended September 30, 2023. The decrease in revenues is due to the lower average realized sales price received during the three months ended September 30, 2024 of $36.95 per MBoe or a decrease of $4.61 per Boe from the $41.56 per Boe received during the same period in 2023. The decrease in the average realized price was offset by the increase in sales volumes during the same period. In Canada, the total sales volumes for the three months ended September 30, 2024 was 227 MBoe or 18 MBoe higher than the 209 MBoe sold during the three months ended September 30, 2023.
Cote d'Ivoire
Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. The Company's Cote d’Ivoire segment contributed $49.8 million of revenue to the Company’s total revenue for the three months ended September 30, 2024. Total sales volumes in Cote d'Ivoire for the third quarter of 2024 was 632 MBbls and the average realized sales price received was $78.75 per Bbl.
Production expenses increased $2.3million, or approximately 6%, for the three months ended September 30, 2024 to $42.3 million from $40.0 million for the same period in 2023. The increase in production expense was primarily driven by the crude oil inventory acquired in the Svenska Acquisition that was recorded at fair value upon acquisition and lower of cost or net realizable value in subsequent periods. In addition, VAALCO has seen inflationary pressure on personnel and contractor costs. In February 2024, the government in Gabon enacted new regulation which has resulted in an increase to withholding taxes on foreign supplied goods and services. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended September 30, 2024 decreased to $19.80 per barrel for the prior year from $22.04 per Bbl primarily as a result of higher production volumes for the current period.
Depreciation, depletion and amortization costs increased $14.5 million, or approximately 45%, for the three months ended September 30, 2024 to $47.0 million from $32.5 million during the same period in 2023. The increase in depreciation, depletion and amortization expense is due primarily to the addition of Cote d'Ivoire related to the Svenska Acquisition partially offset by lower depletable costs in Gabon, Egypt, and Canada.
General and administrative expenses increased $0.7 million, or 11% for the three months ended September 30, 2024 to $6.9 million from $6.2 million for the same period in 2023. The increase in general and administrative expenses is primarily attributable to increases in professional service fees, salaries and wages, and accounting and legal fees.
Other operating expense, net for each of the three months ended September 30, 2024 and 2023 was not material to our results.
Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Note 8 to the unaudited condensed consolidated financial statements. Derivative gain increased by $2.5 million to a gain of $0.2 million for the three months ended September 30, 2024 from a loss of $2.3 million during the same period in 2023. Derivative gain for the three months ended September 30, 2024 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the three months ended September 30, 2024. Our derivative instruments gain (loss), net currently cover a portion of our production through March 2025.
Interest expense, net was $0.6 million for the three months ended September 30, 2024 compared to an expense of $1.4 million during the same period in 2023. The decrease of net interest expense for the three months ended September 30, 2024, primarily results from a decrease in our amortization of debt issue costs and commitment fees incurred on the RBL Facility partially offset by interest income.
Income tax expense (benefit) for the three months ended September 30, 2024 was an expense of $32.6 million. This is comprised of current tax expense of $33.7 million including a $1.8 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, current income taxes were $35.5 million for the period. Income tax expense (benefit) for the three months ended September 30, 2023 was an expense of $25.8 million, which was comprised of current tax expense of $26.8 million and $1.0 million of deferred tax benefit.
Nine Months Ended September 30, 2024 Compared to the Nine Months Ended September 30, 2023
Net income for the nine months ended September 30, 2024 was $46.8 million compared to net income of $16.4 million during the same period of 2023. See discussion below for changes in revenue and expense.
Crude oil, natural gas and NGLs revenues increased $51.4 million, or approximately 17%, to $357.3 million during the nine months ended September 30, 2024 from $305.9 million during the same period in 2023. The revenue increase is attributable to revenues recognized within the Cote d'Ivoire segment during the nine months ended September 30, 2024 that were not present in the prior period.
Nine Months Ended September 30,
Increase/(Decrease)
2024
2023
(in thousands except per Boe information)
Net crude oil, natural gas, and NGLs sales volume (MBoe)
5,388
4,839
549
Average crude oil, natural gas and NGLs sales price (per Boe)
The revenue changes in the nine months ended September 30, 2024 compared to the same period in 2023 identified as related to changes in price or volume, are shown in the table below:
(in thousands)
Price(1)
$
18,912
Volume
34,302
Other
(1,859)
$
51,355
(1)The price in the table above excludes revenues attributed to carried interests.
The table below shows net production, sales volumes and realized prices for both periods.
Nine Months Ended September 30,
2024
2023
Net crude oil, natural gas and NGLs production (MBoe)
5,410
5,172
Net crude oil, natural gas and NGLs sales (MBoe)
5,388
4,839
Average realized crude oil, natural gas and NGLs price ($/Boe)
$
65.99
$
62.48
Average Dated Brent spot price* ($/Bbl)
$
82.50
$
81.99
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Crude oil, natural gas and NGL revenues:
Gabon
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $158.8 million of revenue to the Company’s total revenue during the nine months ended September 30, 2024. This compares to the $171.9 million of revenue contributed by the Gabon segment during the nine months ended September 30, 2023. The decrease in revenues is primarily due to lower sales volume in Gabon, which decreased to 1,947 MBbls for the nine months ended September 30, 2024 from the 2,092 MBbls sales volumes reported in the same period in 2023. The average realized sales price received in Gabon was $81.55 per Bbl for nine months ended September 30, 2024, which was also lower compared to the $82.18 per Bbl average realized sales price received during the first nine months of 2023. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 217,124 barrels and 333,396 barrels at September 30, 2024 and 2023, respectively.
Egypt
Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the nine months ended September 30, 2024, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $107.0 million of revenue to the Company’s total revenue for the nine months ended September 30, 2024. This compares to the $106.4 million of revenue contributed by the Egypt segment during the nine months ended September 30, 2023. The lower revenues in Egypt for the first nine months of 2024 was primarily due to the decrease in sales volume of 133 MBbls to 1,941 MBbls during the period from 2,074 MBbls during the same period in 2023. The decrease in sales was offset by the increase in average realized sales price from $51.30 per Bbl during the nine months ended September 30, 2023 to $55.12 per Bbl during the same period in 2024.
Canada
Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $24.5 million of revenue to the Company’s total revenue for the nine months ended September 30, 2024. This compares to the $27.6 million of revenue contributed by the Canadian segment during the nine months ended September 30, 2023. The decrease in revenues was due to the 17 MBls decrease in sales volumes from 673 MBoe during the nine months ended September 30, 2023 to 656 MBoe in the same period in 2024. In addition, the average realized sales price
also decreased from $40.98 per Boe during the nine months ended September 30, 2024 to $37.29 per Boe during the nine months ended September 30, 2023.
Cote d'Ivoire
Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. The Company's Cote d’Ivoire segment contributed $67.0 million of revenue to the Company’s total revenue during the nine months ended September 30, 2024. Total sales volumes in Cote d'Ivoire for the nine months ended September 30, 2024 was 844 MBbls and the average realized sales price received was $79.43 per Bbl.
Production expenses increased $20.1 million, or approximately 19%, for the nine months ended September 30, 2024 to $126.9 million from $106.8 million for the same period in the prior year. In February 2024, the Government in Gabon enacted new regulation which has resulted in an increase to withholding taxes on foreign supplied goods and services. In addition, VAALCO has seen inflationary pressure on personnel and contractor costs. Also, production expenses have increased due to the addition of Cote d'Ivoire expenses not included in the prior year period. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the nine months ended September 30, 2024 increased to $23.51 per barrel from $22.32 per barrel for the nine months ended September 30, 2023 primarily as a result of production volumes for the current period.
FPSO demobilization expense for the nine months ended September 30, 2024 and 2023 was $0.0 and $5.6 million, respectively. In the first nine months of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in decommissioning fees, which was reported as a separate line item on the income statement.
Depreciation, depletion and amortization costs increased $11.0 million, or approximately 12%, for the nine months ended September 30, 2024 to $106.0 million from $95.0 million during the same period in 2023. The increase in depreciation, depletion and amortization expense is primarily due to the addition of Cote d'Ivoire expense related to the Svenska Acquisition partially offset by lower depletable costs in Gabon, Egypt.
General and administrative expenses increased $4.4 million, or 26%, for the nine months ended September 30, 2024 to $21.2 million from $16.8 million during the same period in 2023. The increase in general and administrative expenses is primarily professional service fees, salaries and wages, and accounting and legal fees.
Credit losses and other increased by $2.8 million to $5.2 million for the nine months ended September 30, 2024 from $2.4 million for the nine months ended September 30, 2023. The increase in credit losses and other for the nine months ended September 30, 2024, is primarily attributable to the receivables with EGPC regarding the settlement of these receivables owed to the Company.
Other operating expense, net for each of the nine months ended September 30, 2024 and 2023 was not material to our results.
Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Note 8 to the Financial Statements. Derivative loss decreased by $1.9 million to a loss of $0.4 million for the nine months ended September 30, 2024 from a loss of $2.3 million during the same period in 2023. Derivative losses for the nine months ended September 30, 2024 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the nine months ended September 30, 2024. Our derivative instruments currently cover a portion of our production through March 2025.
Interest expense, net was $2.6 million for the nine months ended September 30, 2024 compared to an expense of $5.4 million during the same period in 2023. The decrease of net interest expense for the nine months ended September 30, 2024 primarily results from a decrease in our amortization of debt issue costs and commitment fees incurred on the RBL Facility partially offset by interest income.
Other (expense) income, net increased by $4.0 million to an expense of $3.9 million for the nine months ended September 30, 2024 from a $0.1 million expense during the same period in 2023. Other (expense) income, net, normally consists of foreign currency gains and losses. However, during the nine months ended September 30, 2024, there was a $3.4 million expense related to transactions costs associated with the Svenska Acquisition.
Income tax expense (benefit) for the nine months ended September 30, 2024 was an expense of $64.1 million. This is comprised of current tax expense of $72.7 million including a $1.2 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, current income taxes were $73.9 million for the period. Income tax expense for the nine months ended September 30, 2023 was an expense of $52.2 million. This is comprised of current tax expense of $51.5 million and $0.7 million of deferred tax expense.
ITEM3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.
FOREIGN EXCHANGE 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 September 30, 2024, we had net monetary assets of $35.0 million (XAF 20.6 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 three and nine months ended September 30, 2024, we had expenditures of approximately $14.2 million and $50.3 million (net to VAALCO), 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% decrease in the value of the Canadian dollar against the US dollar would decrease the value of the net liabilities for the nine months ended September 30, 2024 by approximately $0.4 million. Conversely, a 10% increase in the value of the Canadian dollar against the US dollar would increase the value of the net liabilities for the nine months ended September 30, 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 September 30, 2024, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase the cash value for the nine months ended September 30, 2024 by $80 thousand. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the nine months ended September 30, 2024 by $65 thousand.
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 nine months ended September 30, 2024 by approximately $3.5 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 nine months ended September 30, 2024 by approximately $4.3 million.
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.
COUNTERPARTY RISK
We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparties. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
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 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.
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 three months ended September 30, 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 three months ended September 30, 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 quarterly sales volumes of 2,134 MBoe, a $5 per Bbl decrease in crude oil price would be expected to cause a $10.7 million decrease per quarter in revenues and operating income (loss) and a $7.5 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 617 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.1 million decrease per quarter in revenues and operating income (loss) and a $2.8 million decrease per quarter 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. 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. 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 cost recovery is shared with the government ("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-sharing 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 which 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 228 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $1.1 million decrease per quarter in revenues and operating income (loss) and a $1.1 million decrease per quarter in net income (loss).
With respect to our crude oil sales in Cote d'Ivoire, the prices received are based on Dated Brent prices plus or minus a differential. If Cote d'Ivoire sales were to remain constant at the most recent yearly sales volumes of 632 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.2 million decrease per quarter in revenues and operating income (loss) and a $1.7 million decrease per quarter in net income (loss).
As of September 30, 2024, we had unexpired derivative instruments outstanding covering approximately 710 MBbls of production through March of 2025. See Note 8 to the unaudited condensed consolidated financial statements for more information on our derivative contracts.
Subsequent to September 30, 2024, the Company entered into the following additional derivative contracts to cover its future anticipated production:
Weighted Average Hedge Price ($/Bbl)
Settlement Period
Type of Contract
Index
Average Volumes Hedged (Bbl)
Floor
Ceiling
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
INTEREST RATE RISK
Changes in market interest rates affect the amount of interest owed on outstanding balances under our RBL Facility. However, as of September 30, 2024, we had no amounts drawn under the RBL Facility. The commitment fees on the undrawn availability under the RBL Facility are not subject to changes in interest rates. Additionally, changes in market interest rates could impact interest costs associated with any future debt issuances.
ITEM4.CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of September 30, 2024, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
On April 30, 2024, we completed the Svenska Acquisition and have implemented new processes and internal controls to assist us in the preparation and disclosure of financial information. Given the significance of the Svenska Acquisition and the complexity of systems and business processes, we intend to exclude the Svenska Acquisition from our assessment of internal control over financial reporting for the year ending December 31, 2024. Except as described above, there have been no changes in our internal control over financial reporting during the three months ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM1.LEGAL PROCEEDINGS
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that none of the claims and litigation we are currently involved in are material to our business.
ITEM1A.RISK FACTORS
Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2023 Form 10-K, our Q1 2024 Form 10-Q and our Q2 2024 Form 10-Q. Except as set forth below, there have been no material changes in our risk factors from those described in our 2023 Form 10-K.
Provisions of our agreements could discourage an acquisition of us by a third-party.
Certain provisions of our production sharing contracts, joint operating agreements and other agreements could make it more difficult or more expensive for a third-party to acquire us or our assets, or may even prevent a third-party from acquiring us or our assets. For example, some of these agreements contain restrictions on assignments of our assets, including requirements to obtain consent from applicable counterparties, preemption rights and requirements to make bonus payments. In some cases, these restrictions apply to “indirect assignments.” By discouraging an acquisition of us or our assets by a third-party, these provisions could have the effect of deterring otherwise interested third-parties from proposing or consummating these acquisitions. This could prevent the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.
We have limited control over the assets we do not operate.
We have limited control over matters relating to development and exploitation activities, including the timing of and capital expenditures for such activities and compliance with environmental, safety, and other standards, of assets where we are not the operator. The operator and our fellow non-operating owners of these properties may act in ways that are not in our best interest. Additionally, we are dependent on the operator and our fellow non-operating owners of such projects to fund their contractual share of the capital expenditures of such projects. Our dependence on the operator and such parties could have a material adverse effect on our business, results of operations or financial condition.
There are no assurances that we will be able to extend the Block CI-40 Petroleum Production Sharing Contract (“Block CI-40 PSC”).
The Block CI-40 PSC expires in April 2028. The Block CI-40 PSC can be extended by 10 years so long as certain conditions are met. Negotiations to extend the Block CI-40 PSC began in January 2024, led by the operator, CNR International (Côte d'Ivoire) S.A.R.L (the “operator”), with the Director General of Hydrocarbons and the Government of the Côte d’Ivoire. Any extension is subject to approval of the Council of Ministers and formal approval by presidential decree. There can be no assurance that an extension will be approved or that any extension’s terms will not contain terms less favorable than our present arrangement. If the Block CI-40 PSC expires, our results of operations would be adversely affected.
The floating, production, storage and offloading vessel (the “FPSO”) in Côte d'Ivoire is scheduled to come offline for scheduled maintenance in January 2025. Our results will be adversely affected until the FPSO is returned to service which may be a time later than we expect.
As an offshore asset, we, along with the operator and contractors of the Block CI-40 PSC, depend on the FPSO to store the crude oil produced prior to sale to customers. The FPSO contract expires in December 2025. The FPSO is expected to be non-operational beginning on or around January 2025, during which time it will be put on dry dock and undergo maintenance. The FPSO is expected to return to service in 2026. During this time, production relating to the Block CI-40 PSC will be halted and we will receive no revenues from the Block CI-40 PSC. Additionally, there can be no assurance that the FPSO will return to service in the expected timeframe or that the costs of returning it to service will not be more than expected, and in either such case our results would be adversely affected.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sale of Equity Securities
There were no sales of unregistered securities during the quarter ended September 30, 2024 that were not previously reported on a Current Report on Form 8-K.
ITEM5.OTHER INFORMATION
During the three months ended September 30, 2024, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act).
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VAALCO ENERGY, INC.
(Registrant)
By:
/s/ Ronald Bain
Ronald Bain
Chief Financial Officer
(Duly authorized officer and Principal Financial Officer)