VAALCO ENERGY INC /DE/ (EGY) FY 2021 MD&A

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. For further discussion of our two operating segments see “Item 1. Business – Segment and Geographical Information – “Gabon Segment” and “Equatorial Guinea Segment”. As discussed further in Note 4 to the Financial Statements, we have discontinued operations associated with our activities in Angola, West Africa.

RECENT DEVELOPMENTS

On March 11, 2020, the World Health Organization classified the outbreak of a new strain of coronavirus (“COVID-19”) as a pandemic, based on the rapid increase in global exposure. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. The adverse economic effects of the COVID-19 outbreak materially decreased demand for crude oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices in 2020. In April 2020, countries within OPEC+, which includes Gabon, reached an agreement to cut crude oil production to reduce the gap between excess supply and demand, in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement and, as a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production. In response to such request from the Minister of Hydrocarbons, beginning in July 2020 and continuing through April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. Reductions in production have significantly improved the demand/supply imbalance, and crude oil prices have improved from the lows seen in March and April of 2020. As a result, in July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. The decision to increase in production was reaffirmed by an OPEC+ meeting held on February 2, 2022. See “Liquidity” below for discussion of the unexpired commodity swaps we have in place.

We considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used for preparation of the financial statements. As a result, we recognized a number of material charges during the three months ended March 31, 2020, including impairments to our capitalized costs for proved crude oil and natural gas properties and valuation allowances on its deferred tax assets. These are discussed further in the notes to our consolidated financial statements included in this report.

The spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in crude oil and natural gas prices could result in future adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations. Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

In response to the COVID-19 outbreak and the current pricing environment, we took the following measures:

 put in place social distancing measures at our work sites;

 actively screened and monitored employees and contractors that come on to our facilities including testing and quarantines with onsite medical supervision;

 engaged in regular company-wide COVID-19 updates to keep employees informed of key developments; and

 implemented sharing certain costs, such as supply vessels, helicopter, and personnel with other operators in the region.

We expect to continue to take proactive steps to manage any disruption in our business caused by COVID-19 and to protect the health and safety of our employees. However, the health and safety measures we and our vendors have taken have resulted in us incurring higher costs. As a result of these factors and the conditions described above, 2020 was one of the most uncertain and disruptive years that the industry has ever seen.

For the year ended December 31, 2021, crude oil prices have improved, there were no disruptions to operations as a result of COVID-19 or any strain thereof, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required for the twelve months ended December 31, 2021. Crude oil prices have continually increased and are currently at the highest levels seen in recent years. The average annual Brent price per barrel for the year ended December 31, 2020 was $41.96 and increased 69% to $70.86 for the year ended December 31, 2021. At the end of 2021 and continuing into 2022, travel-related restrictions have lessened, access to vaccines that reduce the spread and impact of COVID-19 and its variants have become more accessible and the global economy appears

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more flexible to continuing to effectively operate in a COVID-19 environment. However, while the business environment in 2021 improved, the COVID-19 situation and effects thereof remain fluid. A prolonged outbreak may have a material adverse impact on our financial results and business operations, including the timing and ability of us to complete future drilling campaigns and other efforts required to advance the development of our crude oil and natural gas properties.

Recent Operational Updates

Provisional Award of Two Offshore Blocks in Gabon

The BWE Consortium of VAALCO, BW Energy and Panoro Energy were provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of production sharing contracts (“PSCs”) with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

Charter Agreement for the Floating Storage and Offloading Unit

We are currently a party to an FPSO charter for the storage of all of the crude oil that we produce. This contract will expire in September 2022. In August of 2021, we and our co-venturers at Etame approved the Bareboat Contract and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. (“World Carrier”) to replace the existing FPSO with an FSO. The FSO Agreements require a prepayment of $2 million gross ($1.3 million net) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. Current total capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO).

In December 2020, we completed the acquisition of approximately 1,000 square kilometers of new dual-azimuth proprietary 3-D seismic data over the entire Etame Marin block and have now processed the new 3-D seismic which has allowed us to optimize drilling locations for the 2021/2022 drilling campaign. The seismic data enhanced sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. In conjunction with the 2021/2022 drilling program, that began in December 2021, we executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling Limited, to drill a minimum of three wells with options to drill additional wells. On October 4, 2021, we novated the Borr Jack-Up XIV Inc contract with Borr West Africa Assets, Inc. In December of 2021, we spudded the Etame 8H sidetrack, the first well of the 2021/2022 drilling program. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. The initial flow rate of the ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022.

We estimate the range of cost of the 2021/2022 drilling program with four wells to be between $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest with about $26 million to about $31 million gross expected in 2021, or about $16 million to $20 million net to VAALCO.

Acquisition of Additional Working Interest at Etame Marin Block

In November 2020, we signed a SPA to acquire Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon. On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items were recorded at their fair value. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, a $7.7 million bargain purchase gain was recognized. A bargain purchase gain of $5.2 million is included in “Other, net” under “Other income (expense)” in the consolidated statements of operations. An income tax benefit of $2.5 million, related to the bargain purchase gain, is also included in the consolidated statements of operations. The reason for the bargain purchase gain is mainly due to the lower crude oil price outlook used when the SPA was signed, November 17, 2020, and the higher oil price outlook on February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

The actual impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $84.6 million for the year ended December 31, 2021and a $29.3 million increase to “Net income” in the condensed consolidated statement of operations. Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the

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contingent payment were met and on April 29, 2021, we paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

Workovers

In October 2021, we completed two workovers on the Ebouri 2-H and the Etame 12-H wells. The workover on the Ebouri 2-H well increased production from about 500 gross barrels of oil per day (“BOPD“) (255 BOPD, net) prior to the workover to approximately 1,400 gross BOPD (715 BOPD, net). For the Etame 12-H well, we replaced both the upper and lower electrical submersible pumps (“ESP”) and reconfigured the ESP design resulting in restored production of about 1,800 gross BOPD (920 BOPD, net).

DISCONTINUED OPERATIONS-ANGOLA

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the Financial Statements for all periods presented. See Note 4 to the Financial Statements. In the first quarter of 2019, the Company and Sonangol E.P. entered into a settlement agreement finalizing the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola. Pursuant to the settlement agreement, the Company agreed to pay $4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the $3.3 million receivable from Sonangol P&P. The receivable was related to joint interest billings and was reflected as current assets from discontinued operations at year-end 2018. As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019. In July 2019, subsequent to the publication of an executive decree from the Ministry of Mineral Resources and Petroleum, the Company paid the $4.5 million due under the settlement agreement. For the twelve months ended December 31, 2021 or December 31, 2020, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the years 2021 and 2020 are as follows:

The increase in net cash provided by our operating activities for the year ended December 31, 2021 compared to the same period of 2020 includes a $41.2 million increase in cash generated by continuing operations before change in operating assets and liabilities, which was mainly due to higher revenue as referenced below in Results of Operations. The decrease in cash resulting from the net change in operating assets and liabilities of $18.8 million for the year ended December 31, 2020 reflects an increase of $25.6 million in trade receivables and an increase of $11.1 million in other receivables partially offset by increases in foreign income taxes payable and accrued liabilities of $10.2 million.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. Net cash used in investing activities during the year ended December 31, 2021 included $22.5 million paid for the completion of the Sasol Acquisition as discussed in Note 4 to our consolidated financial statements. In addition, we incurred on a cash basis $16.6 million for property and equipment primarily related to equipment and enhancements as well as expenditures related to the 2021/2022 drilling program as discussed in “Recent Operational Updates” above. See “— Capital Expenditures and Capital Resources, Liquidity, and Cash

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Requirements” below for further discussion. For 2020, the $20.0 million cash basis expenditures consisted of $19.7 million related to the 2019/2020 drilling program and $0.3 million paid for equipment and enhancements.

For the year ended December 31, 2021, net cash used in financing activities included $1.4 million for treasury stock as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 16 to our condensed consolidated financial statements, partially offset by $1.3 million in proceeds from options exercised. Net cash used in financing activities during the year ended December 31, 2020 included $1.1 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.

Capital Expenditures

At December 31, 2018, pursuant to the PSC Extension, we had commitments for capital expenditures related to the drilling of two wells and two appraisal wellbores by September 16, 2020. In February 2020, these commitments were fully met as a result of drilling the Etame 9P and SE Etame 4P appraisal wellbores in 2019 and 2020, respectively, as well as the completion of the Etame 9H and Etame 11H development wells in 2019 and 2020, respectively. See “— Capital Expenditures and Capital Resources, Liquidity, and Cash Requirements” below for further discussion.

During 2021, we had accrual basis capital expenditures attributable to continuing operations of $79.2 million, that includes the Sasol Acquisition, compared to $10.5 million accrual basis capital expenditures in 2020. The difference between capital expenditures and the property and equipment expenditures reported in the consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid on the report dates. Capital expenditures in 2021 are attributable to expenditures related to the 2021/2022 drilling program and Sasol acquisition and the 2020 capital expenditures were attributable to expenditures related to the 2019/2020 drilling program, a portion of seismic acquisition costs and equipment and enhancements. See table 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 in Gabon, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 12 to the Financial Statements for further discussion.

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 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 to hedge price risk associated with a portion of our anticipated crude oil 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 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 transactions is a major oil company’s trading subsidiary, and our derivative positions are generally reviewed on a monthly basis. 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 consolidated statement of operations. We record such derivative instruments as assets or liabilities in the consolidated balance sheet. We do not anticipate any substantial changes in our hedging policy.

For the period from January to June 2019, we had commodity swap contracts for approximately 172,000 barrels of crude oil. On May 6, 2019, we entered into commodity swaps at a Dated Brent weighted average price of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. On January 22, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for a quantity of 709,262 barrels. On May 6, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels.

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The following are the hedges outstanding at December 31, 2021:

The following are the additional hedges entered into in 2022:

Cash on Hand

At December 31, 2021, we had unrestricted cash of $48.7 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 term contract that began in January 2020 and ends in July 2022. Pricing under this contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Capital Resources, Liquidity and Cash Requirements

Historically, 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 the Etame Marin block. 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.

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 and cash flow from operations to support our current cash requirements, including those related to our 2021/2022 drilling program and our ability to fund the FPSO through September 2022 and the FSO charter, through March 2023. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures 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 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.

Cash Requirements

Our material cash requirements generally consist of operating leases, purchase obligations, capital projects and 3D seismic processing, the Sasol Acquisition and abandonment funding, each of which is discussed in further detail below.

Sasol Acquisition – As a result of completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in the Etame have increased based on the increase in our working interest in the Etame from 31.1 % at December 31, 2020, to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February 25, 2021. We expect that part of this increase will be offset by an increase in our operating cash flows based on our increased portion of the Etame production.

FSO Agreements – We are currently a party to an FPSO charter for the production and storage of all of the crude oil that we produce. This contract will expire in September 2022. On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement with World Carrier to replace the existing FPSO with a FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the Cap Diamant vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions. Pursuant to the Operating Agreement, VAALCO Gabon agreed to

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engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO. As consideration for the performance by World Carrier of the Operator Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Operating Agreement) until the end of the term, with such term being the same as the term in the Bareboat Charter.

The FSO Agreements require a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. In addition, VAALCO Gabon agreed to pay a daily hire rate at certain rates specified therein, with such hire rate being based on the year within the term.

The aggregate amount to be paid to World Carrier under the FSO Agreements during 2022 is approximately $11 million gross (or $6.5 million net to VAALCO based on its participating interest in the Etame block), net of any applicable taxes.

In connection with the implementation of the FSO, we are required to incur certain capital expenses in order to facilitate the FSO. Current total capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO).

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. The award is subject to concluding the terms of the PSC with the Gabonese government. BW Energy will be the operator with a 37.5% working interest. We will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by a further two more years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.

Drilling Program – We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8-H development well. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. The initial flow rate of the ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. We expect the campaign to include two development wells and two appraisal wells at an estimated cost of $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest.

In June 2021, in conjunction with our 2021/2022 drilling program, we entered into a contract with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells.

Trends and Uncertainties

Sasol Acquisition – At December 31, 2020, we had 3.2 MMBbls of estimated net proved reserves, all of which are related to the Etame Marin block offshore Gabon. In February 2021, as a result of the Sasol acquisition, we increased our working interest in the Etame Marin block from 31.1% to 58.8%. The current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with rights for two five-year extension periods. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. While both short-term and long-term liquidity are impacted by crude oil prices, our long-term liquidity also depends upon our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable.

COVID-19 Pandemic – While crude oil prices are currently at the highest levels seen in recent years, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude oil and natural gas prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.

Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

Commodity Prices – Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil prices, a decrease in demand for crude oil and future production cuts by OPEC+. In 2020, crude oil prices experienced a significant decline as a result of the substantial decline in the global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. Reductions in production have significantly improved the demand/supply imbalance and crude oil prices have improved from the lows

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seen in March and April of 2020. Between July 2020 and April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. Brent crude prices were approximately $77 per barrel as of December 31, 2021. The decision to increase in production was reaffirmed by an OPEC+ meeting held on February 2, 2022.

ESG and Climate Change Effects – ESG matters continue to attract considerable public and scientific attention. In particular, we expect continued regulatory attention on climate change issues and emissions of greenhouse gases (“GHGs”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion). This increased attention to climate change and environmental conservation may result in demand shifts away from crude oil and natural gas products to alternative forms of energy, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. 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, 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 ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investors’ 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 practices by monitoring our adherence to ESG standards, including the reduction of our carbon footprint and measurement of GHG emissions. ESG is important to us, and we are in the process of developing a multi-year plan to establish and document our ESG base currently and developing a systematic plan to monitor and improve matters related to ESG and climate change going forward.

Hedging

We seek to mitigate the impact of volatility in crude oil prices through hedging On January 22, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for 709,262 barrels. On May 6, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, we entered commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels.

The following are the hedges outstanding at December 31, 2021:

The following are the additional hedges entered into in 2022:

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RESULTS OF OPERATIONS

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

We reported net income for the year ended December 31, 2021 of $81.8 million, compared to a net loss of $48.2 million for the year ended December 31, 2020. The year-over-year increase in earnings was mainly due to increases in sales volumes and prices received and no impairment and deferred tax valuation adjustments in 2021. Substantially all of our operations are attributable to our Gabon segment. Further discussion of results by significant line item follows.

The revenue changes between the years ended December 31, 2021 and 2020 identified as related to changes in price or volume are shown in the table below:

(1)The price in the table above excludes revenues attributed to carried interests

Crude oil revenues increased $131.9 million, or approximately 196.3%, during the year ended December 31, 2021 compared to the same period of 2020. The total barrels lifted for the year ended December 31, 2021 was more than the barrels lifted during the same period in 2020, mainly due to our increased working interest as a result of the Sasol Acquisition partially offset by natural declines in production. The Crude oil sales are a function of the number and size of crude oil liftings in each quarter and thus crude oil sales do not always coincide with volumes produced in any given quarter. We made 11 liftings during both years ended December 31, 2021 and December 31, 2020, respectively. Our share of crude oil inventory, excluding royalty barrels, was approximately 75,680 and 172,276 barrels at December 31, 2021 and 2020, respectively. The crude oil inventory was higher at December 31, 2020 due to the scheduled December 2020 lifting being delayed to January 2021.

Production expenses increased $43.9 million, or approximately 117.8%, in the year ended December 31, 2021 compared to the same period of 2020. The increase in expense was primarily related to costs as a result of our increased working interest as a result of the Sasol Acquisition, increased workover costs and higher marine and personnel costs. On a per barrel basis, production expense, excluding workover expense, for the year ended December 31, 2021 increased to $26.77 per barrel from $21.38 per barrel for the year ended December 31, 2020 primarily as a result of a natural decline in oil production and higher marine and personnel costs. While we have

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not experienced any significant operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $2.9 million, net to VAALCO, for the year ended December 2021 and $1.6 million, net to VAALCO, for the year ended December 2020, in higher costs related to the proactive measures taken in response to the pandemic.

Exploration expenses decreased $2.0 million or approximately 56.0%, in the year ended December 31, 2021 compared to the same period of 2020. The exploration expense in 2020 related to seismic acquisition costs while the expenses in 2021 were due to seismic processing costs. See further information at Item 1. Business – Segment and Geographic Information – Gabon Segment — Development.

Depreciation, depletion and amortization increased $11.7 million, or approximately 124.5%, in the year ended December 31, 2021 compared to the same period of 2020 due to higher depletable costs associated with the Sasol Acquisition. Partially offset by an increase in reserve base associated with the positive revisions in reserves.

Impairment of proved crude oil and natural gas properties for the year ended December 31, 2020 of $30.6 million was the result of declining forecasted crude oil prices primarily due to the COVID-19 pandemic. No impairment was recorded for the year ended December 31, 2021.

General and administrative expenses increased $4.1 million, or approximately 38.1% in the year ended December 31, 2021 compared to the same period of 2020. The increase in expense was in part related to a $2.3 million increase in stock-based compensation expense. The change in expense related to stock appreciation rights (“SARs”) expense was an increase of $2.1 million. SARs liability awards are fair valued. The primary driver to changes in the fair value of these awards is changes in the Company’s stock price. See Note 16 for further discussion. In addition, wages and salaries increased $1.1 million due to severance costs associated with changes in key personnel and legal fees increased $0.3 million due more legal activity in the current year.

Bad debt (recovery) expense and other reflected bad debt expense associated with the VAT allowance for the year ended December 31, 2021. Bad debt expense decreased $0.3 million, or approximately 24.9% in the year ended December 31, 2021 compared to the same period of 2020 mainly due to receipt of $0.5 million, net to VAALCO, in 2021 partially offset by increases in the allowance for bad debt.

Other operating income (expense), net decreased $1.2 million, or approximately 73.6%, in the year ended December 31, 2021 compared to the same period of 2020. The $0.4 million balance for the year ended December 31, 2021 is primarily comprised of the difference between the fair value of the contingent consideration paid to Sasol in April 2021, $5.0 million, and the fair value of the contingent consideration on the closing date of the Sasol Acquisition, $4.6 million. For the year ended December 31, 2020 other operating income (expense) is primarily related to a $0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners related to audits for the years 2017 and 2018 as well as $0.9 million in inventory obsolescence.

Derivative instruments gain (loss), net is attributable to our commodity swaps as discussed in Note 10 to the Financial Statements. The $22.8 million loss for the year ended December 31, 2021 is a result of the increase in the price of Dated Brent crude oil above the weighted average swap price of our derivative instruments during the year ended December 31, 2021 as compared to a decrease in the price of Dated Brent crude oil that resulted in a $6.6 million gain during the comparable period in 2020. Our derivative instruments currently cover a portion of our production through September 2022.

Interest income (expense), net for the years ended December 31, 2020 and 2019 relate to interest income on cash balances and are not material to the financial statements.

Other, net for the year ended December 31, 2021 is primarily attributable to $5.2 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee and foreign currency losses. Other, net was not significant for the year ended December 31, 2020.

Income tax expense (benefit) for the year ended December 31, 2021 was $(22.1) million. This is comprised of $42.4 million of deferred tax benefit and a current tax provision of $20.3 million. The income tax expense for the year ended December 31, 2020 was $27.7 million. This is comprised of $ 24.2 million of deferred tax expense and a current tax provision of $3.5 million. The deferred income tax expense for the year ended December 31, 2020 included a $41.6 million charge to increase the valuation allowances on U.S. and Gabon deferred tax assets due to a decrease in future estimated taxable earnings primarily as a result of lower crude oil prices as well as the overall economic conditions of the industry. The current tax provision in both periods is primarily attributable to our operations in Gabon and is higher in 2021 than income tax for the comparable 2020 period as a result of higher revenues. See Note 8 to the Financial Statements for further discussion.

Income (loss) from discontinued operations, net of tax for the years ended December 31, 2021 and 2020 are attributable to our Angola segment as discussed further in Note 4 to the Financial Statements. The loss from discontinued operations for the year ended December 31, 2021 and December 31,2020, respectively, was related to Angola administration costs.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of Financial Statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial

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condition or operating performance is material. Actual results could differ from the estimates and assumptions used. Further, in some cases, GAAP allows more than one alternative accounting method for reporting. In those cases, our reported results of operations would be different should we employ an alternative accounting method. See Note 2 to the Financial Statements for our accounting policy elections.

Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry. As of December 31, 2021, the Company had deferred tax assets of $86.9 million primarily attributable to Gabon and U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and U.S. and foreign net operating loss carryforwards. A valuation allowance of $46.9 million has been established against the deferred tax assets as of December 31, 2021, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

In certain jurisdictions, we may deem the likelihood of realizing deferred tax assets as remote where we expect that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations. For further discussion, see Note 8 to the Financial Statements.

Oil and Gas Accounting Reserves Determination

The successful efforts method of accounting depends on the estimated reserves we believe are recoverable from our crude oil and natural gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data.

To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including:

expected reservoir characteristics based on geological, geophysical and engineering assessments;

future production rates based on historical performance and expected future operating and investment activities;

future crude oil and natural gas quality differentials;

assumed effects of regulation by governmental agencies; and

future development and operating costs.

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting crude oil and natural gas prices and costs change.

Management is responsible for estimating the quantities of proved crude oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI.

Our senior executives and reserve engineers oversee the review of our crude oil and natural gas reserves and related disclosures by our appointed independent reserve engineers. The senior executives meet with the reserve engineers periodically to review the reserves process and results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the independent reserve engineers.

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Reserves estimates are critical to many of our accounting estimates, including:

determining whether or not an exploratory well has found economically producible reserves;

calculating our unit-of-production depletion rates. Proved developed reserves estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense; and

assessing, when necessary, our crude oil and natural gas assets for impairment using undiscounted future cash flows based on management’s estimates. If impairment is indicated, discounted values will be used to determine the fair value of the assets. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.

See “Item 15. Exhibits and Financial Statement Schedules – Supplemental Information on Crude Oil and Natural Gas Producing Activities (unaudited).”

Successful Efforts Method of Accounting for Crude Oil and Natural Gas Activities

We use the successful efforts method to account for our crude oil and natural gas activities. Management believes that this method is preferable, as we have focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred.

The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.

Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.

We review the crude oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results. For further discussion, see Note 9 to the Financial Statements.

Impairment of Unproved Property

We evaluate our undeveloped crude oil and natural gas leases for impairment on at least a quarterly basis by considering numerous factors that could include nearby drilling results, seismic interpretations, market values of similar assets, existing contracts and future plans for exploration or development. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and to Block P in Equatorial Guinea.

Future Dismantlement, Restoration, and Abandonment Costs

We have significant obligations to remove tangible equipment and restore land and seabed at the end of crude oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

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A liability for an asset retirement obligation (“ARO”) is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our crude oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for asset retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note 11 to the Financial Statements for disclosures regarding the asset retirement obligations.

Derivative instruments and hedging activities

We use derivative financial instruments to achieve a more predictable cash flow from crude oil sales by reducing the exposure to price fluctuations. For more information regarding our use of derivative instruments, see Note 10 to the Financial Statements for disclosures.

The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The significant inputs used to estimate fair value are crude oil prices, volatility, discount rate and the contract terms of the derivative instruments. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” and “Cash settlements received on matured derivative contracts, net” lines items located as adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities on the statements of consolidated cash flows. For further discussion, see Note 10 to the Financial Statements.

Business Combinations

We apply the acquisition method of accounting for business combinations, under which we record the acquired assets and assumed liabilities at fair value and recognize goodwill to the extent the consideration transferred exceeds the fair value of the net assets acquired. To the extent the fair value of the net assets acquired exceeds the consideration transferred, we recognize a bargain purchase gain.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, estimates of the fair value of crude oil and gas reserves are prepared. Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and development costs are used to estimate future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate determined appropriate at the time of the acquisition. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

We estimate the fair values of the acquired assets and assumed liabilities as of the date of the acquisition, and our estimates are subject to adjustment through completion, which is in each case within one year of the acquisition date, based on our ongoing assessments of the fair values of property and equipment, intangible assets, other assets and liabilities and our evaluation of tax positions and contingencies. See Note 4 under “Acquisitions and dispositions” for further discussion.

NEW ACCOUNTING STANDARDS

See Note 3 to the Financial Statements.