UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 20172021

OR

For the transition period from to  

Commission file number: 1-32167

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VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

_____________________________________________________

9800 Richmond Avenue

Suite 700

Houston, Texas 77042

(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code): (713) 623-0801

Securities registered under Section 12(b) of the Exchange Act:

Securities registered under Section 12(g) of the Exchange Act: None

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Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.  Yes ☐¨  No ☒x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15d of the Act. Yes ☐¨  No ☒x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒x  No ☐¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒x  No ☐¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒x

TheAs of June 30, 2021, the aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates as of June 30, 2017 was approximately $54.2$175.0 million based on a closing price of $0.94$3.25 on June 30, 2017.2021.

As of February 28, 2018,2022, there were outstanding 58,862,87658,669,028 shares of common stock, $0.10 par value per share, of the registrant.

operating methods, and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

differentials, (the “12-month average”), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service, derivatives or to depreciation, depletion and amortization.

Terms used to describe seismic operations

SPECIAL NOTESeismic data — Crude oil and natural gas companies use seismic data as their principal source of information to locate crude oil and natural gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones that digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

3-D seismic data — 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three-dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential crude oil and natural gas reservoirs in the area evaluated.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This reportAnnual Report on Form 10-K (this “Annual 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”), 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 reportAnnual 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”, “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:

Events outside of our control, such as the ongoing COVID-19 pandemic, could adversely impact our business, results of operations, cash flows, financial condition and liquidity.

Our business requires significant capital expenditures, and we may not be able to obtain needed capital or financing to fund our exploration and development activities or potential acquisitions on satisfactory terms or at all.

Unless we are able to replace the proved reserve quantities that we have produced through acquiring or developing additional reserves, our cash flows and production will decrease over time.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

All of the value of our current production and reserves is concentrated in a single block offshore Gabon, and any production problems or reductions in reserve estimates related to this property would adversely impact our business.

We may not enter into definitive agreements with the BWE Consortium to explore and exploit new properties, and we may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves operated by the BWE Consortium or from any non-operated properties we have an interest in.

Our offshore operations involve special risks that could adversely affect our results of operations.

If we are not able to timely implement the transition to the FSO unit before the expiration of the FPSO contract in September 2022, our results of operations could be materially adversely affected.

Acquisitions and divestitures of properties and businesses may subject us to additional risks and uncertainties, including that acquired assets may not produce as projected, may subject us to additional liabilities and may not be successfully integrated with our business. In addition, any sales or divestments of properties we make may result in certain liabilities that we are required to retain under the terms of such sales or divestments.

We may experience a financial loss if our significant customer fails to pay us for our crude oil or natural gas or reduce the volume of crude oil and natural gas that they purchase from us.

Our reserve information represents estimates that may turn out to be incorrect if the assumptions on which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves.

If our assumptions underlying accruals for abandonment costs are too low, we could be required to expend greater amounts than expected.

We could lose our interest in Block P if we do not meet our commitments under the production sharing contract.

Commodity derivative transactions we enter into may fail to protect us from declines in commodity prices and could result in financial losses or reduce our income.

Our business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions.

Production cuts mandated by the government of Gabon, a member of OPEC, could adversely affect our revenues, cash flow and results of operations.

We have less control over our investments in foreign properties than we would have with respect to domestic investments, and added risk in foreign countries may affect our foreign investments.

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

Our results of operations, financial condition and cash flows could be adversely affected by changes in currency exchange rates and by currency regulations.

We operate in international jurisdictions, and we could be adversely affected by violations of the United States Foreign Corrupt Practices Act and similar worldwide anti-corruption laws.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

We may not have enough insurance to cover all of the risks we face.

Our business could suffer if we lose the services of, or fail to attract, key personnel.

Crude oil and natural gas prices are highly volatile and a depressed price regime, if prolonged, may negatively affect our financial results.

Exploring for, developing, or acquiring reserves is capital intensive and uncertain.

Material declines in crude oil and natural gas prices have required us, and may require us in the future, to take write-downs in the value of our crude oil and natural gas properties.

Competitive industry conditions may negatively affect our ability to conduct operations.

Competition due to advances in renewable fuels may lessen the demand for our products and negatively impact our profitability.

Weather, unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our crude oil and natural gas activities.

An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our product.

We face various risks associated with increased activism against crude oil and natural gas exploration and development activities.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

The physical and regulatory impact of climate change could disrupt our business and cause us to incur significant costs in preparing for or responding to their effects.

PART I

Item 1. Business

BACKGROUND

VAALCO Energy, Inc. is a Delaware corporation, incorporated in 1985 and headquartered at 9800 Richmond Avenue, Suite 700, Houston, Texas 77042. Our telephone number is (713) 623-0801 and our website address is www.vaalco.com. Information contained on our website is not incorporated by reference into this Annual Report. As used in this Annual Report, on Form 10-K, the terms, “we”, “us”, “our”,“we,” “us,” “our,” the “Company” and “VAALCO” refer to VAALCO Energy, Inc. and its consolidated subsidiaries, unless the context otherwise requires.

We are a Houston, Texas basedTexas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil. Our primary source of revenue has been from ourthe Etame Production Sharing Contract (“Etame PSC”)PSC related to the Etame Marin block located offshore the Republic of Gabon (“Gabon”) in West Africa. We also currently own interestsan interest in an undeveloped block offshore Equatorial Guinea, West Africa. As discussed further in Note 5 to the audited consolidated financial statements included in Part III, Item 8 – “Consolidated Financial Statements

STRATEGY

We own crude oil producing properties and Supplementary Data”(“Financial Statements”), we have discontinued operations associated with ourconduct operating activities in Angola,offshore West Africa.

Our consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc. 

STRATEGY

Our strategy is to utilize our technical expertise and operational infrastructure,Africa with a focus on extending our existing license in Gabon, further developingmaximizing the value of our Gabon resources and expanding into new development opportunities in Westacross Africa. A significant component of ourOur financial results of operations isare heavily dependent upon the differencemargins between prices received for our offshore Gabon crude oil production and the costs to find and produce such crude oil. Oil and natural gas pricesOn September 25, 2018, the term of the Etame PSC with Gabon related to the Etame Marin block located offshore Gabon was extended through 2028 with two five-year options to extend the PSC (“PSC Extension”). The PSC Extension provides us with the extended time horizon necessary to pursue developing the resources we have been volatile and subject to fluctuations based onidentified at Etame. We also completed a number of factors beyond our control. Beginning in the third quarter of 2014, the global prices for oil and natural gas began a dramatic decline, which continued through 2015 and into 2016. During this period, we scaled back our global operations, divested non-core assets, amended our credit agreement and focused on reducing costs and maximizing our cash flows. Crude prices improved during 2017 from $55 per Bbl at the end of 2016 to $67 per Bbl at the end of 2017.  We have conducted no drilling activities in 2016 and 2017, but we may drill two or three development wells in 2018, subject to partner and governmental approval.

At December 31, 2017, we had estimated net proved developed reserves of 3.0 million barrels of oil equivalent. For 2017, our reserves replacement amount was equal to 127%dual listing of our 2017 Gabon production, as reflected incommon stock on the reserve report issued by our independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (NSAI”).  We added 1.3 MMBOE of reserves through reservoir performance additions and 0.6 MMBOE through positive pricing revisions. The increase in the average of the first-day-of-the-month prices adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was from $40.35 for the 2016 year-end report to $53.49 for the 2017 year-end report.

Assuming oil and natural gas prices continue at current levels (and holding other variables constant),London Stock Exchange on September 26, 2019, which we believe that through March 31,will provide us access to additional sources of capital to help fund our growth objectives.

In September 2019, we will be able generate cash flows sufficient to covercommenced our operating expenses. However, an unfavorable resolution of our current obligations or a return to the levels of depressed oil2019/2020 drilling campaign. We drilled one development well and natural gas prices seenone appraisal wellbore in 2019, and during the first quarter of 2016 would2020, we drilled one development well and one appraisal wellbore. In addition, we successfully completed drilling the South East Etame 4H development well and brought the well onto production on March 21, 2020.

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, which will be used to optimize and de-risk future drilling locations and potentially identify new drilling locations. We expect the seismic data to enhance sub-surface imaging by merging legacy data with newly acquired seismic data, allowing for the first continuous 3-D seismic survey over the entire block.

On February 25, 2021, we completed the acquisition of Sasol Gabon S.A.’s (“Sasol’s”) 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the sale and purchase agreement dated November 17, 2020 (the “SPA”).

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 had been provisionally awarded two blocks, G12-13 and H12-13, in the 12th Offshore Licensing Round in Gabon.

The award is subject to concluding the terms of the production sharing contracts with the Gabonese government. BW Energy will be the operator with a 37.5% working interest and we and Panoro Energy will have a material adverse effect37.5% working interest and 25% working interest, respectively, as non-operating joint owners.

In December 2021, we commenced our 2021/2022 drilling campaign offshore Gabon with the Etame 8-H well. We expect to drill a minimum of four wells with options to drill additional wells. In February 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 are now focused on maximizing value, growing reserves and increasing production and will continue our liquidity,efforts to repeat similar drilling campaigns in the future.

Our strategy is to create long-term value for all stakeholders by focusing on profitable growth from low-risk reserve development while maintaining financial conditiondiscipline. Specifically, we seek to:

Focus on maintaining production and results of operations. To fund any potential growth opportunities going forward, we are considering multiple alternatives, including, but not limitedlowering costs to additional debt or equity financing through traditional sources or strategic partnerships (see “— Strategic Alternativesincrease margins and Operating Strategies” below). Therepreserve optionality to capitalize on an increase in crude oil prices;

Manage capital expenditures related to the Etame drilling program so that expenditures can be no guaranteefunded by cash on hand and cash from operations;

Continue our focus on operating safely and complying with internationally accepted environmental operating standards;

Optimize production through careful management of future capital acquisition or fundraising success. We currently have no availabilitywells and infrastructure;

Maximize our cash flow and income generation;

Continue planning for additional borrowings under our Amended Term Loan Agreement.  Our current cash position and our ability to access additional capital may limit our available opportunities.

We believe that improved crude oil pricesdevelopment at Etame as well as increasesfuture activity in Equatorial Guinea;

Preserve a strong balance sheet by maintaining conservative leverage ratios and exhibiting financial discipline;

Opportunistically hedge against exposures to changes in crude oil prices; and

Actively pursue strategic, value-accretive mergers and acquisitions of similar properties to diversify our reserves have favorable implications for our company’s cash flows, potential accessportfolio of producing assets.

Strategy related to capital, liquidity and financial condition and we may incur capital expenditures in 2018 for development, which may require additional capital.    BWE Consortium

Strategic Alternatives and Operating Strategies.  Our Board of Directors has appointed a strategic committee to oversee the evaluation of our strategic alternatives including those discussed below. We can give no assurances that any of these strategic alternatives can be completed, and if so, on reasonable terms that are acceptable to us.

Our strategic growth alternatives are as follows:

Our operating strategies for 2018 are financially driven and are as follows:

We believe that we have strong management and technical expertise specific to West Africa, and that our strengths includeinclude:

Our reputation as a safe and efficient operator in Africa;

Our history of establishing favorable operating relationships with host governments and local joint venture owners;

Our subsurface knowledge of key plays and risks in the following:broader regional framework of discoveries and fields;

OPEC+ agreement, the Minister of Hydrocarbons in Gabon requested that the Company reduce its production. In response to such request from the Minister of Hydrocarbons, between July 2020 and April 2021, the Company temporarily reduced production from the Etame Marin block. Currently, the Company’s production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022. The decision to increase in production was reaffirmed by an OPEC+ meeting held on February 2, 2022.

Development

We commenced our 2019/2020 drilling campaign in September 2019 and completed the campaign in April 2020. In September 2019, we spud the Etame field.9P appraisal wellbore at the Etame block offshore Gabon. In 2001,October 2019, the GovernmentEtame 9P, targeting the subcropping Dentale reservoir, was successfully drilled to a total depth of Gabon awarded to us10,260 feet and our consortium partners a 12,000 gross acre exploitation area forencountered both Gamba and Dentale crude oil sands. In December 2019, VAALCO reached total depth of approximately 8,900 feet in drilling the Etame 9H development well and completed approximately 1,000 feet of the horizontal section within the Gamba reservoir as planned. The horizontal section of the Etame field. The exploitation area has9H development well is at the top of the Gamba structure where the high-quality reservoir is approximately 45 feet thick. After installing production equipment, the Etame 9H development well was brought online at an initial rate of 5,500 BOPD gross, (1,500 BOPD net to VAALCO’s 31.1% working interest in 2019).

Shortly after completion of the Etame 9H development well, we began drilling the Etame 11H horizontal development well from the Etame platform, targeting the same Gamba reservoir at a term of 20 years through June 2021, and includes the Southeast Etame field. There are currently five wells producingdifferent location in the Etame field.

Avouma/South Tchibala field.block. We and our consortium partners have rights toreached a 13,000-gross acre exploitation area for the joint developmenttotal measured depth of Avouma/South Tchibala field and the North Tchibala field, which expire in March 2025. Currently, one well in the Avouma/South Tchibala field is producing and two wells are temporarily shut-in pending workovers.

Ebouri field.  We and our consortium partners have rights to a 3,700-gross acre exploitation area for the joint development of the Ebouri field, which expire in July 2026. Currently, we have one producing well in the Ebouri field.

Southeast Etame.    We drilled one well in the Southeast Etame field in 2015, and this well is continuing to produce. The Southeast Etame field is included in the exploitation area for the Etame field which has a term of 20 years through June 2021.

North Tchibala field.    We drilled two wells in the North Tchibala field in 2015. These wells targeted the Dentale formation, and are producing currently. The North Tchibala field is included in the exploitation area for the Avouma/South Tchibala field. This exploitation area expires in March 2025.

Development.  Following the installation of the platform for the Etame field and the platform for the Southeast Etame/North Tchibala fields in 2014, we commenced drilling the first well of a multi-well drilling campaign in 2014. As a result of this campaign, in 2015, two new development wells were drilledapproximately 9,022 feet in the Etame field11H development well and completed approximately 860 feet of horizontal section within the Gamba reservoir. Similar to Etame 9H well, the horizontal section of the Etame 11H well is at the top of the Gamba structure but at a different location. After installing production equipment, the Etame 11H well was brought on production, and three new development wells wereonline at an initial flow rate of approximately 5,200 BOPD gross, (1,400 BOPD net to VAALCO’s 31.1% working interest in 2020) , in early January 2020.

We drilled and brought on productionthe SE Etame 4P appraisal wellbore to evaluate a Gamba step out area in the Southeast Etame field and the North Tchibala field. The first well drilled was not placed on production due to high levels of hydrogen sulfide (“H₂S”) present in fluids produced from the well.  See “—  Hydrogen Sulfide Impact” below. 

The Constellation II drilling rig that we had contracted in 2014 and 2015 for these operations performed workover operations in late 2015 and early 2016.  In February 2016, due to the continuing low commodity price regime, we released the rig and incurred expenses of $7.9 million in 2016, net to us, related to its demobilization and early release. These expenses are reflected in “Other operating expenses” in the Financial Statements. See also Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Rig commitment.”

Duringblock during the first quarter of 2016,2020. With the drilling of the SE Etame 4P appraisal wellbore, we conducted workover operations on two Avouma field wells. An Electrical Submersible Pump (“ESP”) system was replaced successfullysatisfied the drilling commitment as part of the PSC Extension that we signed in one well, butlate 2018. The SE Etame 4P appraisal wellbore indicated the workover operations on the second well were suspended duepresence of approximately 1.0 to operational problems. During the second and third quarters2.0 MMBbls of 2016, the ESPshydrocarbons in the South Tchibala 2-HGamba reservoir, and the Company began drilling a third development well, the SE Etame 4H as part of the 2019/2020 drilling campaign. This development well was brought online in late March of 2020. With respect to all of the wells drilled in the 2019/2020 drilling campaign, we did not encounter hydrogen sulfide (“H₂S”) in either the Gamba or Dentale reservoirs, which could impact the safety and marketability of production from those wells.

As discussed above, 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. We expect the seismic data to enhance sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. The processing of the seismic data began in January 2021, and was completed by the fourth quarter of 2021. The seismic data will be used to optimize and de-risk future drilling locations and potentially identify new drilling locations. We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8-H development well. We anticipate the costs of the 2021/2022 drilling program to have an estimated cost of $117.0 million to $143 million gross, or $74.0 million to 91.0 million, net to VAALCO’s 63.6% participating interest. In February 2022, we completed the drilling of the Etame 8-H well and moved the Avouma 2-H well also failed. These wells were temporarily shut-in, but through our utilizing a lower-cost hydraulic workover unitdrilling rig to replace the failed ESP systems, the two wells were placed back on production in December 2016 and January 2017, respectively.

On November  22, 2016, we closed on the purchase of an additional 2.98% working interest (3.23% participating interest) in the Etame Marin block from Sojitz Etame Limited (“Sojitz”), which had an effective date of August 1, 2016.  See Note 5 of the Financial Statements for further discussion. 

In July 2017, the ESP in the South Tchibala 2-H well failed, resulting in the well being temporarily shut-in.

In October 2017, we began workover operations on the South Tchibala 1-HB well.  These operations were successfully completed in November 2017, and the well was returned to production. However, this well experienced an ESP failure in late December, and it remains temporarily shut-in.  We began workover operations on the South Tchibala 2-H well in November 2017.  These operations were successfully completed in November 2017, and the well was returned to production.  In November 2017, the Avouma 2-H well experienced ESP failures, and the well remains temporarily shut-in.  We are working with the manufacturer and other technical

consultants to investigate the root causes of the ESP failures.  Excluding the Avouma platform wells,to drill the wells onAvouma 3H-ST1 development well, which is targeting the other three platforms with ESPs have operated without incident for up to four years. 

During July 2017, production was temporarily shut-in for periodic maintenance, and as a result, production volumes were lower in the three months ended September 30, 2017 and our production expense increased as a resultGamba reservoir. The initial flow rate of the maintenance-related costs.ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022.

Our current net production is averaging approximately 3,500 barrels of oil equivalent per day (BOEPD), down from a 4,160 barrels of oil equivalent per day (BOEPD) average for fiscal 2017 as a result of natural decline and temporarily shutting in the Avouma 2-H well.Production

For 2017, our total proved reserves replacement was 127% of our 2017 total net production in Gabon. See “— Reserve Information” below. These results occurred primarily due to (i) better-than-forecasted results for production and (ii) increased crude oil prices.

Production.  Production operations in the Etame Marin block include nineeleven platform wells, plus three subsea wells across all fields tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the crude oil from a leased FPSO vessel anchored to the seabed on the block. Production from seven of our wells is aided by ESPs.electric submersible pumps (“ESPs”). We currently have tenfourteen producing wells and two wells shut in at Avouma due to ESP failures.wells. The FPSO has production limitations ofcan process up to approximately 25,000 BOPD and 30,000 barrelsBbls of total fluids per day. For the years ended December 31, 2017,  20162021, 2020 and 2015,2019, aggregate production from the block was approximately 5.65.4 MMBbls (1.5(2.6 MMBbls net to us), 6.26.6 MMBbls (1.5(1.8 MMBbls net to us) and 6.84.7 MMBbls (1.7(1.3 MMBbls net to us), respectively. Our net share of barrels produced reflects an allocation of cost oil and profit oil after reduction for a royalty of approximately 13%. Periodically, we perform workovers on our wells to maintain or restore production. For further discussion on workovers see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments.”

Hydrogen Sulfide Impact

Four of our wells are currently shut-in for safety and marketability reasons because of high levels of H₂S. These wells have been excluded from the above-referenced well count. H₂S was not encountered in any of the wells or appraisal wellbores drilled in the 2019/2020 drilling campaign and thus far in the 2021/2022 drilling campaign. To re-establish and maximize production from the impacted areas, additional capital investment will be required, including the construction of one or more processing facilities capable of removing H₂S, the recompletion of the temporarily abandoned wells and the potential drilling of additional wells. TheseWe have determined that these identified processing facilities are not economicthe most economically attractive use of the Company’s resources at current forecastedcrude oil prices. As of December 31, 2017,2021, we had no proved reserves booked for the wells impacted by high levels of H₂S.

Exploration

At December 31, 2017,2021, we had no$13.7 million in undeveloped leasehold costs related to the Etame Marin block. The sixth extension periodThese costs are associated with the exploitation area expansion related to the PSC Extension and acquisition of Sasol’s interest in the exploration acreage onSasol Etame Marin block.

Abandonment Costs

Under the Etame Marin block expired at the end of July 2014, with the Consortium having fully met all of the obligations under its terms. 

Abandonment Costs

As part of securing the first of two five-year extensions toPSC terms, the Etame field production license to which we were entitled from the government of Gabon, weConsortium has agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. The agreement was finalized in 2014, but effective for 2011 forward, providing for annual funding over a period of ten years at 12.14% of the total abandonment estimate for the first seven years, with annual payments for the remaining unfunded estimated costs spread over the last three years of the production license.

We are required under the Etame PSC to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The currentmost recent abandonment study was completed in January 2016 resulting2021 and resulted in estimated gross abandonment costs of approximately $61.1$81.3 million ($19.047.8 million, net to VAALCO) on an undiscounted basis. Through December 31, 2017,  $34.82021, $37.1 million ($10.821.8 million, net to VAALCO) on an undiscounted basis has been funded. The annual abandonment cost requirements net to VAALCOVAALCO’s 58.8% working interest, are expected to be $2.3$5.8 million in 2018,2022 and, $4.9 million overonce the years from 2019 to 2021 netabandonment study has been approved by Ministry of estimated interest income.Hydrocarbons in Gabon, a revised funding schedule will be established. Amounts paidpaid are reimbursable through a “Cost Account” under the cost accountEtame PSC, which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. These amounts are non-refundable. Our estimated liabilities for the abandonment of these Gabon offshore facilities as of December 31, 20172021 and 20162020 were $20.2$40.7 million and $18.6$17.3 million, respectively, which are included in the total “Asset retirement obligation” line item on our consolidated balance sheets as of December 31, 20172021 and 2016.2020. Initial recording of this liability is offset by a corresponding capitalization of asset retirement costs reflected under “Property“Crude oil and natural gas properties and equipment – successful efforts method” in the line item “Wells, platforms and other production facilities” on our consolidated balance sheets as of December 31, 20172021 and 2016.    2020. 

Onshore – Mutamba Iroru Block

We have a 50% working interest (41% net working interest assuming the Republic of Gabon exercises its back-in rights) and have been designated as the operator of the Mutamba Iroru block located onshore Gabon. Because of the lower projected oil price data in 2015, we wrote off our investment in this block in 2015, charging all costs, including capitalized exploratory well costs, to exploration expense. The government of Gabon believes that our production sharing contract for this block expired in mid-2014. While we maintain that the PSC is still valid, we expect that a new PSC would be required in order to pursue development, and we would only enter into a new PSC in the event that the project becomes economic. We can provide no assurances as to either the approval of a new PSC, or any subsequent approval of a development plan by the Government of Gabon.

Equatorial Guinea Segment

We haveacquired a 31% working interest in an undeveloped portion of a block (“Block PP”) offshore Equatorial Guinea that we acquired in 2012. ItThe Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as the operator of Block P on November 12, 2019. We acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing our working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million to Compania Nacional de Petroles de Guinea Equitoria, (“GEPetrol”) in the event that there is currently unlikely thatcommercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. In April 2021 Crown Energy, who held a 5% working interest, elected to default on its obligations from Block P. On April 12, 2021, the majority of non-defaulting parties, as required by the Block P joint operating agreement, assigned the defaulting party’s interest to the non-defaulting parties. As a result, VAALCO’s working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. We have completed a feasibility study of a standalone development concept of the Venus discovery on Block P. We, working closely with the other joint venture owners, are now in the process of finalizing the plan of development before submitting it to the EG MMH for their approval.

As of December 31, 2021 and 2020, we will be making any near-term expenditureshad $10.0 million recorded for the book value of the undeveloped leasehold costs associated with respect to any development of this property.  the Block P license.

We and our partners will need to evaluatejoint venture owners are evaluating the timing and budgeting for explorationdevelopment and developmentexploration activities under a development and production area in the block, including the approval of a development and production plan to developfor the Venus discovery on the block. OurDiscovery. The Block P production sharing contract covering this development and production area provides for a development and production period of 25 years from the date of approval of a development and production plan.

United States SegmentOPEC+ Production Reductions

Near the end of 2019, OPEC had an agreement in place to reduce production by a total of 1.2 MBOPD until March 2020. In April 2017,2020, countries within OPEC+ 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 undertook 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 the request from the Minister of Hydrocarbons, in July 2020 through April 2021, we temporarily reduced production from the Etame Marin block. In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022. The decision to increase production was reaffirmed by an OPEC+ meeting held on February 2, 2022.

DRILLING ACTIVITY

As discussed above, we commenced the 2019/2020 drilling campaign in September 2019. The following table sets forth the total number of completed the sale of our interestsexploratory and development wells drilled in the East Poplar Dome field in Montana for $0.3 million, resulting in2021, 2020 and 2019 on a gain of approximately $0.3 million during the year ended December 31, 2017.    gross and net basis:

In December 2016,2021 we completedbegan drilling the sale of our interests in two producing wells in the Hefley field (Granite Wash formation) in North Texas for $0.8 million, resulting in an immaterial loss. Our remaining interests in the U.S. are inconsequential.    

Organization of Petroleum Exporting Countries (“OPEC”) Production Reductions

In November 2016, OPEC reached a decision to reduce its level of production effective January 1, 2017. Gabon, as a member of OPEC, agreed to reduce its production by up to 9,000 Bbl per day. In November 2017, OPEC reached a decision to extend the period of the reduced production levels through December 2018.  As a result of natural production declines,  production in 2017 was not impacted by this agreement, and for 2018 we do not expect our production or drilling plans will be impacted by the agreement.

DRILLING ACTIVITY

The table below reports the results of our drilling activity for each of the last three years. The “International” geographic designation for the prior three years was comprised solely of Gabon.

(1)N’Gongui No. 2 discovery well, which had been suspended since being drilled onshore Gabon in 2012 and was deemed to be unsuccessful in 2015. Excludes an unsuccessful well associated with discontinued operations in Angola.

(2)Includes the EtameETAME 8-H development well that was completed in progress at December 31, 2014, evaluated for H₂S in 2015 and then shut-in when the presence of high levels of H₂S was confirmed.February 2022.

ACREAGE AND PRODUCTIVE WELLS

Below is the total acreage under lease or covered by the Etame PSC and Block P and the total number of productive crude oil and natural gas wells as of December 31, 2017:2021

(1)Excludes four wells shut-in due to the presence of high levels of H2S. All wells included in the table are Etame Marin block.

RESERVE INFORMATION

Estimated Reserves and Estimated Future Net Proved ReservesRevenues

Reserve Data

In accordance with the current SEC guidelines, of the SEC, estimates of future net cash flow from our properties and the present value thereof are made using an unweighted, arithmeticthe average of the first-day-of-the-month price for each of the 12twelve months of the year adjusted for quality, transportation fees and market differentials. Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2017,2021, the average of such price used for our reserve estimates was $53.49$69.10 per Bbl for crude oil from Gabon. This compares to the average of such price used for 20162020 of $40.35$42.46 per Bbl.Bbl and $63.60 per Bbl for 2019.

Reserves are reported by geographic area. International consists solelybelow consist of net proved reserves related to the Etame Marin block located offshore Gabon in West Africa. We haveThe Company currently has no proved reserves related to our other international ventures and as a result of the sale of the Hefley wells in December 2016, we have no proved reserves in the United States. There have been no estimates of total proved net crude oil or natural gas reserves filed with or included in reports to any federal authority or agency other than the SEC since the beginning of the last fiscal year. Natural gas volumes include natural gas liquid (“NGL”) barrels which were converted to Mmcf using the relative prices of the products.reserves. The table below sets forth our estimated net proved reserve quantities for the years ended December 31, 2017,  2016,2021, 2020 and 20152019 as prepared by NSAI,our independent petroleum engineers.

engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). The 2021 information includes the Sasol interest in the Etame Marin block as we acquired Sasol’s interest on February 25, 2021.

2022. At December 31, 2020, we had no PUDs recorded atdue to current SEC pricing. At December 31, 2017, 2016 and 2015.2019, we had no PUDs because future development wells had not been approved by joint venture owners.

Controls over Reserve Estimates

Our policies and practices regarding internal controls over the recording of reserves isare structured to objectively and accurately estimate our crude oil and natural gas reserves quantities and present values in compliance with SEC regulations and generally accepted accounting principles in the U.S. (“GAAP”). Compliance with these rules and regulations with respect to our reserves is the responsibility of a reservoir engineer, who is our principal engineer. Our principal engineer has over 2030 years of experience in the crude oil and natural gas industry, including over 10 years as a reserve evaluator and trainer, and is a qualified reserves estimator, as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a Bachelor’s degree in mechanical engineering and Master’s degree in petroleum engineering and Texas Professional Engineering (PE) certification, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers. The Audit Committee of the Board of Directors meets periodically with management to discuss matters and policies related to reserves.

Our controls over reserve estimation include retaining NSAI as our independent petroleum and geological firm for all years presented. We provide information to NSAI about our crude oil and natural gas properties, which includes, but is not limited to, production profiles, ownership and production sharing rights, prices, costs and future drilling plans. NSAI prepares its own estimates of the reserves attributable to our properties. The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. John R. Cliver and Mr. Zachary R. Long. Mr. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. He graduated from Rice University in 2004 with a Bachelor of Science Degree in Chemical Engineering and from the University of Texas at Austin in 2008 with a Master of Business Administration Degree. Mr. Long, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from University of Louisiana at Lafayette in 2003 with a Bachelor of Science Degree in Geology and from Texas A&M University in 2005 with a Master of Science Degree in Geophysics.

Net Volumes sold, Prices, and Production Costs

Net volumes sold, average sales prices per unit, and production costs per unit for our 2017,  2016,2021, 2020 and 20152019 operations are shown in the tables below. All volumes are for crude oil produced from the Etame Marin block.

DISCONTINUED OPERATIONS-ANGOLA

On September 30, 2016, we notified Sonangol P&P, our joint venture partner,owners, that we were withdrawing from the joint operating agreement effective October 31, 2016. 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. In 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. See “Item 7. “7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Discontinued Operations - Angola.”

AVAILABLE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov.

You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our website at www.vaalco.com. No information from the either the SEC’s website or our website is incorporated by reference herein. We have placed on our website copies of charters for our Audit Committee, Charter,Compensation Committee and Nominating and Corporate Governance Committee as well as our Code of Business Conduct and Ethics (“Code of Ethics”), Corporate Governance Principles and Code of Ethics for the Chief Executive OfficerCEO and ChiefSenior Financial Officer.Officers. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, VAALCO Energy, Inc., 9800 Richmond Avenue, Suite 700, Houston, Texas 77042.

Professional Development, Safety and Training

We believe that key factors in employee retention are professional development, safety and training. We have training programs across all levels of the Company to meet the needs of various roles, specialized skill sets and departments across the Company. We provide compliance education as well as general workplace safety training to our employees and offer Occupational Safety and Health Administration training to key employees. We are committed to the security and confidentiality of our employees’ personal information and employs software tools and periodic employee training programs to promote security and information protection at all levels. We utilize certain employee turnover rates and productivity metrics in assessing our employee programs to ensure that they are structured to instill high levels of in-house employee tenure, low levels of voluntary turnover and the optimization of productivity and performance across our entire workforce. Additionally, we have a performance evaluation program which adopts a modern approach to valuing and strengthening individual performance through on-going interactive progress assessments related to established goals and objectives.

Communication and Engagement

We strongly believe that our success depends on employees understanding how their work contributes to the Company’s overall strategy. To this end, we communicate with our workforce through a variety of channels and encourage open and direct communication, including: (i) quarterly company-wide CEO updates; (ii) regular company-wide calls with management and (iii) frequent corporate email communications.

COVID-19 Pandemic

In response to the COVID-19 pandemic, related government legislation and guidelines and orders issued by key authorities, we implemented changes that we determined were in the best interest of our employees, as well as the communities in which we operate. These changes included quarantining and testing of employees and persons before going to our offshore platforms, having the majority of our employees work from home for several months, and implementing additional safety measures for employees continuing critical on-site work. We continue to maintain a high level of safety protocols and embrace a flexible working arrangement for our employees in Houston.

COMPETITION

The crude oil and natural gas industry is highly competitive. Competition is particularly intense from other independent operators and from major crude oil and natural gas companies with respect to acquisitions and development of desirable crude oil and natural gas properties and licenses, and contracting for drilling equipment. There is also competition for the hiring of experienced personnel. In addition, the drilling, producing, processing and marketing of crude oil and natural gas is affected by a number of factors beyond our control, which may delay drilling, increase prices and have other adverse effects, which cannot be accurately predicted.

Our competition for acquisitions, exploration, development and production includes the major crude oil and natural gas companies in addition to numerous independent crude oil companies, individual proprietors, investors and others. We also compete against companies developing alternatives to petroleum-based products, including those that are developing renewable fuels. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable crude oil and natural gas assets, or to evaluate, bid for and purchase a greater number of properties and licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry-wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. Our ability to generate reserves in the future will depend on our ability to select and acquire suitable producing properties and/or developingdevelop prospects for future drilling and exploration.

INSURANCE

For protection against financial loss resulting from various operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, worker’s compensation and employer’s liability. We maintain insurance at levels we believe to be customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment. Such insurance might not cover the complete claim amount and would not cover fines or penalties for a violation of environmental law. We are not fully insured against all risks associated with our business either because such insurance is unavailable or because premium costs are considered uneconomic. A material loss not fully covered by insurance could have an adverse effect on our financial position, results of operations or cash flows.

REGULATORY

General

Our operations and our ability to finance and fund our operations and growth are affected by political developments and laws and regulations in the areas in which we operate. In particular, crude oil and natural gas production operations and economics are affected by:

civil unrest;

price and currency controls;

limitations on crude oil and natural gas production;

tax, environmental, safety and other laws relating to the petroleum industry;

changes in laws relating to the petroleum industry;

changes in administrative regulations and the interpretation and application of administrative rules and regulations; and

changes in contract interpretation and policies of contract adherence.

In any country in which we may do business, the crude oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the crude oil and natural gas industry, some of which carry substantial

penalties for the failure to comply. The regulatory burden on the crude oil and natural gas industry increases our cost of doing business and our potential for economic loss.

Gabon

Our exploration and production activities offshore Gabon are subject to Gabonese regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations. The following is a summary of certain applicable regulatory frameworks in Gabon.

In 2014 a new Hydrocarbons Law entered into force to regulate oil - Up until 2014, the fiscal and gas activities in Gabon. It repealed some prior laws relating to oil activities as well as all contradictory regulations contained inregulatory framework governing the remaining non-repealed lawsexploration and production of the oil and gas sector.

Pursuant to the Hydrocarbons Law, petroleum resourceshydrocarbons in Gabon arewas notably unregulated. Successive model contracts issued by the propertyState of Gabon acted as guidelines; all fiscal aspects of each contract were negotiable between the State of Gabon and exploratory parties, including work commitments and exploration costs for each PSC.

In September 2014, Law No. 11/2014, of 28 August 2014, came into force in Gabon (“2014 Hydrocarbons Law”). The 2014 Hydrocarbons Law was not exhaustive; it sought to provide a framework of governing principles and rules, applicable to both the exploratory and extracting industry of hydrocarbons, as well as the downstream sector, to be complemented by implementing regulations.

Under the Gabonese Civil Code (“Civil Code”), laws will not have retroactive effects unless they expressly or tacitly provide otherwise. The Civil Code further provides that former laws continue to govern the effects of existing contracts, save in case of express or tacit derogation by the legislator and that, in any event, the application of a new law to existing contracts cannot modify the effects already produced by existing contracts under a former law, except via express derogation by the legislator.

The 2014 Hydrocarbons Law explicitly provided that establishment conventions, petroleum companies undertake operations on behalf of the Government of Gabon. In order to conductcontracts, petroleum operations, oiltitles, mining concessions and gas companies must enter into a hydrocarbons agreement, typically an exploration and production sharing contract, which is signed on behalf ofexploitation permits concluded or granted by the State by the Minister in charge of Hydrocarbons and the Minister in charge of Economy. Such agreement is subject to enactment by Presidential Decree, and its provisions must conformGabon prior to the date of its publication remained in force until their expiration date.

However, the 2014 Hydrocarbons Law subject to being null and void.

Furthermore, under Article 260further provided that unless such arrangements became consistent with the requirements of the 2014 Hydrocarbons Law, all oilestablishment conventions, mining concessions and gas companies, even those carrying out operations underexploitation permits in effect could not be extended or renewed. Furthermore, the previous legal framework, must make payment2014 Hydrocarbons Law prohibited establishment conventions and mining concessions, and provided that the exploitation of two financial contributions set forthnew discoveries in areas covered by existing conventions and concessions would be required to be made in accordance with the 2014 Hydrocarbons Law.

2019 Hydrocarbons Law - The 2014 Hydrocarbons Law was repealed in its entirety by Law No. 002/2019, of 16 July 2019, published on 22 July 2019 (“2019 Hydrocarbons Law”). As with the 2014 Hydrocarbons Law, the 2019 Hydrocarbons Law contains provisions applicable to both the upstream and downstream segments. However, despite the publication of the 2019 Hydrocarbons Law, there are various issues and matters yet to be fully enacted by implementing regulations.

Under the transitory provision contained in the new2019 Hydrocarbons Law, namelyexisting PSCs and other petroleum contracts, permits and authorizations remain in full force and effect until their expiration.

However, any renewal or extension of those instruments are subject to the Investment Diversification Fund (payment of 1%provisions of the Contractor’s turnover during the production phase),2019 Hydrocarbons Law, and theits implementing regulations.

The 2019 Hydrocarbons Investment Fund (payment of 2%Law also provides for obligations for immediate application, irrespective of the Contractor’s turnover duringdate of signature of existing PSCs or petroleum contracts and/or granting of petroleum permits and authorizations. These include (i) the requirement for foreign producers and explorers applying for an exclusive development and production phase),authorization to conduct their operations in Gabon through a company incorporated in Gabon rather than through branches of entities incorporated in other jurisdictions; and (ii) the obligation for all companies undertaking hydrocarbon activities to domicile their site rehabilitation funds with the Bank of Central African States, which is the Central African Economic and Monetary Community (“CEMAC”) or a Gabonese bank or financial

institution subject to the Central Africa Banking Commission, which supervises banks and financial institutions licensed to operate in CEMAC countries, within two years ofone year after the entry into force thereof. Under Article 260, oilof the 2019 Hydrocarbons Law.

PSCs entered into between independent contractors and gas companiesthe State of Gabon since the implementation of the 2019 Hydrocarbons Law must include a clause providing that participation by the State of Gabon cannot exceed a 10 percent participating interest in the operations, to be carried by the contractor.

The 2019 Hydrocarbons Law also withinentitles the Gabon Oil Company to acquire a maximum of one year from publication15 percent stake at market value in all PSCs as of the Hydrocarbons Law, set up and domiciledate of signature.

In addition, the site rehabilitation funds for the Hydrocarbon activities at the Banque des Etats de l’Afrique Centrale or at a Gabonese banking or financial institution.

The2019 Hydrocarbons Law provides that the State of Gabon may acquire an equity stake of up to 10 percent, at market value, in an operator applying for a detailed legal frameworkor already holding an exclusive development and production authorization.

Equatorial Guinea

Our exploration and production activities in terms of organizationEquatorial Guinea are subject to the applicable regulations of the sector, contentscountry. Failure to comply with these laws and termsregulations may result in the suspension or termination of our operations and conditionssubject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations. The following is a summary of certain applicable regulatory frameworks in Equatorial Guinea.

All hydrocarbons agreements, liability, local content, safetyexisting in Equatorial Guinea’s onshore territory, as well as in its sovereign and environment, domestic supply requirements, fiscal termsjurisdictional waters, are Equatorial Guinea property and part of the public domain. The monetization of such ashydrocarbons is to be pursued exclusively by Equatorial Guinea under its constitution, which reserves the exploitation of mineral and hydrocarbons resources exclusively to Equatorial Guinea and the public sector. However, the constitution also provides that Equatorial Guinea can delegate to, grant a concession to or associate itself with private parties for purposes of exploration and production sharing, royalty, bonusesactivities in the manner and other charges, corporate income tax, customs,cases set forth by law.

Private crude oil companies have been allowed to conduct petroleum operations in Equatorial Guinea through PSCs signed by the minister responsible for petroleum operations on behalf of Equatorial Guinea. PSCs are subject to ratification by the President of the Republic of Equatorial Guinea and local training obligations.

become effective only on the date the contractor is notified of presidential ratification. The powers to make many ofsign and amend PSCs and supervise their performance belong to the day-to-day decisions concerningministry responsible for petroleum activities, including the granting of certain consents and authorizations, remain vested with the Hydrocarbons General Directorate, a government authority.operations. In addition, the national oil company—Société Nationale des Hydrocarbures du Gabon—currentlycompany of Equatorial Guinea, GEPetrol, holds, manages and takes participations in petroleum activities on behalf of Equatorial Guinea.

In 2006, the State. PursuantParliament of Equatorial Guinea passed a new hydrocarbons law (“2006 Hydrocarbons Law”), which superseded the previous 1981 Hydrocarbons Law, as amended in 2000, incorporating not only the regime applicable to Article 4the exploration, appraisal, development and production of hydrocarbons, but also rules on their transportation, distribution, storage, preservation, decommissioning, refining, marketing, sale and other disposal. The Hydrocarbons Law contains provisions on a number of aspects concerning exploration and production operations and contracts, such as national content obligations, unitization, transfers and abandonment. The 2006 Hydrocarbons Law grants the ministry appointed to be responsible for petroleum operations (“Appointed EG Petroleum Ministry”) significantly broad regulatory, inspective and auditing powers concerning the performance of petroleum operations. These include the powers to negotiate, sign, amend and perform all contracts entered into between the State of Equatorial Guinea and independent contractors, as well as the right to access all data and information required for the control of contractors and their activities, including free access to the locations and facilities where petroleum operations are conducted.

In addition, the Appointed EG Petroleum Ministry can also order (i) the suspension of petroleum operations; (ii) the evacuation of persons from locations; (iii) the suspension of the use of any machine or equipment; and/or (iv) any other action it deems necessary or appropriate when the Appointed EG Petroleum Ministry determines that a given petroleum operation may cause injury to or death of persons, damage properties, or harm the environment, or whenever the national interest so requires.

Until June 2016, the Appointed EG Petroleum Ministry was the Ministry of Mines, Industry and Energy, whose organization and authority were granted under Decree No. 170/2005, of 15 August 2005.

In June 2016, the President of Equatorial Guinea appointed the EG MMH and the Minister of Industry and Energy, effectively splitting the Ministry of Mines, Industry and Energy into two ministries. However, no legislation on the organization and authority of each ministry has been enacted, and, in effect, the EG MMH has been exercising the powers contained within the Hydrocarbons Law to theAppointed EG Petroleum Ministry.

All contracts signed with the State may acquire an equity stake of up to 20%, at market value, within any companies applyingEquatorial Guinea for or already holding an exclusive production authorization. The contractor must carry the State in its 20% participating interest in the hydrocarbons agreements during the exploration phase. The parties are free to agree on a higher stake at market value. Further, under Article 86and production of hydrocarbons have taken the form of PSCs. A model PSC, approved along with the Hydrocarbons Law, must be used as the basis for any negotiation between independent contractors and the State of Equatorial Guinea. Over time, however, revised copies of the model PSC, reflecting changes made during negotiations of certain PSCs, have been used for the negotiation of subsequent PSCs.

The Hydrocarbons Law and Petroleum Regulations provide the Appointed EG Petroleum Ministry with the power to award contracts for the exploration and production of hydrocarbons, and decide whether the award is made by means of competitive international public tender or direct negotiation. These contracts, however, which are to be negotiated by the Appointed EG Petroleum Ministry, shall only become effective after they have been ratified by the President of Equatorial Guinea and on the date of delivery to the contractor of a written notice of the President’s ratification. In practice, however, this notification to operators has been provided by the Appointed EG Petroleum Ministry.

GEPetrol, established in 2001, is the national oil company of Equatorial Guinea and Sociedad Nacional de Gas de Guinea Equatorial (“Sonagas”), established in 2005, is the national gas company of Equatorial Guinea.

The Hydrocarbons Law provides that these national companies are exclusively owned by the State of Equatorial Guinea, and must be supervised by the Appointed EG Petroleum Ministry.

Under the applicable laws, the State of Equatorial Guinea may also acquire participating interestselect to have, either directly or through a national company, a minimum interest of up20 percent in a PSC.

The State of Equatorial Guinea’s interest (through GEPetrol or otherwise) may be, and typically is, carried. No costs are paid by the State of Equatorial Guinea or GEPetrol with respect to 15%, at market value.

In addition to general labor regulations, which requirea carried interest. The Hydrocarbons Law provides that the workforceState of Equatorial Guinea (through GEPetrol or otherwise) will only be required to contribute to any companycost for petroleum operations that it has a carried interest in Gabon compliesfrom the period where it notifies the contractor that it no longer wants its interest carried. In effect, however, the carry normally ends with a 90/10 ratiothe approval of Gabon nationalthe development and production of the asset subject to foreign expatriate workers, pursuant tothe PSC.

The terms and effects of the carry of an interest of the State of Equatorial Guinea (through GEPetrol or otherwise) are not clearly established in the Hydrocarbons Law subcontracting activities are awarded in priorityor the Petroleum Regulations; the contractor that carries the State of Equatorial Guinea’s interest is given the right to Gabonese companies in which at least 80%a percentage of the workforce consists of Gabonese nationals. In this respect, only technically qualified license holders may be hiredcost recovery oil pertaining to that interest, as subcontractors.agreed in each PSC.

Under the 2014 Hydrocarbons Law, assignment of interests in production sharing contracts is subject to the Ministry of Hydrocarbons’ consent and to the State’s preemption rights. Foreign companies carrying out production activities under the form of a local branch must incorporate a local company within two years of the entry into force of the Hydrocarbons Law under its Article 254.

With respect to natural gas, the State shall enjoy exclusive marketing rights for non-associated gas while any non-commercial share of associated natural gas remains the property of the State.

Hydrocarbons agreements entered into prior to the Hydrocarbon Law’s publication remain in force until their expiration and should continue to be governed by their own provisions. Our understanding is that the Hydrocarbons Law applies to any issues not expressly dealt with in these contracts’ provisions.

Our production sharing contract governing our rights to the Etame Marin block offshore Gabon was entered into before the publication of the Hydrocarbon Law. The PSC contains a stabilization clause, which provides for the stability of the legal, tax, economic and financial conditions in force at the signing of the PSC. Pursuant to the PSC, these conditions may not be adversely altered during the term of the agreement; however, we can make no assurance that the interpretation of the Hydrocarbon Law will not adversely affect our operations or assets in Gabon.

As discussed in “— Segment and Geographic Information—Gabon Segment—Offshore – Etame Marin Block—Production,” production from the Etame block is stored in an FPSO which we lease from a third party.  Over the past 15 years, this vessel was imported under a temporary import license issued to us.  Customs officials have advised us that the temporary import license cannot be renewed and that the owner of the FPSO,  Tinworth Pte. Limited, an affiliate of BW Offshore Limited, needs to obtain a permanent import license in order to continue operating in Gabon.  We are working to find other forms of relief.  Should these other efforts fail and the vessel owner does not obtain the permanent import license, this could result in customs fines and penalties being owed by the

vessel owner. We are also working with the owner to ensure that they meet the requirements to obtain the permanent import license.  In connection with this regulatory matter, the Gabon government could take actions which would impede the operations of the FPSO if this is not resolved.  This matter could have an adverse impact on our financial position, results of operations or cash flows.

ENVIRONMENTAL REGULATIONS

General

Our operations are subject to various federal, state, local and international laws and regulations, including laws and regulations in Gabon and Equatorial Guinea, governing the discharge of materials into the environment or otherwise relating to environmental protection or pollution control subject to the laws and regulations of Equatorial Guinea if exploration drilling occurs in that country.control. The cost of compliance could be significant. FailureWhile we are currently complying with and are in good standing with all environmental laws and regulations, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or for conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the crude oil and natural gas industry in general, our business and financial results could be adversely affected. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict, however, what effect future environmental regulation or legislation, enforcement policies, andor claims for damages to property, employees, other persons, and the environment resulting from our operationsor natural resources could have on our activities.us.

In addition, a number of governmental bodies have adopted, have introduced or are contemplating regulatory changes in response to various climate change non-governmental organizations and the potential impact of climate change.change and to the lobbying effects of various climate change non-governmental organizations. Legislation and increased regulation regarding climate change could impose significant costs on us, our joint venture partners,owners, and our suppliers, including costs related to increased energy requirements, capital equipment, environmental monitoring and reporting, and other costs to comply with such regulations. For example, in April 2016, 195 nations, including Gabon, Equatorial Guinea and the United States, signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls for signatory countries to set their own greenhouse gas emissions targets, make these emissions targets more stringent over time and be transparent about the greenhouse gas emissions reporting and the measures each country will use to achieve its greenhouse gas targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. The Paris Agreement is effectively a successor agreement to the Kyoto Protocol treaty, an international treaty aimed at reducing emissions of greenhouse gases, to which various countries and regions are parties. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which took effect on February 19, 2021 and on April 22, 2021, President Biden announced a target for the US to achieve a 50-52 percent reduction from 2005 levels in economy-wide GHG emissions by 2030. Given the political significance and uncertainty around the impact of climate change and how it should be dealt with, we cannot predict how legislation and regulation, including the Paris Agreement and any related greenhouse gas emissions targets, potential prices on carbon emissions, regulations or other requirements, will affect our financial condition and operating performance. In addition, increased awareness and any adverse publicity in the global marketplace about potential impacts on climate change by us or other companies in our industry could harm our reputation or impact the marketability of our product.crude oil and natural gas. The potential physical impacts of climate change on our operations are highly uncertain and would be particular to the geographic circumstances in areas in which we operate. These may include changes in rainfall and storm patterns and intensities, water shortages, changing sea levels, and changing temperatures. These impacts may adversely impact the cost, production, and financial performance of our operations.

In part because they are developing countries, it is unclear how quickly and to what extent Gabon or Equatorial Guinea will increase their regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon or Equatorial Guinea could have a material effect on us. Developing countries, in certain instances, have patterned environmental laws after those in the U.S., which are discussed below. However, the extent to whichthat any environmental laws are enforced in developing countries varies significantly.

With regards to our development operations offshore West Africa, we are a member of Oil Spill Response Limited (OSRL)(“OSRL”), a global emergency and crude oil spill-response organization headquartered in London. OSRL has aircraft and equipment available for dispersant application or equipment transport, including active recoveryvarious boom systems and other booms that can be used for offshore orand shoreline responses.recovery operations. In addition, OSRL can provide communications equipment, safety equipment, transfer pumps, dispersant application systems, temporary storage equipment, generators, boats and vessels and oiled wildlife equipment. 

VAALCO has a Tier 1 spill kit in-country for immediate deployment if required. See “Item 1A “1A.Risk Factors” for further discussion on the impact of these and other regulations relating to environmental protection.

Environmental Regulations in the United States

Currently, we conduct no operations in the U.S. and have only inconsequential interests in two U.S. properties.  However, our prior operations in the U.S., and any future operations we may conduct in the U.S., may subject us to certain liabilities under U.S. federal, state and local environmental regulations.  In the U.S., environmental laws and regulations are administered by the U.S. Environmental Protection Agency (“EPA”) and counterpart state agencies in the various states where operations are conducted. 

These U.S. laws and regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law.

Some of our prior operations on U.S. onshore properties involved hydraulic fracturing activities associated with drilling in shale formations. Hydraulic fracturing has been increasingly the subject of significant focus among many non-governmental organizations

and regulators. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of both water supply sources and disposal methods.

Superfund

We have previously owned or leased properties in the U.S. used for the exploration and production of oil and natural gas. Although we may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for disposal.  In addition, some of these properties are or have been operated by third parties. We have no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We could, in the future, be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination or mitigate existing contamination.

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action.

Although CERCLA generally exempts “petroleum” from the definition of a Hazardous Substance, in the course of our prior U.S. operations, we may have generated substances that may fall within CERCLA’s definition of a “Hazardous Substance” and may have disposed of these substances at disposal sites owned and operated by others. Also, properties that we own and properties that we may have owned or operated may have been sites on which Hazardous Substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of its properties that are named as PRPs related to their ownership or operation of such properties. States such as Texas have comparable statutes which may cover substances (including petroleum) in addition to those covered under CERCLA. In the event contamination is discovered at a site on which we have been an owner or operator or to which we sent regulated substances, we could be liable for costs of investigation and remediation and damages to natural resources.

The Oil Pollution Act of 1990

The Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act (“CWA”)  imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening U.S. waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill.

Other Environmental Regulation in the U.S.

In the past, we may have generated wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes which may limit disposal options.  Although most oil and natural gas wastes are exempt from regulation as a hazardous waste under RCRA at the federal level, not all comparable state statutes may have provided the same exemption, and certain wastes that we previously generated may have been subject to RCRA or comparable state statutes.

The CWA and analogous state laws impose restrictions and strict controls regarding the discharge (including spills and leaks) of pollutants, including produced waters and other oil and natural gas wastes as well as fill materials, into state waters and waters of the U.S., a term broadly defined but which remains subject to litigation and rulemaking over the scope of related waters. 

The Clear Air Act and analogous state laws govern emissions from sources of air pollution. These laws may require new and modified sources of air pollutants to obtain permits prior to commencing construction and may require the installation of stringent control methods.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. A critical habitat or suitable habitat designation by the U.S. Fish and Wildlife Service could also result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.

Most environmental programs provide for fines, penalties and injunctive relief for violations of their requirements. Some programs additionally provide for citizen suits, which allow a private citizen to sue to enforce the requirements of the applicable regulatory program.

Item 1A. Risk Factors

Our business faces many risks. You should carefully consider the following risk factors in addition to the other information included in this report.Annual Report. If any of these risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected. Any risks discussed elsewhere in this Form 10-KAnnual Report and in our other SEC filings could also have a material impact on our business, financial position or results of operations. Additional risks not presently known to us or whichthat we consider immaterial based on information currently available to us may also materially adversely affect us.

OilRisks Related to Our Business, Operations and natural gas pricesStrategy

Events outside of our control, such as the ongoing COVID-19 pandemic,could adversely impact our business, results of operations, cash flows, financial condition and liquidity.

We face risks related to epidemics, outbreaks or other public health events that are highly volatile,outside of our control. The global or national outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could significantly disrupt our business and a return to a very depressed price regime for a prolonged period of time will negativelyoperational plans and adversely affect our financial results.

Our revenues, cash flow, profitability, oil and natural gas reserves value and future rateresults of growth are substantially dependent upon prevailing prices for oil and natural gas. Our ability to borrow funds and to obtain additional capital on reasonable terms is also substantially dependent on oil and natural gas prices. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas declined dramatically in the second half of 2014 and decreased further in 2015 and early 2016. During 2015, based on New York Mercantile Exchange (“NYMEX”) pricing, the spot price per Bbl of Brent crude oil ranged from a high of $66 to a low of $35. During 2016,  the spot price per Bbl of Brent crude oil ranged from a high of $55 to a low of $26. During 2017,  the spot price per Bbl of Brent crude oil ranged from a high of $67 to a low of $44.

As a result of the low oil and natural gas prices since 2014, our revenues, operating income,operations, cash flows, financial condition and borrowing capacity have been materially and adversely affected and have required reductions in the carrying value of our oil and natural gas properties and our planned level of capital expenditures. The average price at which we sold our crude oil in 2017 was $52.58 per Bbl compared to $40.13 per Bbl in 2016 and $47.85 per Bbl in 2015. Because the oil priceliquidity. Although we are requirednot able to use byenumerate all potential risks to our business resulting from the SEC to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of increasing or falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if oil and natural gas prices increase.