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Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts. The unaudited pro forma net income for the year ended December 31, 2022 excludes $14.6 million of transaction costs incurred by VAALCO associated with the Arrangement, excludes the bargain purchase gain of $10.8 million and reclassifies interest expense, for certain leases identified as operating leases, as production expense. The unaudited pro forma net income for the year ended December 31, 2021 includes $21.1 million of transaction costs incurred by VAALCO and TransGlobe associated with the Arrangement, includes the bargain purchase gain of $10.8 million and reclassifies interest expense, for certain leases identified as operating leases, as production expense. Includes assets acquired in the TransGlobe acquisition The unaudited pro forma net income for the year ended December 31, 2021 excludes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $7.7 million and transaction costs of $1.0 million. Represents depreciation and interest associated with financing leases. The unaudited pro forma net revenues associated with Crude oil, natural gas and natural gas liquids sales have been adjusted for shipping and handling costs based on the Company’s historical policy and revenue recognition is based on the Company’s working interest, less royalties, the entitlement method. Includes assets acquired in the Sasol acquisition Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded. The unaudited pro forma operating income for the year ended December 31, 2021 removes the $31.5 million impairment reversal recorded by TransGlobe in 2021, adjusts costs associated with overlifts to reduce revenue, includes $10.2 million of severance costs associated with the Arrangement, reclassifies depreciation expense, for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the Arrangement based on the purchase price allocation (the impairment reversal was allowable under IFRS by TransGlobe in 2021). The Measurement Period Adjustment is due to an original deferred tax liability being estimated at closing. Additional information about the deferred tax liability was identified in the first part of 2023 creating the need for the $1.4 million adjustment. 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Table of Contents



 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

(Mark One)

  

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

OR

  

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to  

 

Commission file number: 1-32167


VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)


Delaware

76-0274813

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

9800 Richmond Avenue

Suite 700

Houston, Texas 77042

(Address of principal executive offices) (Zip Code)

 

(Registrants telephone number, including area code): (713) 623-0801

 

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

   

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.10

EGY

New York Stock Exchange

Common Stock, par value $0.10

EGY

London Stock Exchange

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


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

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

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 ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).  Yes ☒  No ☐

 

 

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.

    

Large accelerated filer ☐

Accelerated filer

Non-accelerated filer ☐

Smaller reporting company 

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

As of June 30, 2023, the aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates was approximately $396.6 million based on a closing price of $3.76 on June 30, 2023.

As of March 8, 2024, there were outstanding 103,274,173 shares of common stock, $0.10 par value per share, of the registrant.

Documents incorporated by reference: Portions of the definitive Proxy Statement of VAALCO Energy, Inc. relating to the Annual Meeting of Stockholders to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, which are incorporated into Part III of this Form 10-K.



 

 

 

 

VAALCO ENERGY, INC.

TABLE OF CONTENTS

 

 

Page

Glossary of Certain Crude Oil, Natural Gas and Natural Gas Liquids Terms

3  

PART I

8  

Item 1. Business

8  

Item 1A. Risk Factors

27  

Item 1B. Unresolved Staff Comments

44  
Item 1C. Cybersecurity 44  

Item 2. Properties

45  

Item 3. Legal Proceedings

46  

Item 4. Mine Safety Disclosures

46  

PART II

46  

Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

46  

Item 6. Reserved

48  

Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations

48  

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

61  

Item 8. Consolidated Financial Statements and Supplementary Data

62  

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

62  

Item 9A. Controls and Procedures

62  

Item 9B. Other Information

63  

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

64  

PART III

64  

Item 10. Directors, Executive Officers and Corporate Governance

64  

Item 11. Executive Compensation

64  

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

64  

Item 13. Certain Relationships and Related Transactions, and Director Independence

64  

Item 14. Principal Accountant Fees and Services

64  

PART IV

65  

Item 15. Exhibits and Financial Statement Schedules

65  

INDEX TO CONSOLIDATED FINANCIAL INFORMATION

65  

Item 16. Form 10-K Summary

67  
 

 

2

 

 

Glossary of Certain Crude Oil, Natural Gas and Natural Gas Liquid ("NGL") Terms

 

 

 

Terms used to describe quantities of crude oil, natural gas and NGLs

 

 

Bbl — One stock tank barrel, or 42 United States (“U.S.”) gallons liquid volume, of crude oil or other liquid hydrocarbons.

  Bbl/d — Barrels per day
  Bcf — One billion cubic feet
  Boe — Barrel of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
  BOEPD — One Boe per day
 

BOPD — One Bbl per day.

  Km2 — Square Kilometers
  M3 — Cubic Meters
 

MBbl — One thousand Bbls.

  MMBbl — One million Bbls
  MBoe — One thousand Boes.
  MMBoe — One million Boes.
 

MBopd — One thousand Bbls per day.

  MBOEPD – One thousand Boes per day.
  MCF — One thousand cubic feet.
  MCFD — One thousand cubic feet per day.
  MMBTU – One million British Thermal Units.
  MMcf — One million cubic feet.
  NGLs — Natural Gas Liquids.
  NRI — working interest volumes less royalty volumes, where applicable.
  WI — working interest volumes.

 

Terms used to describe legal ownership of crude oil, natural gas and NGLs properties, and other terms applicable to our operations

 

 

 Arta — The Arta field in the West Gharib concession in the Egyptian Eastern Desert.

 

BWE Consortium — A consortium of the Company, BW Energy and Panoro Energy provisionally awarded two blocks, G12-13 and H12-13, in the 12th Offshore Licensing Round in Gabon.

 

C$ — means Canadian dollars.

 

Cardium — The Cardium formation that spans a large area from southwest Alberta to northeast British Columbia, with the producing area concentrated along the eastern slopes of the Rocky Mountains to the northwest of Calgary.

 

Carried interest — Working Interest (as defined below) where the carried interest owner’s share of costs is paid by the non-carried working interest owners. The carried costs are repaid to the non-carried working interest owners from the revenues of the carried working interest owner.

 

Crown Royalty — The payments to be made to the Province of Alberta pursuant to the Alberta Crown Agreement or under the generic crown royalty scheme.

 

EGPC — Egyptian General Petroleum Corporation. 

 

Egypt — Arab Republic of Egypt.

 

Gabon — Republic of Gabon.

 

Etame Consortium A consortium of four companies granted rights and obligations in the Etame Marin block offshore Gabon under the Etame PSC.

  Merged Concession — The modernized concession that merged the West Bakr, West Gharib and NW Gharib concessions.
  Merged Concession Agreement — The agreement with EGPC for the Merged Concession signed by the Ministry of Petroleum at an official signing ceremony on January 19, 2022.
 

PSC A production sharing contract.

 

FPSO A floating, production, storage and offloading vessel.

 

FSO – A floating storage and offloading vessel.

  NW Gharib — The North West Gharib Concession area in Egypt.
  NW Sitra — The North West Sitra Concession area in Egypt.

 

3

 

 

Participating Interest — Working Interest (as defined below) attributable to a non-carried interest owner adjusted to include its relative share of the benefits and obligations attributable to carried working interest owners.

    RBL — Reserved based lending facility 
 

Royalty interest — A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of crude oil and, natural gas and NGLs production or, if the conveyance creating the interest provides, a specific portion of crude oil and, natural gas and NGLs produced, without any deduction for the costs to explore for, develop or produce the crude oil and, natural gas and NGLs.
  South Alamain — The South Alamain Concession area in Egypt.
  West Bakr — The West Bakr Concession area in Egypt.
  West Gharib — The West Gharib Concession area in Egypt.
 

Working Interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of crude oil, natural gas and NGLs production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such crude oil, natural gas and NGLs. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

  $ — means U.S. dollars.
  Yusr — The Yusr reservoirs in the West Bakr concession in the Egyptian Eastern Desert.

 

Terms used to describe interests in wells and acreage

 

 

Gross crude oil and, natural gas and NGLs wells or acres — Gross wells or gross acres represent the total number of wells or acres in which a working interest is owned, before consideration of the ownership percentage.
 

Net crude oil and, natural gas and NGLs wells or acres — Determined by multiplying “gross” wells or acres by the owned working interest.

 

Terms used to classify reserve quantities

 

 

Proved developed crude oil and, natural gas and NGLs reserves — Developed crude oil and, natural gas and NGLs reserves are reserves of any category that can be expected to be recovered:
 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved crude oil and, natural gas and NGLs reserves — Proved crude oil and, natural gas and NGLs reserves are those quantities of crude oil and, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs, and under existing economic conditions, 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.
 

(i) The area of the reservoir considered as proved includes:

 

(A) The area identified by drilling and limited by fluid contacts, if any, and

 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis of available geoscience and engineering data.

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii) Where direct observation from well penetrations has defined a highest known crude oil (HKO) elevation and the potential exists for an associated natural gas cap, proved crude oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv) Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection), are included in the proved classification when:

 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first day of the month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Reserves — Reserves are estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas, NGLs or related substances to market, and all permits and financing required to implement the project.

 

4

 

 

Proved undeveloped crude oil and, natural gas reserve and NGLs reserves, PUDs — Proved undeveloped crude oil and, natural gas and NGLs reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii) Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

Unproved properties — Properties with no proved reserves.

 

Terms used to assign a present value to reserves

 

 

Standardized measure — The standardized measure of discounted future net cash flows (“standardized measure”) is the present value, discounted at an annual rate of 10%, of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”), using the 12-month unweighted average of first-day-of-the-month Brent prices adjusted for historical marketing 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

 

 

Seismic data — crude oil, natural gas and NGLs companies use seismic data as their principal source of information to locate crude oil, natural gas and NGLs 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, natural gas and NGLs reservoirs in the area evaluated.

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual 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 Annual Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

 

 

volatility of, and declines and weaknesses in crude oil and, natural gas and NGLs prices, as well as our ability to offset volatility in prices through the use of hedging transactions;
 

the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves;

 

impairments in the value of our crude oil, natural gas and NGLs assets;

 

future capital requirements;

 

our ability to maintain sufficient liquidity in order to fully implement our business plan;

 

our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;

 

the ability of the BWE Consortium to successfully execute its business plan;

 

our ability to attract capital or obtain debt financing arrangements;

 

our ability to pay the expenditures required in order to develop certain of our properties;

 

operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs;
 

difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs;

 

5

 

 

the impact of competition;

 

our ability to identify and complete complementary opportunistic acquisitions;

 

our ability to effectively integrate assets and properties that we acquire into our operations;

 

weather conditions;

 

the uncertainty of estimates of crude oil, natural gas reserves and NGLs;

 

currency exchange rates and regulations;

 

unanticipated issues and liabilities arising from non-compliance with environmental regulations;

 

the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;

  the ultimate resolution of our negotiations with EGPC relating to the Effective Date Adjustment (as defined below);
 

the availability and cost of seismic, drilling and other equipment;

 

difficulties encountered in measuring, transporting and delivering crude oil, natural gas, and NGLs to commercial markets;

 

timing and amount of future production of crude oil and, natural gas and NGLs;
 

hedging decisions, including whether or not to enter into derivative financial instruments;

 

general economic conditions, including any future economic downturn, the impact of inflation, disruption in financial of credit;

 

our ability to enter into new customer contracts;

 

changes in customer demand and producers’ supply;

 

actions by the governments of and events occurring in the countries in which we operate;

 

actions by our joint venture owners;

 

compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;

 

the outcome of any governmental audit; and

 

actions of operators of our crude oil and, natural gas and NGLs properties.

 

The information contained in this Annual Report, including the information set forth under the heading “Item 1A. Risk Factors,” identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Annual Report, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Annual Report.

 

Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified by this “Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Annual Report.

 

Risk Factor Summary 

 

Below is a summary of our risk factors. The risks below are those that we believe are the material risks that we currently face but are not the only risks facing us and our business. If any of these risks actually occur, our business, financial condition and results of operations could be materially adversely affected. See “Risk Factors” beginning on page 27 and the other information included elsewhere or incorporated by reference in this annual report for a discussion of factors you should carefully consider before deciding to invest in our common stock.

 

 

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.

 

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 in which we have an interest.

 

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

 

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.

 

6

 

 

The proposed acquisition of Svenska (as defined below) may not be consummated and if consummated, we may not realize the anticipated benefits expected from the acquisition.
 

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/decommissioning costs are too low, we could be required to expend greater amounts than expected.

  We may not generate sufficient cash to satisfy our payment obligations under the Merged Concession Agreement or be able to collect some or all of our receivables from the EGPC, which could negatively affect our operating results and financial condition.
  The Egyptian PSCs contain assignment provisions which, if triggered or deemed to be triggered, could adversely affect our business.
 

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

 

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

  We are exposed to the credit risks of the third parties with whom we contract.
 

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

  Current and future geopolitical events outside of our control could adversely impact our business, results of operations, cash flows, financial condition and liquidity.
 

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.

 

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

  Inflation could adversely impact our ability to control costs, including operating expenses and capital costs.
 

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

 

We operate in international jurisdictions, and we could be adversely affected by violations of the U.S. 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.

  We may be exposed to the risk of earthquakes in Alberta, Canada.
  We may be adversely affected by changes in currency regulations.
  We may be adversely affected by changes to interest rates.
  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.
  There may be valid challenges to title or legislative changes which affect our title to the oil, natural gas and NGLs properties we control in Canada.
 

Crude oil, natural gas and NGLs 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.
 

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

Weather, unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our crude oil, natural gas and NGLs activities, including but not limited to, earthquakes in Alberta and risks related to hydraulic fracking.

 

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 opposition to and activism against crude oil, natural gas and NGLs exploration and development activities.

  Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our product.
 

Compliance with applicable laws, environmental and other government regulations could be costly and could negatively impact production.

  A significant level of indebtedness incurred under the Facility may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities in the future. In addition, the covenants in the Facility impose
restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of any future outstanding indebtedness under the Facility.
  If we experience in the future a continued period of low commodity prices, our ability to comply with applicable debt covenants may be impacted.
  The borrowing base under the Facility may be reduced pursuant to the terms of the Facility Agreement, which may limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.
  Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

 

7

 

 

 

PART I

Item 1. Business

 

OVERVIEW

 

As used in this Annual Report, the terms, “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-based, African-focused independent energy company with strong production and reserve portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada, currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

 

We own a working interest in, and are the operator of, the Etame PSC related to the Etame Marin block located offshore Gabon in West Africa. The Etame Marin block covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet. Currently, our working interest in the Etame Marin block is 58.8%, and we are designated as the operator on behalf of the Etame Consortium. The block is subject to a 7.5% back-in carried interest by the government of Gabon, which they have assigned to a third party. Our working interest will decrease to 57.2% in June 2026 when the back-in carried interest increases to 10%.

 

We are also a member of a consortium with BW Energy and Panoro Energy (the “BWE Consortium”). The BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. Negotiations to finalize the commercial terms were held in 2023, however they were halted late in the year due to the presidential elections.  The negotiations were started again at the request of the Gabonese Government in early February 2024, where the consortium and the government came to an agreement on the fiscal terms on February 9, 2024. The next step is concluding the terms of PSCs with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13 are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

 

As a result of the business combination transaction with TransGlobe Energy Corporation (“TransGlobe”) in 2022 (the “Arrangement”), we own a 100% working interest in PSCs covering two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions (45,067 acres) and the Western Desert which contains the South Ghazalat concession (7,340 acres).  We also acquired TransGlobe’s production and working interests in Cardium light oil and Mannville liquids-rich gas assets located in Harmattan, Canada (47,400 gross acers developed).

 

On February 29, 2024, VAALCO Energy (Holdings), LLC (“Buyer”), a Delaware limited liability company and wholly-owned subsidiary of us, and Petroswede AB, a company incorporated in Sweden (“Seller”), entered into a Share Purchase Agreement (the “Share Purchase Agreement”) pursuant to which the Buyer will purchase all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for $66.5 million in cash (the “Purchase Price”), subject to adjustment as described in the Share Purchase Agreement. Pursuant to the terms and subject to the conditions of the Share Purchase Agreement, upon closing of the Acquisition (the “Closing”), Buyer will acquire Svenska and, as a result, Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. Buyer will also acquire a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.  The Purchase Price will be funded by a combination of a dividend of cash on Svenska’s balance sheet to the Seller immediately prior to the consummation of the Acquisition and a portion of VAALCO’s cash-on-hand. VAALCO estimates that cash due from VAALCO at Closing will be in the range of approximately $30 to $40 million.

 

At December 31, 2023, net proved reserves related to Gabon were 9.1 MBoe, net proved reserves related to Egypt were 10.6 MBoe and net proved reserves related to Canada were 9.0 MBoe.

 

We also currently own an interest in an undeveloped block offshore Equatorial Guinea, West Africa.

 

STRATEGY 

 

We own crude oil, natural gas and NGLs producing properties and conduct operating activities in Egypt, Canada, and offshore Gabon, with a focus on maximizing the value of our current resources and expanding into new development opportunities across Africa. Our financial results are heavily dependent upon the margins between prices received for our crude oil, natural gas and NGLs production and the costs to find and produce such crude oil, natural gas and NGLs.

 

We intend to increase stockholder value by accretively growing production and value through organic drilling in a capital efficient manner to unlock the inherent value of our assets and making disciplined strategic acquisitions that meet our strategic and financial objectives. Specifically, we seek to:

 

 

Focus on maintaining production and lowering costs to increase margins and preserve optionality to capitalize on an increase in crude oil, natural gas and NGLs prices;
 

Manage capital expenditures related to our drilling programs so that expenditures can be funded 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 wells and infrastructure;

 

Maximize our cash flow and income generation;

 

Continue planning for additional development at Etame, Egypt, and Canada as well as future 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, natural gas or NGLs prices; and
 

Actively pursue strategic, value-accretive mergers and acquisitions of similar properties to diversify our portfolio of producing assets.

 

8

 

We believe that we have strong management and technical expertise specific to the markets in which we operate, and that our strengths include:
 

 

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

 

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 broader regional framework of discoveries and fields;

 

Our operational capacity to take on new development projects;

 

Our familiarity with local practices and infrastructure; and

 

Our market intelligence to provide early insight into available opportunities.

 

SEGMENT AND GEOGRAPHIC INFORMATION

 

For operating segment and geographic financial information, see Note 5 to the Consolidated Financial Statements. Our reportable operating segments are Gabon, Egypt, Canada and Equatorial Guinea.

 

Gabon Segment

 

Offshore Etame Marin Block

 

The Etame PSC related to the Etame Marin block is located offshore Gabon. The Etame Marin block covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet. Currently, our working interest in the Etame Marin block is 58.8%, and we are designated as the operator on behalf of the Etame Consortium. The block is subject to a 7.5% back-in carried interest by the government of Gabon, which they have assigned to a third party. Our working interest will decrease to 57.2% in June 2026 when the back-in carried interest increases to 10%. The terms of the Etame PSC include provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of “Profit Oil” determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. The term of the Etame PSC with Gabon related to the Etame Marin block located offshore Gabon extends 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 identified at Etame. Prior to February 1, 2018, the government of Gabon did not take any of its share of Profit Oil in-kind. Beginning February 1, 2018, the government of Gabon elected to, and has continued to, take its Profit Oil in-kind. 

 

As of December 31, 2023, our core areas in Gabon are illustrated below:

 

gabonetamemarinlicenseareama.jpg

 

 
 
9

 

Egypt Segment

 

In Egypt, as of December 31, 2023, our interests are spread across two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions, and the Western Desert, which contains the South Ghazalat concession. The Eastern Desert merged concession is approximately 45,067 acres and the Western Desert, South Ghazalat concession, is approximately 7,340 acres. Both of our Egyptian blocks are PSCs with the Egyptian General Petroleum Corporation (“EGPC”), the Egyptian government and VAALCO. We have an equal ownership interest, with EGPC owning the other portion, in the joint venture that has a 100% working interest in both PSCs. Our oil entitlement is the sum of cost oil, profit oil and excess cost oil, if any. The government takes their share of production based on the terms and conditions of the respective contracts. Our share of royalties is paid out of the government's share of production. Taxes are captured in the Egyptian government's net entitlement oil due and therefore there is no additional tax burden to us. 

 

On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024  payment and issue two $10.0 million credits against receivables owed from EGPC. We will make two further annual modernization payments of $10.0 million each beginning February 1, 2025 until February 1, 2026. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date"). As of December 31, 2023, the $50 million of financial work commitments had been delivered to EGPC. As the Merger Concession Agreement is effective as of February 1, 2020, there will be an effective date adjustment owed to us for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date. The cumulative amount of the effective date adjustment was estimated at $67.5 million. However, the cumulative amount to be received as a result of the effective date adjustment is currently being finalized with EGPC and could result in a range of outcomes based on the final price per barrel negotiated. At December 31, 2023, we had received $17.2 million of the receivable and the remaining $50.3 million is recorded on our consolidated balance sheet in Receivables-Other, net. 

 

The Egyptian PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs. Each PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production less cost oil) is shared between the government and the contractor as defined in the specific PSC. The Egyptian PSCs do not contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the contractor's sales volumes. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

 

The following illustrates our Merged Concession in the Eastern Desert:

 

egyptconcessionmapeasterndes.jpg
 
10

 

The following illustrates our concession, South Ghazalat, in the Western Desert:

 

egyptconcessionwest.jpg
 
11

 

Canada Segment

 

In Harmattan, Canada, we own production and working interests in Cardium light oil and Mannville liquids-rich gas assets. Harmattan is located approximately 80 kilometers north of Calgary, Alberta. This property produces oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to 2,600 meters. The Harmattan property covers 47,400 gross acres of developed land and 28,700 gross acres of undeveloped land. We also own a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are handled. All gas is delivered to a third party non-operated gas plant for processing.

 

Under the Modernized Royalty Framework (the “MRF”) in Alberta, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable drilling and completion cost allowance. After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%. The MRF applies to the hydrocarbons produced by wells spud or re-entered on or after January 1, 2017. The Royalty Guarantee Act (Alberta) came into effect in July 2019, amending the Mines and Minerals Act (Alberta) and guaranteeing no major changes to the oil and gas royalty structure for a period of 10 years.

 

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner. The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.

 

Below is an illustration of our Canadian assets:

 

canadadevelopmentleasemap.jpg

 

 

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Equatorial Guinea Segment

 

We acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The 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 commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify our 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 assigned the defaulting party’s interest to the non defaulting parties. As a result, our working interest increased to 45.9% with the approval of a fourth amendment to the production sharing contract by the EG MMH. On July 15, 2022, VAALCO, on behalf of itself and Guinea Ecuatorial de Petroleós (“GEPetrol”), submitted to the EG MMH a plan of development for the Venus development in Block P. On September 26, 2022, the EG MMH approved the submitted plan of development. Final documents to effect the plan of development are subject to EG MMH approval. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and was approved effective November 16, 2022. 
 

In February of 2023, we acquired an additional 14.1% participating interest, increasing our participating interest in the Block to 60.0%. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus development plan has been initiated. This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.80 million at first commercial production of the Block. The Third  Amendment to the Joint Operating Agreement (“JOA”) was approved by GEPetrol and Atlas on Feb 18, 2024 and was further approved by the MMH on Feb 27, 2024. With the approval of the JOA, the work could commence on the engineering for the Venus Development to enable a Final Investment Decision (“FID”) on the Venus Development. 

 

As of December 31, 2023, our Block P license in Equatorial Guinea is illustrated below:

 

eqguinealicenseareamap.jpg

 

 
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DRILLING ACTIVITY

 

In Gabon, we commenced the  2021/2022 drilling campaign in December 2021. The following table sets forth the total number of completed exploratory and development wells in 2023, 2022 and 2021 on a gross and net basis:

 

   

Gabon

 
   

Gross

   

Net

 
   

2023

   

2022

   

2021

   

2023

   

2022

   

2021

 

Exploratory wells

                                   

Productive

                       

Dry

                       

In progress

                       

Development wells

                                   

Productive

      4             2.4      

Dry

                       

In progress

 

        1    

        0.6  

Total wells

      4     1         2.4     0.6  

 

In December 2021, we began drilling the ETAME 8H-ST development well that was completed in February 2022. In 2022, we completed the Etame 8H-ST, North Tchibala 2H-ST, South Tchibala-1HB-ST2 and Avouma 3H-ST development wells. 

 

The following table sets forth the total number of exploratory and development wells from the TransGlobe acquisition date in 2022 and 2023 in Egypt on a gross and net basis:

 

   

Egypt

 
   

Gross

   

Net

 
   

2023

   

2022

   

2023

   

2022

 

Exploratory wells

                               

Productive

                       

Dry

    2       2       2       2  

In progress

                       

Development wells

                               

Productive

    16       2       16       2  

Dry

                       

In progress

          1             1  

Total wells

    18       5       18       5  

 

The 18 wells drilled in 2023 along with the spud date for each were the EastArta-53 - January 15, 2023, the K-81 - February 2, 2023, the K-79 - February 21, 2023, the Arta-80 - March 10, 2023, the Arta-81 - March 21, 2023, the HE-5 Injector - April 16, 2023, the HE-3 - May 10, 2023, the Arta-82 - May 25, 2023, the Arta-84 - June 6, 2023, the NEG-5C1 - June 16, 2023, the K-80 - June 30, 2023, the K-84 - July 16, 2023, the K-85 - July 31, 2023, the M-24 - August 14, 2023, the Arta-91 - September 1, 2023, the EA-54 - September 12, 2023 and the EA-55 - October 4, 2023.  The two dry hole wells were the NWG-SC1 and the EA-54 which were abandoned during 2023.

The wells drilled in 2022 included the M-17 Development well which was spud on September 28, 2022 and rig released on October 17, 2022, the NWG-2INJ-1A planned as injector well but encountered oil and came online December 23, 2022 and the Arta-77Hz well in progress which came online in the first quarter of 2023.
 

The following table sets forth the total number of exploratory and development wells from the TransGlobe acquisition date in 2022 and all of 2023 in Canada on a gross and net basis:
 

   

Canada

 
   

Gross

   

Net

 
   

2023

   

2022

   

2023

   

2022

 

Exploratory wells

                               

Productive

                       

Dry

                       

In progress

                       

Development wells

                               

Productive

    2       3       2       3  

Dry

                       

In progress

                       

Total wells

    2       3       2       3  

 

The two wells drilled in 2023 were the 12-12-030-04W5/0 and the 16-30-029-03W5/0 with a spud date of January 28, 2023 and February 22, 2023, respectively.

The three wells drilled in 2022 were the 4-10-29-3W5, the 4-18-29-3W5 and the 4-24-29-4W5 well with a spud date of July 4, 2022, June 11, 2022 and June 23, 2022, respectively. 

 

14

 

ACREAGE AND PRODUCTIVE WELLS  

 

Below is the total acreage under lease or covered by the Etame PSC, Egypt PSCs, Canada PSCs and Block P and the total number of productive crude oil, natural gas and NGLs wells as of December 31, 2023:

 

   

Developed

   

Undeveloped(2)

   

Total

 

Acreage in thousands

 

Gross

     

Net

   

Gross

   

Net

   

Gross

   

Net

 

Gabon

    6.9         4.1       39.4       23.1       46.3       27.2  

Canada

    47.4         41.7       28.7       25.3       76.1       67.0  

Egypt

    29.2         29.2       23.3       23.3       52.5       52.5  

Equatorial Guinea

                  57.3       26.3       57.3       26.3  

Total acreage

    83.5         75.0       148.7       97.9       232.2       173.0  
                                                   

Productive crude oil wells

 

Gross

     

Net

                                 

Gabon

    15  

(1)

    8.8                                  

Canada

    63         59.5                                  

Egypt

    123         123.0                                  

Total Productive crude oil wells

    201         191.3                                  
                                                   

Productive natural gas wells

  Gross       Net                                  

Gabon

                                             

Canada

    40         37.6                                  

Egypt

                                             

Total productive natural gas wells

    40         37.6                                  

(1)  Excludes three wells shut-in due to the presence of high levels of H2S.

(2)  The expiration dates for undeveloped acreage associated with each region is as follows:

a. For Gabon the undeveloped acres expire at the end of the license contract; currently 2028 with two five-year options to extend the license contract.

b. For Egypt the undeveloped acres expire at the end of the license contracts; currently 2035 with one five-year option to extend the license contract for the West Gharib, West Bakr and North West Gharib areas and 2039 with one 5 year extension for South Ghazlat area.

c. For Canada the undeveloped acres are generally held by production by areas that are producing reserves. At December 31, 2023 approximately 82% of Canada’s net undeveloped acreage has no expiration risk. Approximately 4.3 acres have risk of expiration from 2024 through 2027.

 

 

RESERVE INFORMATION 

 

Estimated Reserves and Estimated Future Net Revenues

 

Reserve Data

 

In accordance with the current SEC guidelines, estimates of future net cash flow from our properties and the present value thereof are made using the average of the first-day-of-the-month price for each of the twelve 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 2023, the average of such prices used for our reserve estimate was $83.22 per Bbl for crude oil for Gabon. Prices were $64.59 per Bbl for crude oil from Egypt and $71.67 per Bbl for crude oil from Canada. For 2022, the average of such prices used for our reserve estimates was $100.35 per Bbl for crude oil from Gabon. Prices were between $84.76 and $85.65 per Bbl for crude oil from Egypt and $89.61 per Bbl for crude oil from Canada. For Gabon, this compares to the average of such price used for 2021 of $69.10 per Bbl.

 

For 2023, the adjusted average price for our reserves associated with natural gas was $1.91 per MCF, $5.20 per Bbl for Ethane, $20.18 per Bbl for propane, $36.69 per Bbl for butane and $74.76 per Bbl for condensates. For 2022, the adjusted average price for our reserves associated with natural gas was $4.13 per MCF, $12.77 per Bbl for Ethane, $40.27 per Bbl for propane, $43.85 per Bbl for butane and $91.57 per Bbl for condensates.

 

15

 

Reserves reported below consist of net proved reserves related to the Etame Marin block located offshore Gabon in West Africa, the eastern desert and western area of Egypt and Harmattan area of west central Alberta, Canada. The tables below sets forth our estimated net proved reserve quantities for the years ended December 31, 2023, 2022 and 2021. The Gabon and Egypt information was prepared by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Canada information was prepared by the independent firm, GLJ Ltd. ("GLJ"). The 2021 information includes the Sasol interest in the Etame Marin block as we acquired Sasol’s interest on February 25, 2021.

 

    As of December 31, 2023  
   

Crude Oil (MBbls)

   

Natural Gas (MMcf)

   

NGLs (MBbls)

   

Total (MBoe)(1)

 

Proved developed reserves

                               

Gabon

    8,053                   8,053  

Egypt

    10,141                   10,141  

Canada

    1,310       9,011       1,449       4,260  

Total proved developed reserves

    19,504       9,011       1,449       22,454  

Proved undeveloped reserves

                               

Gabon

    1,011                   1,011  

Egypt

    451                   451  

Canada

    2,122       7,921       1,289       4,731  

Total proved undeveloped reserves

    3,584       7,921       1,289       6,193  

Total proved reserves

    23,088       16,932       2,738       28,647  

(1) To convert Natural Gas to MBoe, MMcf is divided by 6.

 

Standardized Measure and Changes in Proved Reserves

 

The following table shows changes in total proved Gabon reserves for all presented years:

Proved Reserves

 

As of December 31,

 

(MBoe)

 

2023

   

2022

   

2021

 

Proved reserves, beginning of year

    10,219       11,218       3,216  

Production

    (3,197 )     (2,971 )     (2,599 )

Revisions of previous estimates

    2,042       1,972       7,968  

Extensions and discoveries

                 

Purchase of reserves

                2,633  

Proved reserves, end of year

    9,064       10,219       11,218  

 

In February 2021, we completed the acquisition of Sasol’s interest in the Etame Marin block. The reserves associated with the acquisition is included in the purchase of reserves category of the December 2021 balance. In 2022, we drilled four wells that were previously included in the proved undeveloped category of the 2021 reserves. 

 

In comparing the net proved reserves of 9.1 MMBoes at December 31, 2023 to the 10.2 MMBoes at December 31, 2022, we added 2.0 MMBoes of reserves through positive revisions of previous estimates. 2.8 MMBoes of the positive revisions were due to performance offset by 0.8 MMBoes of negative revisions through price. The decrease of 17% in the average of the first-day-of-the-month prices for each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $83.22 for 2023 down from $100.35 for 2022.

 

The following table shows changes in total proved Egypt reserves for the year ended December 31, 2023 and the period October 14, 2022 through December 31, 2022:

 

Proved Reserves

 

As of December 31,

 

(MBoe)

 

2023

   

2022

   

2021

 

Proved reserves, beginning of year

    8,577              

Production

    (2,771 )     (639 )      

Revisions of previous estimates

    4,693              

Extensions and discoveries

    93              

Purchase of reserves

          9,216        

Proved reserves, end of year

    10,592       8,577        

 

In 2023, eighteen wells were drilled in Egypt as part of the 2023 drilling campaign. Two of these wells were exploratory that resulted in dry hole wells. 

 

In comparing the net proved reserves of 10.6 MMBoes at December 31, 2023 to the 8.6 MMBoes at December 31, 2022, we added 4.7 MMBoes of reserves through positive revisions of previous estimates. 5.3 MMBoes of the positive revisions were due to performance offset by 0.6 MMBoes of negative revisions through price. The decrease of 20% in the average of the first-day-of-the-month prices for each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $64.59 for 2023 down from $85.02 for 2022.

 

 

16

 

The following table shows changes in total proved Canada reserves for the year ended December 31, 2023 and the period October 14, 2022 through December 31, 2022:

 

Proved Reserves

 

As of December 31,

 

(MBoe)

 

2023

   

2022

   

2021

 

Proved reserves, beginning of year

    9,161              

Production

    (859 )     (247 )      

Revisions of previous estimates

    (1,163 )            

Extensions and discoveries

    1,852              

Purchase of reserves

          9,408        

Proved reserves, end of year

    8,991       9,161        

 

 

In comparing the net proved reserves of 9.0 MMBoes at December 31, 2023 to the 9.2 MMBoes at December 31, 2022, 1.2 MMBoes of reserves were removed through negative revisions of previous estimates. 0.9 MMBoes of the negative revisions were due to performance and 0.3 MMBoes of negative revisions were through price. The decrease of 28% in the average of the first-day-of-the-month prices for the composite MBoe equivalent each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $39.63 per Boe for 2023 down from $55.30 per Boe for 2022..

 

The following table sets forth the standardized measure of discounted future net cash flows:

 

   

As of December 31,

 
   

2023

   

2022

   

2021

 
   

(in thousands)

 

Gabon

  $ 107,824     $ 244,427     $ 99,258  

Egypt

    161,747       226,888        

Canada

    72,363       153,150        

Standardized measure of discounted future net cash flows

  $ 341,934     $ 624,465     $ 99,258  

 

The information set forth in the tables includes revisions for certain reserve estimates attributable to proved properties included in preceding years’ estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of an increase or decrease in the projected economic life of such properties resulting from changes in product prices, estimated operating costs and other factors. Crude oil amounts shown for Gabon are recoverable under the Etame PSC, and the reserves in place at the end of the contract remain the property of the Gabon government. Crude oil amounts shown for Egypt are recoverable under the Merged Concession and the western desert South Ghazalat concession, and the reserves in place at the end of those concessions remain the property of the Egyptian government. The reserves at the end of the contract, including extensions, are not included in the table above.

 

We do not reflect proved reserves on discoveries in our reserve estimates until such time as a development plan has been prepared and approved by our joint venture owners and the government, where applicable.

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flows should not be construed as the current market value of the estimated crude oil, natural gas and NGLs reserves attributable to our properties.

 

Proved undeveloped reserves 

 

Historically, we have reviewed on an annual basis all of our PUDs to ensure an appropriate plan for development exists. 

 

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

 

   

Proved Undeveloped Reserves

   

Future Development Costs

 
   

(MBoe)

   

(in thousands

 

Beginning proved undeveloped reserves at December 31, 2022

    4,322     $ 72,142  

Undeveloped reserves converted to developed reserves

    (602 )     (11,212 )

Revisions

    891       34,570  

Extensions and discoveries

    1,582       23,607  

Ending proved undeveloped reserves at December 31, 2023

    6,193     $ 119,107  

 

 

Our PUD reserves at December 31, 2023 increased by 1.9 MMBoe, primarily due to:

 

Extensions and Discoveries Extensions and discoveries of 1.6 MMBoe are primarily due to our Canada segment where the wells drilled in 2023 proved up areas surrounding the drilling locations and future drilling locations were added in that area.

 

Revisions of Previous Estimates — Revision of 0.9 MMBoe are primarily due to our Gabon segment where a well future well locations was added.

 

Conversion to Proved Developed Conversions of 0.6 MMBoe are attributable to our Egypt segment where five wells that were previously classified ad PUDs were converted to PDP as part of the 2023 drilling program.

 

 

17

 

Controls over Reserve Estimates

 

Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our crude oil, natural gas, and NGLs 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 our Technical Reserve Committee and our reservoir engineer, who is our principal engineer. Our principal engineer has over 30 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 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 Technical Reserve Committee of the Board of Directors meets periodically with management to discuss matters and policies related to reserves.

 

Our controls over reserve estimation include engaging and retaining qualified independent petroleum and geological firms with respect to reserves information. We provide information to our independent reserve engineers about our crude oil, natural gas and NGLs properties in Gabon, Egypt and Canada which includes, but is not limited to, production profiles, ownership and production sharing rights, prices, costs and future drilling plans. Our independent reserve engineers prepare their own estimates of the reserves attributable to our properties. The reserves estimates for our Gabon, Egypt and Canada assets shown herein have been independently evaluated by NSAI (Gabon and Egypt), GLJ (Canada) and our Technical Reserve Committee.

 

NET VOLUMES SOLD, PRICES, AND PRODUCTION COSTS

 

Net volumes sold, average sales prices per unit, and production costs per unit for our 2023, 2022 and 2021 operations are shown in the tables below. 

 

   

Production Volumes (2)

   

Sales Volumes (2)

   

Average Sales Price (2)

   

Average Production Cost (2)

 
   

Crude Oil (MBbl)

   

Natural Gas (MMcf)

   

NGLs (MBbl)

   

Crude Oil (MBbl)

   

Natural Gas (MMcf)

   

NGLs (MBbl)

   

Crude Oil (Per Bbl)

   

Natural Gas (per Mcf)

   

NGLs (Per Bbl)

   

Total (per BoE)

 
                                                                                 

Year Ended December 31, 2023

                                                                               

Gabon

    3,197                   3,196                 $ 79.80     $     $     $ 27.26  

Egypt(1)

    2,771                   2,771                   58.11                   19.77  

Canada(1)

    334       1,528       270       334       1,528       270       71.88       1.93       26.58       11.02  

Total

    6,302       1,528       270       6,301       1,528       270     $ 69.84     $ 1.93     $ 26.58     $ 22.16  
                                                                                 

Year Ended December 31, 2022

                                                                               

Gabon

    2,971                   2,919                 $ 103.09     $     $     $ 33.18  

Egypt(1)

    547                   547                   69.00                   21.84  

Canada(1)

    72       396       73       93       335       63       79.56       4.00       36.12       9.33  

Total

    3,590       396       73       3,559       335       63     $ 97.24     $ 4.00     $ 36.12     $ 30.12  
                                                                                 
                                                                                 

Year Ended December 31, 2021

                                                                               

Gabon

    2,599                   2,711                 $ 70.66                 $ 29.97  
                                                                                 

(1) Reflects sales and production costs after the acquisition date, October 13, 2022

(2) The sales volumes and per Boe information are reported on NRI basis

(3) All of the Company’s production volumes in Gabon are from the Etame Marin block, all of the Company’s production volumes in Egypt are from the Petrobakr concession and substantially all of the Company’s production volumes in Canada are from the Harmattan area.

 

 

 

18

 

AVAILABLE INFORMATION

 

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. We make available, free of charge on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, at https://www.vaalco.com/investors/sec-filings as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. These reports and other information are also available on the SEC's website at https://www.sec.gov. Information contained on our website and the SEC’s website is not incorporated by reference into this Annual Report. We have placed on our website copies of charters for our Audit Committee, Compensation Committee and Environmental, Social and Governance Committee as well as our Code of Business Conduct and Ethics (“Code of Ethics”), Corporate Governance Principles and Code of Ethics for the CEO and Senior Financial Officers. Stockholders may request a printed copy of these governance materials by writing to the Company Secretary, VAALCO Energy, Inc., 9800 Richmond Avenue, Suite 700, Houston, Texas 77042. We intend to disclose updates or amendments to our Code of Ethics and Code of Ethics for the CEO and Senior Financial Officers on our website within four business days following the date of such update or amendment.

 

CUSTOMERS

 

Gabon

 

For the years ended December 31, 2023, 2022 and 2021, we sold our crude oil production from Gabon under a term contract with pricing in the month of lifting, adjusted for location and market factors. For the period of August 2022 through December 2022, revenues in Gabon were concentrated in one customer that constituted 100% of revenues in Gabon. For the year ended December 31, 2023, revenues in Gabon were concentrated in one customer that constituted 100% of revenues in Gabon. 

 

Egypt

 

For the period of October 14, 2022 through December 31, 2022, revenues in Egypt were concentrated with one customer that constituted 100% of revenues in Egypt. For the year ended December 31, 2023, revenues in Egypt were concentrated in two separate customers that constituted approximately 62% and 38% of revenues in Egypt.

 

Canada

 

For the period of October 14, 2022 through December 31, 2022, revenues in Canada were concentrated in three separate customers that constituted approximately 54%, 32% and 14% of revenues in Canada. For the year ended December 31, 2023, revenues in Canada were concentrated in three separate customers that constituted approximately 52%, 37% and 7% of revenues in Canada

 

EMPLOYEES AND HUMAN CAPITAL RESOURCE MANAGEMENT

 

We operate on the fundamental philosophy that people are our most valuable asset as every person who works for us has the potential to impact our success. Identifying quality talent is at the core of everything we do and our success is dependent upon our ability to attract, develop and retain highly qualified employees. Our core values include honesty/integrity, treating people fairly, high performance, efficient and effective processes, open communication and being respected in our local communities. These values establish the foundation on which the culture is built and represent the key expectations we have of our employees. We believe our culture and commitment to our employees creates an environment that allows us to attract and retain our qualified talent, while simultaneously providing significant value to us and our stockholders by helping our employees attain their highest level of creativity and efficiency.

 

As part of our sustainability effort, we plan to conduct and publish the results of an all-employee engagement survey in 2024.

 

Demographics

 

As of December 31, 2023, we had 189 full-time employees, 91 of whom were located in Gabon, 34 in Egypt, 9 in Canada and 55 in Houston. Likewise, there are 42 contractors in Gabon, 16 contractors in Egypt, 1 contractor in Canada and 21 contractors in Houston. We are not subject to any collective bargaining agreements, although some of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union. We believe relations with our employees are satisfactory.

 

Diversity and Inclusion

 

We value building diverse teams, embracing different perspectives and fostering an inclusive, empowering work environment for our employees. We have a long-standing commitment to equal employment opportunity as evidenced by our Equal Employment Opportunity policy. Approximately 16% of our management team are female employees, 96% of our Gabon workforce is Gabonese and 92% of our Egypt workforce is Egyptian.

 

Compensation and Benefits

 

Critical to our success is identifying, recruiting, retaining, and incentivizing our existing and future employees. We strive to attract and retain the most talented employees in the industry by offering competitive compensation and benefits. Our pay-for-performance compensation philosophy is based on rewarding each employee’s individual contributions and striving to achieve equal pay for equal work regardless of gender, race or ethnicity. We use a combination of fixed and variable pay including base salary, bonus, and merit increases, which vary across the business. In addition, as part of our long-term incentive plan for executives and certain employees, we provide share-based compensation to foster our pay-for-performance culture and to attract, retain and motivate our key leaders.

 

19

 

As the success of our business is fundamentally connected to the well-being of our people, we offer benefits that support their physical, financial and emotional well-being. We provide our employees with access to flexible and convenient medical programs intended to meet their needs and the needs of their families. In addition to this medical coverage, we offer eligible employees dental and vision coverage, health savings and flexible spending accounts, paid time off, employee assistance programs, voluntary short-term and long-term disability insurance and term life insurance. Additionally, we offer a 401(k) Savings Plan and Deferred Compensation Plan to certain employees. Certain employees receive additional compensation for working in foreign jurisdictions.  We also plan to expand the benefit for our employees to participate in paid volunteering in company-approved activities, in certain areas of operation.  As part of this global effort, we also expect to publish details about this new benefit for employees.

 

Workplace environment is also crucial in attracting and retaining key talent.  Most of our offices offer a certain level of flexibility (i.e. work from home days and/or flexible core hours) to help meet the needs of the multigenerational workforce and the needs of the business. Our benefits and compensation packages vary by location and are designed to meet or exceed local laws and to be competitive in the marketplace.

 

Commitment to Values and Ethics

 

Along with our core values, we act in accordance with our Code of Ethics, which sets forth expectations and guidance for employees to make appropriate decisions. Our Code of Ethics covers topics such as anti-corruption, discrimination, harassment, privacy, appropriate use of company assets, protecting confidential information, and reporting Code of Ethics violations. The Code of Ethics reflects our commitment to operating in a fair, honest, responsible and ethical manner and also provides direction for reporting complaints in the event of alleged violations of our policies (including through an anonymous hotline). Our executive officers and supervisors maintain “open door” policies and any form of retaliation is strictly prohibited.

 

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 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 our 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.

 

COMPETITION

 

The crude oil, natural gas and NGLs industry is highly competitive. Competition is particularly intense from other independent operators and from major crude oil, natural gas and NGLs companies with respect to acquisitions and development of desirable crude oil, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs 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 develop 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.

 

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REGULATORY 

 

Question - is our practice to obtain any updates on country-specific regulations from local counsel? Also, there was an issue with us not filing to be regulated locally for emissions, verses federally, in Canada. Consider if that merits a mention somewhere.

 

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, natural gas and NGLs production operations and economics are affected by:

 

 

change in governments;

 

civil unrest;

 

price and currency controls;

 

limitations on crude oil, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the crude oil, natural gas and NGLs 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. In recent years, there have been indications that authorities were working or planned to work on a Gas Code and new Hydrocarbons Law. Also, following the coup d’état of August 30, 2023, Gabon established a Transition Committee for the Restoration of Institutions, swore in General Brice Oligui Nguema as the President and appointed a Transition Government and tentatively plans to hold national, presidential and local elections in 2025.  Accordingly, the risk of legislation having a significant impact on petroleum operations being adopted during the Transition Period cannot be discarded. The following is a summary of certain applicable regulatory frameworks in Gabon.

 

2014 Hydrocarbons Law - Up until 2014, the fiscal and regulatory framework governing the exploration and production of hydrocarbons in Gabon was notably unregulated. Successive model contracts issued by the State 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 August 28, 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 contracts, petroleum titles, mining concessions and exploitation permits concluded or granted by the State of Gabon prior to the date of its publication remained in force until their expiration date.

 

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However, the 2014 Hydrocarbons Law further provided that unless such arrangements became consistent with the requirements of the 2014 Hydrocarbons Law, establishment conventions, mining concessions and exploitation permits in effect could not be extended or renewed. Furthermore, the 2014 Hydrocarbons Law prohibited establishment conventions and mining concessions, and provided that the exploitation of new 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 2019 Hydrocarbons Law, existing 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 provisions of the 2019 Hydrocarbons Law, and its implementing regulations.

 

The 2019 Hydrocarbons Law also provides for obligations for immediate application, irrespective of the date 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 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 one year after the entry into force of the 2019 Hydrocarbons Law.

 

PSCs entered into between independent contractors and the 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% participating interest in the operations, to be carried by the contractor.

 

Under the 2019 Hydrocarbons Law, the direct or indirect assignment of a Contractor’s rights or obligations to third parties (non affiliates) under the PSC is subject to approval of the Minister of Petroleum. The State and the national operator have preemption rights, that the State must exercise within 60 days and the national operator must exercise within 45 days if the State does not exercise its rights within the 60 days. The preemption right of the State and the national operator also applies in change of control situations. In February 2024, the State/national operator exercised its preemption right in a share transaction involving a number of PSCs and concessions already in effect prior to 2014.

 

The 2019 Hydrocarbons Law also entitles the National operator to acquire a maximum 15% stake at market value in all PSCs as of the date of signature.

 

In addition, the 2019 Hydrocarbons Law provides that the State of Gabon may acquire an equity stake of up to 10%, at market value, in an operator applying for or already holding an exclusive development and production authorization.

 

Canada

 

In Harmattan, Canada, we now own production and working interests in certain facilities in the Cardium light oil and Mannville liquids-rich gas assets. Harmattan is located approximately 80 kilometers north of Calgary, Alberta. This property produces oil and associated natural gas from the Cardium and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to 2,600 meters. The Harmattan property covers 46,100 gross acres of developed land and 29,300 gross acres of undeveloped land. We also own a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are handled. All gas is delivered to a third party non-operated gas plant for processing.

 

Our exploration and production activities in Canada are subject to Canadian federal and provincial 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 Canada.

 

With the exception of the province of Manitoba, each provincial government in Western Canada owns most of the mineral rights to the oil and natural gas located within their respective provincial borders. The Government of Alberta grants rights to explore for and produce oil and natural gas based on conditions set out in provincial legislation and regulations in exchange for a Crown Royalty share as set out in the Alberta Modernized Royalty Framework Guidelines, 2017 (as amended in 2023). To develop oil and gas resources, producers must also have access rights to the surface lands required to conduct operations. For private lands in Alberta, producers must either obtain consent of the private landowner or, where an agreement cannot be reached, a right of entry order issued under the Surface Rights Act (Alberta). In addition to obtaining mineral and surface rights in Canada, producers may need to engage extensively with Indigenous groups. Canadian federal and provincial governments have a constitutional duty to consult and, in some cases, accommodate Indigenous groups where a project might adversely impact a potential Indigenous rights and title claim. The procedural aspects of the duty to consult are often delegated to project proponents.

 

Pursuant to The Constitution Act, 1867 (Canada), the Canadian federal government has primary jurisdiction over interprovincial oil and gas pipelines, import and export trade in oil and gas, and offshore oil and gas exploration and production. Proposed interprovincial pipeline projects require a regulatory review by the Canada Energy Regulator under the Canadian Energy Regulator Act (Canada) to proceed. An impact assessment by the Impact Assessment Agency and a determination by Cabinet that a pipeline project is in the public interest will also likely be required under the Impact Assessment Act (Canada)(“IAA”). Certain oil and gas projects were subject to federal environmental assessments prior to the Supreme Court of Canada finding the “designated projects” component of the IAA to be unconstitutional in a judgement released on October 13, 2023. The federal government has yet to introduce legislative changes to the IAA clarifying the scope of federal environmental assessments following the Supreme Court of Canada’s ruling.

 

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The Alberta Energy Regulator (“AER”) is the primary regulator of resource development in Alberta. It derives its authority from the Responsible Energy Development Act (Alberta) and several related statutes. AER regulatory approval is required for all oil and natural gas projects or activities in Alberta. An environmental impact assessment under the Environmental Protection and Enhancement Act (Alberta) will also likely be required. 

 

In addition to conducting project approvals, the AER regulates the lifecycle of projects and performs ongoing monitoring of oil and gas projects to ensure compliance with standards and conditions set out in the licenses and approvals it issues and in the AER directives and regulations. The AER also oversees project closure obligations. For example, the AER administers the Licensee Liability Management Rating Program, which is currently being phased out with implementation of the AER’s new Liability Management Framework (“LMF”), to ensure adequate security is available for a project to be decommissioned safely, with no harm to the public or the environment.

 

Canada also has extensive climate change regulations at both the federal and provincial level mandating greenhouse gas (“GHG”) emission reductions by oil and natural gas producers. The federal government enacted the Greenhouse Gas Pollution Pricing Act (Canada) (the “GGPPA”), which came into force on January 1, 2019. One component of this regime is an emissions trading system for large industry. The GGPPA allows provinces to either develop their own carbon pollution pricing systems that meet the minimum federal benchmark, failing which the federal carbon pollution pricing system applies. Alberta’s Technology Innovation and Emissions Reduction Regulation (“TIER”), which came into effect on January 1, 2020, regulates emissions of heavy industry in line with federal standards. On December 14, 2022, the Government of Alberta introduced several amendments to TIER which became effective January 1, 2023, broadening the scope of “large emitters” subject to TIER and strengthening facility specific benchmarks, among other things. The Government of Alberta also enacted the Methane Emission Reduction Regulation (Alberta) on January 1, 2020, which, in line with AER Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (“AER Directive 060”) and AER Directive 017: Measurement Requirements for Oil and Gas Operations sets vent gas limits for methane per month, which are monitored through the collection of representative measuring data.

 

In Canada, there is a general presumption against the retroactive application of legislation absent an express statutory statement to the contrary. Significant changes to oil and gas regulations impacting existing projects are also often implemented through a prospective phase-in approach. For example, in 2019 the Royalty Guarantee Act (Alberta) came into effect and provides that no major changes will be made to the current oil and gas royalty structure for a period of at least 10 years. AER Directive 060 was updated in April 2022 and sets more stringent vent gas limits for equipment installed after January 1, 2022, with a phased in approach for equipment installed prior to that date.

 

Egypt

 

Laws and Regulations

 

The Egyptian Ministry of Petroleum and Mineral Resources (“MOP”) is the ministerial governmental authority responsible for the regulation and development of the oil and gas industry in Egypt. Certain government agencies, including EGPC, the Egyptian Natural Gas Holding Company ("EGAS") and the Ganoube El-Wadi Petroleum Holding Company ("GANOPE") (each the “government entity”) have been set up to help the MOP achieve its objectives.

 

Under the Egyptian Constitution, all oil and gas resources are under the control of the State of Egypt. Accordingly, only the State can grant rights for exploration and exploitation of oil and gas resources for interested investors. The Egyptian Constitution provides that concessions for the exploitation of such resources shall be issued by virtue of a law for a period not exceeding 30 years.

 

Concession Agreement

 

The mechanism for granting a contractor the right to carry out oil and gas exploration and development activities is the concession agreement. Concession agreements have the force and privileges of law in Egypt, meaning each agreement is an Egyptian Act of Parliament. The concession agreement overrides any contradictory Egyptian laws but not the Egyptian Constitution. In the absence of any legal rule under the relevant concession agreement, the exploration and exploitation operations will be subject to the rules of the Fuel Materials Law No. 66/1953 as amended, and its executive regulation issued by Minister of Industry Decree No. 758/1972 as amended (the "Fuel Materials Law"), and related ministerial decrees, where applicable.

 

Concession agreements usually follow a standard format which may be updated by the MOP and the relevant government entity from time to time, with slight variations. The commercial terms of concession agreements are open to negotiation, but each concession agreement will typically set out certain factors such as: (i) minimum work and financial commitments associated with each exploration and development program; (ii) any bonus payment(s) to be paid by the contractor to the relevant government agency upon triggering events (usually tied to certain production milestones); (iii) royalties payable to the government in cash or in kind; (iv) exploration and development periods and extensions of each; (v) rules concerning the contractor's recovery of its costs and expenses in association with exploration, development and related operations; (vi) production sharing valuations; (vii) priority right to the relevant government entity to offtake the production for domestic needs; (viii) relinquishment obligations and the associated triggering events; and (ix) requirements and procedures to convert an area to a development and to obtain a development lease, conclude sales and offtake agreement, and to dispose of the contractor’s share of production.

 

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Cost Recovery and Production Allocation

 

The concession agreement will set out in detail the distribution of cost recovery for the contractor, including a dedicated annex outlining the accounting procedures for treatment of costs, expenses, and taxes under the concession agreement. Typically, the contractor bears all the risks until a commercial discovery is made, and, following which, the joint operating committee ("JOC") is formed. The contractor will then be entitled to recover a certain percentage of its costs related to its previous and ongoing exploration and development activities in proportion to its working interest in the concession agreement. These costs may be recovered from the total petroleum production at a rate set out under the concession agreement on a quarterly basis. If the recoverable expenditures exceed the amount recoverable from petroleum production in any period, the unrecovered portion of the expenditures can usually be carried forward to subsequent periods. Full title to fixed and movable assets that are charged to cost recovery will usually pass from the contractor to the relevant government agency when its total costs have been recovered in accordance with the concession agreement, or at the time of relinquishment of the concession agreement with respect to all assets chargeable to the operations whether recovered or not, whichever occurs earlier.

 

Ownership of Assets

 

Under the model concession agreements, the movable and immovable assets (other than lands, which become GANOPE/EGAS/EGPC's property as of the purchase thereof) are transferred automatically and gradually from the contractor to the government entity, as they become subject to cost recovery pursuant to the cost recovery provisions of the concession. The contractor (through the JOC) only has the right to use such assets for the purpose of petroleum operations under the concession agreement.

 

Termination and Revocation of Concession

 

The concession agreement is terminated by the lapse of its term, unless terminated prematurely. In addition, the Government has the right to prematurely terminate the concession agreement in several instances set out in the concession. The Government may, among other things, terminate the concession in the event of a misrepresentation by the contractor, an assignment of the contractor's rights without obtaining the required approvals, or the contractor being declared bankrupt, or committing any material breach under the concession or the Fuel Materials Law. If the Government deems that one of these causes (other than force majeure events) exists, it will give the contractor 90 days’ written notice to remedy and remove the cause. If, at the end of the 90-day notice period, the cause has not been remedied and removed, the concession agreement may be terminated by a presidential decree.

 

Equatorial Guinea

 

Our exploration and production activities in Equatorial Guinea are subject to the applicable regulations of the country. 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. A draft of a new Hydrocarbons Law was distributed by the Ministry of Petroleum during 2023 for comment and a new General Tax Law is being reviewed by the Parliament, but it is still not possible to determine if any changes materially affecting our operations will be approved. The following is a summary of certain currently applicable regulatory frameworks in Equatorial Guinea.

 

All hydrocarbons existing in Equatorial Guinea’s onshore territory, as well as in its sovereign and jurisdictional waters, are Equatorial Guinea property and part of the public domain. The monetization of such hydrocarbons 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 activities in the manner and 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 become effective only on the date the contractor is notified of presidential ratification. The powers to sign and amend PSCs and supervise their performance belong to the ministry responsible for petroleum operations. In addition, the national oil company of Equatorial Guinea, GEPetrol, holds, manages and takes participations in petroleum activities on behalf of Equatorial Guinea.

 

In 2006, the Parliament 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 the 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.

 

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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 the Appointed EG Petroleum Ministry. This situation has not changed. Also, in early 2023, Mr. Gabriel Obiang Lima, who had been the Minister in charge of petroleum matters for several years, was moved to another Ministry and Mr. Antonio Oburu, who had been the General Director of the National Oil Company (GEPetrol), became the head of the MMH. Until now no materials changes in the enforcement of petroleum legislation has been felt.

 

All contracts signed with the State of Equatorial Guinea for the exploration and 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 elect to have, either directly or through a national company, a minimum interest of 20% 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 a carried interest. The Hydrocarbons Law provides that the State of Equatorial Guinea (through GEPetrol or otherwise) will only be required to contribute to any cost for petroleum operations that it has a carried interest in from the period where it notifies the contractor that it no longer wants its interest carried. In effect, however, the carry normally ends with the approval of the development and production of the asset subject to the 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 or the Petroleum Regulations; the contractor that carries the State of Equatorial Guinea’s interest is given the right to a percentage of the cost recovery oil pertaining to that interest, as agreed in each PSC.

 

ENVIRONMENTAL REGULATIONS

 

General

 

Our operations are subject to various federal, state, local and international laws and regulations, including laws and regulations in Gabon, Equatorial Guinea, Egypt and Canada, governing the discharge of materials into the environment or otherwise relating to environmental protection or pollution control. The cost of compliance could be significant. While we are currently complying in all material respects 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 joint and several liability, which could subject us to liability 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, natural gas and NGLs 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, or claims for damages to property, employees, other persons, the environment or natural resources could have on us.

 

In addition, a number of governmental bodies have adopted, have introduced or are contemplating regulatory changes in response to the potential impact of climate change. Legislation, increased regulation and litigation regarding climate change could impose significant costs on us, our joint venture 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, Egypt, Canada and the U.S., signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls for signatory countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG 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 GHG, to which various countries and regions are parties.

 

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The State of Gabon and the Republic of Equatorial Guinea did not sign the Global Renewables and Energy Efficiency Pledge at COP 28. However, a few oil companies operating in Gabon signed the Oil and Gas Decarbonization Charter at COP 28. One of them is ending its operations in Equatorial Guinea upon the expiration of its petroleum contracts.

 

On October 5, 2016, Canada ratified the Paris Agreement by a vote in Parliament. In August 2017, the U.S. Department of State officially informed the United Nations of the U.S.’ 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 U.S.’ 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% reduction from 2005 levels in economy-wide GHG emissions by 2030. Following the Paris Agreement and its ratification in Canada, the Government of Canada also pledged to cut its emissions by 40-45% from 2005 levels by 2030. In June 2021, the Canadian federal government passed the Canadian Net-Zero Emissions Accountability Act (Canada), which provides a legal foundation and framework for Canada to achieve net-zero GHG emissions by 2050.

 

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 GHG emissions targets, potential prices on carbon emissions, incentives to use renewable forms of energy or other requirements, will affect our financial condition and operating performance. Apart from any new legal developments, 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, restrict our access to capital or impact the marketability of crude oil, natural gas and NGLs. In addition, 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 amounts, storm patterns and storm 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 economically developing countries, it is unclear how quickly and to what extent Gabon, Equatorial Guinea or Egypt will increase their regulation of climate change issues in the future. As of the date of this Annual Report, Equatorial Guinea has not adopted any new environmental legislation. Gabon has adopted Ordinance No. 019/2021 of September 13, 2021 on Climate Change, which ratification law has been published in the Official Gazette, with the objective of complying with the Paris Agreement (the "Ordinance on Climate Change"). The Ordinance on Climate Change particularly aims to: (a) provide a framework for targets to be set for controlling and reducing emissions and for increasing GHG absorption in the national climate change strategy and the national plans for climate change adaptation and mitigation; (b) define and develop tools and mechanisms for climate change adaptation and mitigation; (c) provide a framework for, and implement, strategies for adaptation, monitoring mitigation and assessment, action plans, policies, programs and adaptation and mitigation measures; (d) provide a framework and take effective response for adaptation and mitigation measures to facilitate the setting of specific sustainable development, security and energy efficiency goals; (e) promote and manage sustainable development through climate change mitigation and adaptation activities; (f) establish climate change financing mechanisms; and (g) complement international instruments addressing climate change. It also sets forth climate adaptation and mitigation measures for carbon intensive operators (which include petroleum companies) such as (a) the establishment of a National Plan on the Reduction of Gas Flaring with a zero flaring objective; (b) the establishment of a GHG emissions database and quota system, (c) a carbon offset register, and (d) penalties and sanctions for not complying with such measures. Egypt ratified the United Nations Framework Convention on Climate Change (UNFCCC) in 1994, signed the Paris Agreement in 2016 and ratified it in 2017. Egypt is among the top affected countries by climate change. Egypt is already implementing plans pertaining to energy resources diversification and acceleration of decreased carbon emissions, in line with its “Sustainable Development Strategy: Egypt Vision 2030”, the “Integrated Sustainable Energy Strategy 2035” and its “National Climate Change Strategy 2050”. Egypt was also host to the United Nations Climate Change Conference-COP27, during which the role of the oil and gas sector was the highlight of the “Decarbonization Day” thereof. Egypt submitted in June 2023 a revised Nationally Determined Contribution (NDC) to the United Nations Development Programme (“UNDP”), focusing on Egypt’s commitment to reduce emissions by 65% in the oil and gas sector (1.7 Mt CO2e) by 2030, increasing renewable energy capacities and alternative energy (including natural gas) sources to generate 42% of electricity by 2035, and increased policy actions and measures across key sectors including the oil and gas sector. Through 2022 to 2023, Egypt announced and signed further partnerships in the energy sector, particularly for green hydrogen and ammonia production. In December 2023, during COP28, Egypt formally launched the first African voluntary carbon marketplace.

 

Moreover, Gabon has recently adopted Law no. 007/2023 of November 2, 2023 on the prevention and management of disasters, which requires companies conducting activities defined as dangerous or operating at facilities that are deemed to have an impact on the environment, to obtain, as relevant, authorizations, or establish operational plans. There are no further guidelines on whether and how it will apply to the petroleum industry.

 

In addition, following the coup d’état on August 30, 2023 in Gabon, the establishment of a Transition Committee for the Restoration of Institutions, the swearing in of General Brice Oligui Nguema as President and the appointment of a Transition Government, with in view of holding elections in 2025 (tentative date), it is still unclear whether and how any environmental regulation having a material impact on petroleum operations will be adopted during the Transition Period, and how the current regulations will be implemented.

 

Any significant increase in the regulation or enforcement of environmental issues by Gabon, Equatorial Guinea or Egypt could have a material effect on us. Economically developing countries, in certain instances, have patterned environmental laws after those in the U.S. However, the extent that any environmental laws are enforced in economically developing countries varies significantly.

 

With regards to our development operations offshore West Africa, we are a member of Oil Spill Response Limited (“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 various boom systems that can be used for offshore and shoreline recovery operations. In addition, VAALCO has a Tier 1 spill kit in-country for immediate deployment if required. See “Item 1A. Risk Factors” for further discussion on the impact of these and other regulations relating to environmental protection. 

 

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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 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 Annual 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 that we consider immaterial based on information currently available to us may also materially adversely affect us.

 

Risks Relating to Our Business, Operations and Strategy

 

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.

 

Our exploration and development activities, as well as our active pursuit of complementary opportunistic acquisitions, are capital intensive. To replace and grow our reserves, we must make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of crude oil, natural gas and NGLs reserves. Historically, we have financed these expenditures primarily with cash from operations, debt, asset sales and private sales of equity. We are the operator of the Etame Marin block offshore Gabon, and are responsible for contracting on behalf of all the remaining parties participating in the project and rely on our joint venture owners to pay for 36.4% of the offshore Gabon budget. With respect to Block P, the EG MMH approved our appointment as technical operator in August 2020 and, since we were appointed, we will rely on the timely payment of cash calls by our joint venture owners to pay for 46.3% of the Equatorial Guinea budget, except during any development phases where we have agreed or will agree to carry their interests. The continued economic health of our joint venture owners could be adversely affected by low crude oil prices, thereby adversely affecting their ability to make timely payment of cash calls.

 

If low crude oil, natural gas and NGLs prices, operating difficulties or declines in reserves result in our revenues being less than expected or limit our ability to enter into debt financing arrangements, or our joint venture owners fail to pay their share of project costs, we may be unable to obtain or expend the capital necessary to undertake or complete future drilling programs or to acquire additional reserves.

 

We do not currently have any commitments for future external funding for capital expenditures or acquisitions beyond cash generated from operating activities and our $50 million Facility Agreement (the commitments under which decreased to $43.8 million beginning October 1, 2023). Our ability to secure additional or replacement financing to finance expenditure beyond our current committed capital expenditure for the next 12 months may be limited. We cannot provide any assurances that such additional debt or equity financing or cash generated by operations will be available to meet our capital requirements and fund acquisitions. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. Even if we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities or our ability to make future acquisitions. If cash generated by operations or cash available under any financing sources is not sufficient to meet our capital requirements beyond our current committed expenditure for the next 12 months, the failure to obtain additional financing could result in a curtailment of our operations relating to the development of our properties or prevent us from consummating acquisitions of additional reserves. Such a curtailment in operations or activities could lead to a decline in our estimated net proved reserves and would likely materially adversely affect our business, financial condition and results of operations.

 

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.

 

Our future success depends upon our ability to find, develop or acquire additional crude oil, natural gas and NGLs reserves that are economically recoverable. In general, production from crude oil, natural gas and NGLs properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil, natural gas and NGLs reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced.

 

There can be no assurance that our development and exploration projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economic finding costs. The drilling of crude oil, natural gas and NGLs wells involves a high degree of risk, especially the risk of dry holes or of wells that are not sufficiently productive to provide an economic return on the capital expended to drill the wells. Additionally, seismic and other technology does not allow us to know conclusively prior to drilling a well that crude oil natural gas or NGLs is present or economically producible. Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including declines in crude oil, natural gas or NGLs prices and/or prolonged periods of historically low crude oil, natural gas and NGLs prices, weather conditions, political instability, availability of capital, economic/currency imbalances, compliance with governmental requirements, receipt of additional seismic data or the reprocessing of existing data, failure of wells drilled in similar formations, equipment failures (such as ESPs), delays in the delivery of equipment, and the availability of drilling rigs. If we are unable to increase our proved quantities, there will likely be a material impact on our cash flows, business and operations.

 

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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 in which we have an interest. 

 

On October 11, 2021, we announced our entry into a consortium with 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. Negotiations to finalize the commercial terms were held in 2023, however they  were halted late in the year due to the presidential elections. The negotiations were kick started again at the request of the Gabonese Government  in early February 2024, where the consortium and the government came to an agreement on the fiscal terms on February 9, 2024. The next step is 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 37.5% working interest and 25% working interest, respectively, as non-operating joint owners. The joint owners in the BWE Consortium intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. Our obligations within the BWE Consortium are subject to a number of conditions, including the negotiation and execution of production sharing contracts with the Gabonese government, as well the entry into joint operating agreements with our joint interest owners. There is no assurance that we will be able to agree to terms on definitive production sharing contracts with the Gabonese government nor joint operating agreements with the joint owners in the BWE Consortium. If we are unable to negotiate and enter into definitive agreements with each party, we may not be able to explore, develop and exploit new properties, and our results of operations could be materially adversely affected.

 

We may have limited control over matters relating to development and exploitation activities, including the timing of and capital expenditures for such activities, in projects where we are not the operator, including properties operated by the BWE Consortium. The success and timing of development and exploitation activities on such properties, depends upon a number of factors, including:

 

 

the timing and amount of capital expenditures;

 

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

 

the operator’s expertise, financial resources and willingness to initiate exploration or development projects;

 

approval of other participants in drilling wells;

 

risk of other a non-operator’s failure to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;

 

selection of technology;

 

delays in the pace of exploratory drilling or development;

 

the rate of production of the reserves; and/or

 

the operator’s desire to drill more wells or build more facilities on a project inconsistent with our capital budget, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

 

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

 

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

 

Offshore operations are subject to a variety of operating risks specific to the marine environment. Our offshore production facilities are subject to hazards such as capsizing, sinking, grounding, collision and damage from severe weather conditions. The relatively deep offshore drilling that we conduct involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. We have experienced pipeline blockages in the past and may experience additional pipeline blockages in the future. The impact that any of these risks may have upon us is increased due to the low number of producing properties we own. We could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or result in loss of equipment and license interests.

 

Exploration and development operations offshore Africa often lack the physical and oilfield service infrastructure present in other regions. As a result, a significant amount of time may elapse between an offshore discovery and the marketing of the associated crude oil, natural gas and NGLs, increasing both the financial and operational risks involved with these operations. Offshore drilling operations generally require more time and more advanced drilling technologies, involving a higher risk of equipment failure and usually higher drilling costs. In addition, there may be production risks for which we are currently unaware. The development of new subsea infrastructure and use of floating production systems to transport crude oil from producing wells may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in loss of production, significant liabilities, cost overruns or delays.  

 

In addition, in the event of a well control incident, containment and, potentially, clean-up activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third-party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and clean-up. As a result, a well control incident could result in substantial liabilities for us and have a significant negative impact on our earnings, cash flows, liquidity, financial position and stock price.

 

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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.

 

One of our growth strategies is to capitalize on opportunistic acquisitions of crude oil, natural gas and NGLs reserves and/or the companies that own them and other strategic transactions that fit within our overall business strategy. Any future acquisition will require an assessment of recoverable reserves, title, future crude oil, natural gas and NGLs prices, operating costs, potential environmental hazards, potential tax and employer liabilities, regulatory requirements and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every potential liability on each individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition.

 

Additional potential risks related to acquisitions include, among other things:

 

 

incorrect assumptions regarding the reserves, future production and revenues, or future operating or development costs with respect to the acquired properties, as well as future prices of crude oil, natural gas and NGLs;

 

decreased liquidity as a result of using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;

 

significant increases in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

the assumption of unknown liabilities, losses or costs (including potential regulatory actions) that we are not indemnified for or that our indemnity, insurance or other protection is inadequate to protect against;

 

an increase in our costs or a decrease in our revenues associated with any claims or disputes with governments or other interest owners;

 

an incurrence of non-cash charges in connection with an acquisition and the potential future impairment of goodwill or intangible assets acquired in an acquisition;

 

the risk that crude oil, natural gas and NGLs reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;

 

difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;

 

the diversion of management’s attention from other business concerns during the acquisition and throughout the integration process;
 

losses of key employees at the acquired businesses;

 

difficulties in operating a significantly larger combined organization and adding operations;

  delays in achieving the expected synergies from acquisitions;
  the failure to realize expected profitability or growth;
  the failure to realize expected synergies and cost savings; and
  challenges in coordinating or consolidating corporate and administrative functions.

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. In addition, acquisitions of businesses often require the approval of certain government or regulatory agencies and such approval could contain terms, conditions, or restrictions that would be detrimental to our business after a merger.

 

In the case of sales or divestitures of our properties and businesses, we may become exposed to future liabilities that arise under the terms of those sales or divestitures. Under such terms, sellers typically are required to retain certain liabilities for matters with respect to their sold properties or businesses. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. In addition, we may be required to recognize losses in accordance with exit or disposal activities.

 

The proposed acquisition of Svenska may not be consummated and if consummated, we may not realize the anticipated benefits expected from the acquisition.

 

On February 29, 2024, Buyer and Seller, entered into the Share Purchase Agreement pursuant to which the Buyer will purchase all of the issued shares in the capital of Svenska for $66.5 million in cash, subject to adjustment as described in the Share Purchase Agreement. Pursuant to the terms and subject to the conditions of the Share Purchase Agreement, upon Closing, Buyer will acquire Svenska and, as a result, Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. Buyer will also acquire a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.  The Purchase Price will be funded by a combination of a dividend of cash on Svenska’s balance sheet to the Seller immediately prior to the consummation of the Acquisition and a portion of VAALCO’s cash-on-hand. VAALCO estimates that cash due from VAALCO at Closing will be in the range of approximately $30 to $40 million.

 

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Closing is subject to obtaining necessarily regulatory approvals in Cote d’Ivoire and Sweden and the satisfaction of other customary closing conditions. If the closing conditions are not satisfied or waived within nine months of date of the Share Purchase Agreement, then either the Buyer or the Seller may, at its discretion, terminate the Share Purchase Agreement.  No assurance can be given that the required approvals will be obtained or that the required conditions to closing will be satisfied or waived in a timely manner or at all, and accordingly consummation of the Acquisition may be delayed or not occur at all.

 

If consummated, the success of the Acquisition will depend, in part, on our ability to realize the anticipated benefits from combining our business with Svenska’s business. The anticipated benefits and efficiencies of the Acquisition may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that we do not currently foresee. The failure to realize the anticipated benefits and synergies expected from the Acquisition could adversely affect our business, financial condition and operating results.

 

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.

 

There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating the underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner. The estimates included in this document are based on various assumptions required by the SEC, including non-escalated prices and costs and capital expenditures subsequent to December 31, 2023, and, therefore, are inherently imprecise indications of future net revenues.

 

Estimates of economically recoverable crude oil, natural gas and NGLs reserves and the future net cash flows from them are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserves recovery, timing and amount of capital expenditures, marketability of crude oil, natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil, natural gas and NGLs reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery, and estimates of future net revenues associated with reserves may vary and such variations may be material.

 

Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable crude oil, natural gas and NGLs reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

 

In addition, our reserves may be subject to downward or upward revision based upon production history, results of future development, availability of funds to acquire additional reserves, prevailing crude oil, natural gas and NGLs prices and other factors. Moreover, the calculation of the estimated present value of the future net revenue using a 10% discount rate as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil, natural gas and NGLs industry in general. It is also possible that reserve engineers may make different estimates of reserves and future net revenues based on the same available data.

 

Our reserve estimates are prepared using an average of the first day of the month prices received for crude oil, natural gas and NGLs for the preceding twelve months. Future reductions in prices, below the average calculated for 2023, would result in the estimated quantities and present values of our reserves being reduced. The forecast prices and costs assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

 

Our proved reserves are in foreign countries and are or will be subject to service contracts, production sharing contracts and other arrangements. The quantity of crude oil, and natural gas and NGLs that we will ultimately receive under these arrangements will differ based on numerous factors, including the price of crude oil, and natural gas and NGLs, production rates, production costs, cost recovery provisions and local tax and royalty regimes. Changes in many of these factors could affect the estimates of proved reserves in foreign jurisdictions.

 

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

 

All of our existing properties in Gabon which have future abandonment obligations are located offshore. Our existing properties in Egypt and Canada are onshore. The costs to abandon offshore on onshore wells and the related infrastructure may be substantial. For financial accounting purposes, we record the fair value of a liability for an asset retirement obligation in the period that it is incurred and capitalize the related costs as part of the carrying amount of the long-lived assets. The estimated liability is reflected in the “Asset retirement obligations” and the “Accrued liabilities and other” line items of our consolidated balance sheet.

 

As part of the Etame Marin block production license, we are subject to an agreed-upon cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. Based upon the most recent abandonment study completed in November 2021, the abandonment cost estimate used for this purpose is approximately $81.3 million ($47.8 million net to our 58.8% working interest) on an undiscounted basis. On an annual basis over the remaining life of the production license, we must fund a portion of these estimated abandonment costs. Future changes to the anticipated abandonment cost estimates could change our asset retirement obligations and increase the amount of future abandonment funding payments we are obligated to make. 

 

In Egypt, under model concession agreements and the Egyptian Fuel Materials Law No. 66/1953 as amended and its Executive Regulations issued by Minister of Industry Decree No. 758/1972 as amended (the “Fuel Materials Law”), liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. The model concession agreements do not deal with area handover and abandonment upon termination, expiration or withdrawal from a concession agreement and certain articles in the Fuel Materials Law may apply, albeit the matter in practice is within the discretion of the EGPC. While the current risk that we may become liable for decommissioning liabilities in Egypt is low, future changes to legislation or practice of the EGPC could result in decommissioning, abandonment and/or handover liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect our financial condition.

 

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In relation to petroleum wells, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC. If EGPC agrees that a producing well is not economic, then the contractor will be responsible for decommissioning the well under an EGPC-approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that we could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism.

 

In Canada, liabilities in respect of the decommissioning of our wells, fields and related infrastructure are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and require us to make provisions for and/or underwrite the liabilities relating to such decommissioning. It is difficult to accurately forecast the costs that we would incur in satisfying any decommissioning obligations. When such decommissioning liabilities crystallize, we will be liable either on our own or jointly and severally liable with any other former or current partners in the field. In the event that we are jointly and severally liable with other partners and such partners default on their obligations, we would remain liable, and our decommissioning liabilities could be magnified significantly through such default. Any significant increase in the actual or estimated decommissioning costs that we incur may adversely affect our financial condition. Under the Alberta LMF, the AER began to set annual mandatory closure spend targets for all licensees with inactive inventory in 2022. Under the AER’s Closure Nomination Program, introduced in February 2023 through an update to AER Directive 088: Licensee Life-Cycle Management, eligible landowners or land rights holders can nominate oil and gas wells and facilities that have been inactive or abandoned for longer than five years, for closure, at the expense of the licensee. Liability management in the Alberta oil and gas sector will continue to evolve as the AER continues its phased implementation of the new LMF.

 

If we are required to expend greater amounts than expected on abandoning or decommissioning costs, this could materially affect our revenues and financial performance.

 

We may not generate sufficient cash to satisfy our payment obligations under the Merged Concession Agreement or be able to collect some or all of our receivables from the EGPC, which could negatively affect our operating results and financial condition.

 

On January 19, 2022, subsidiaries of TransGlobe executed the Merged Concession Agreement with the EGPC, which is effective upon the Merged Concession Effective Date. Under the Merged Concession Agreement, VAALCO is obligated to make modernization payments that total $65 million and are payable over six years from the Merged Concession Effective Date of which $45.0 million have been paid. Under the Merged Concession Agreement, TransGlobe will be required to pay an additional $10 million on February 1st for each of the next two years. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024  payments and issue two $10.0 million credits against receivables owed from EGPC. In addition, VAALCO has also committed to spending a minimum of $50 million over each five-year period for the 15 years of the primary term (total $150 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which would be subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control. We may be unable to maintain a level of cash flow sufficient to permit us to satisfy the payment obligations under the Merged Concession Agreement. If we are unable to satisfy our obligations, it is possible that the EGPC could seek to terminate the Merged Concession Agreement, which would negatively affect our operating results and financial condition. 

 

In addition, as of the Merged Concession Effective Date, there was an adjustment of funds owed to us for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date. The cumulative amount of the effective date adjustment was estimated at $67.5 million. However, the cumulative amount of the effective date adjustment is currently being finalized with EGPC and could result in a range of outcomes based on the final price per barrel negotiated. At December 31, 2023, the remaining $50.3 million is recorded on our consolidated balance sheet in Receivables-Other, net. If the EGPC’s financial position becomes impaired or it disputes or if the EGPC refuses to pay some or all of the said amount, our ability to fully collect such receivable from the EGPC could be impaired, which could negatively affect our operating results and financial condition.

 

The Egyptian PSCs contain assignment provisions which, if triggered, could adversely affect our business.

 

On October 13, 2022, VAALCO completed its business combination transaction with TransGlobe whereby TransGlobe became an indirect wholly-owned subsidiary of VAALCO. Legacy subsidiaries of TransGlobe are party to the Egyptian PSCs, which contain restrictive wording relating to assignments of rights under such agreements which, if triggered, require consent of the Egyptian Government in connection with any such assignment (the “Assignment Provisions”). If triggered, the Assignment Provisions also provide that (i) in certain circumstances, the EGPC has the right to acquire the interest intended to be assigned; and (ii) an assignment fee is payable to the EGPC in an amount equal to 10% of the value of each assignment.

 

We do not believe the Arrangement triggered the Assignment Provisions. EGPC has not concurred that no assignment fee is payable.  We are continuing to engage in discussions with the office of the Minister of Petroleum and Mineral Resources and the EGPC for the purpose of resolving the matter. Resolution of this matter could result in a range of outcomes and no assurance can be given that such outcomes will not involve an offset of amounts owed by EGPC to VAALCO. If the Arrangement is deemed to have triggered the Assignment Provisions or VAALCO agrees to make payment to EGPC as part of a resolution, such payment could have an adverse effect on the value of our assets and could adversely affect our results of operations or financial condition. 

 

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

 

Our Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan. We and our Block P joint venture owners are evaluating the timing and budgeting for development and exploration activities in the block. We have completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P and on July 15, 2022 submitted to the EG MMH a plan of development for Block P which on September 16, 2022 was approved by the government of Equatorial Guinea. Due to delays by the partners in agreeing on certain terms relating to joint operations, the EG MMH delayed commencement of the Plan of Development, but on August 24, 2023, the EG MMH directed that activities relating to the Plan of Development resume.  There can be no certainty any such transaction will be completed or that we will be able to commence drilling operations in Block P. If the joint venture owners of Block P fail to meet the commitments under the production sharing contract amendment, our capitalized costs of $10 million associated with Block P interest would be impaired.

 

31

 

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

 

In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil, natural gas and NGLs we have entered into and may continue to enter into derivative arrangements with respect to a portion of our expected production.

 

Our derivative contracts typically consist of a series of commodity swap contracts, such as puts, collars and fixed price swaps, and are limited in duration. 

 

The following table shows the hedges outstanding at December 31, 2023:

 

Settlement Period

Type of Contract

Index

 

Average Monthly Volumes

   

Weighted Average Put Price

   

Weighted Average Call Price

 
       

(Bbls)

   

(per Bbl)

   

(per Bbl)

 

January 2024 - March 2024

Collars

Dated Brent

    85,000     $ 65.00     $ 97.00  

April 2024 - June 2024

Collars

Dated Brent

    65,000     $ 65.00     $ 100.00  

 

 

The following table shows the additional hedges entered into in 2024:

 

Settlement Period

Type of Contract

Index

 

Average Monthly Volumes

   

Weighted Average Put Price

   

Weighted Average Call Price

 
       

(Bbls)

   

(per Bbl)

   

(per Bbl)

 

July 2024 - September 2024

Collars

Dated Brent

    80,000     $ 65.00     $ 92.00  

 

The hedge counterparty will be obligated to make payments to us to the extent that the floating (market) price is below an agreed fixed (strike) price. However, hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on our contract obligations. Disruptions in the market could also lead to sudden changes in the liquidity of the counterparties to our hedge transactions which in turn limit our ability to perform under their hedging contracts with us. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their non-performance, we could incur a significant loss.

 

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when production is less than the volume covered by the derivative instruments or when there is an increase in the differential between the underlying price and actual prices received in the derivative instrument. In addition, certain types of derivative arrangements may limit the benefit that we could receive from increases in the prices for crude oil. natural gas and NGLs, and may expose us to cash margin requirements.

 

We are exposed to the credit risks of the third parties with whom we contract.

 

We may be exposed to third-party credit risk through our contractual arrangements with government entities party to our PSCs, our current or future joint venture owners, marketers of our petroleum and natural gas production, purchasers of our oil, natural gas and NGLs products and other parties. In addition, we may be exposed to third-party credit risk from operators of properties in which we have a Working Interest or Royalty Interest. In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry generally and among our joint venture owners may affect a joint venture owner’s willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until it finds a suitable alternative partner. To the extent that any of such third parties go bankrupt, become insolvent, or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in our inability to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect our financial and operational results.

 

Our ability to collect payments from the sale of crude oil, natural gas and NGLs from our customers depends on the payment ability of our customer base, which may include a small number of significant customers. If our significant customers fail to pay for any reason, we could experience a material loss. In addition, if our significant customers cease to purchase or reduce the volume they purchase of our crude oil, natural gas or NGLs, the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, our crude oil, natural gas and NGLs.

 

In addition, we are and may in the future be exposed to third-party credit risk through our contractual arrangements with governmental entities in Gabon or the EGPC. Significant changes in the crude oil industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect our ability to realize the full value of our accounts receivable from government entities in Gabon or the EGPC. Historically, we have had significant account receivables outstanding from governmental entities in Gabon and the EGPC. While the EGPC has made regular payments of these amounts owing, the timing of these payments has historically been longer than the normal industry standard. In addition, EGPC has at times faced difficulties in accessing foreign exchange markets for the purpose of obtaining U.S. dollars in exchange for Egyptian Pounds. In the event the Governments of Gabon or Egypt fails to meet their respective obligations or we are forced to accept payment in foreign currencies, such failures could materially adversely affect our financial and operational results.

 

We are also exposed to third-party credit risk through our banking relationships in the jurisdictions in which we operate. Recent macroeconomic conditions have caused turmoil in the banking sector in the United States and elsewhere. If any of the banks in which we keep our deposits is affected by such turmoil, we could be materially and adversely affected.

 

32

 

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

 

As a crude oil, natural gas and NGLs producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations and cash flows.

 

Cybersecurity attacks in particular are becoming more sophisticated, and geopolitical tensions or conflicts, such as Russia’s invasion of Ukraine, may further heighten the risk of such attacks. We rely extensively on information technology systems, including internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our technologies systems and networks, and those of our business associates may become the target of cybersecurity attacks, including without limitation malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems and materially and adversely affect us in a variety of ways, including the following:

 

 

unauthorized access to and release of seismic data, reserves information, strategic information or other sensitive or proprietary information, which could have a material adverse effect on our ability to compete for crude oil, natural gas and NGLs resources;

 

data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

 

unauthorized access to and release of personal identifying information of employees and vendors, which could expose us to allegations that we did not sufficiently protect that information;

 

a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt operations;

 

a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export facilities, which could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

 

a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from engaging in hedging activities, resulting in a loss of revenues; and

 

business interruptions, including use of social engineering schemes and/or ransomware, could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

 

To protect against such attempts of unauthorized access or attack, we have implemented multiple layers of cybersecurity protection, infrastructure protection technologies, disaster recovery plans and employee training. While we have invested significant amounts in the protection of our technology systems and maintain what we believe are adequate security controls over sensitive data, there can be no guarantee such plans will be effective.

 

Any cyber incident could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

 

Current and future geopolitical events outside of our control could adversely impact our business, results of operations, cash flows, financial condition and liquidity.

 

We face risks related to geopolitical events, international hostility, epidemics, outbreaks and other macroeconomic events that are outside of our control. The occurrence of certain geopolitical events, including those arising from terrorist activity, international hostility, public health crisis, and the economic impact of global trade tension and the imposition of tariffs, could significantly disrupt our business and operational plans and adversely affect our results of operations, cash flows, financial condition and liquidity. For instance, the ongoing conflicts in the Middle East and between Russia and Ukraine have and may continue to cause geopolitical instability, and adversely impact the global economy, supply chains and specific markets and industries. Although we are not able to enumerate all potential risks to our business resulting from these and other similar events, we believe that such risks include, but are not limited to, the following:

 

 

disruption to our supply chain for materials essential to our business, including restrictions on importing and exporting products;

 

customers, suppliers and other third parties arguing that their non-performance under our contracts with them is permitted as a result of force majeure or other reasons;

 

cybersecurity attacks, particularly as digital technologies may become more vulnerable and experience a higher rate of cyberattacks in the current environment of remote connectivity;

 

any reductions of our workforce to adjust to market conditions, including severance payments, retention issues, and possible inability to hire employees when market conditions improve;

 

logistical challenges, including those resulting from border closures and travel restrictions, as well as the possibility that our ability to continue production may be interrupted, limited or curtailed if workers and/or materials are unable to reach our offshore platforms and FSO charter vessel or our counterparties are unable to lift crude oil from our FSO charter vessel;

  we may be materially adversely affected by the effects of sanctions and other penalties imposed on Russia by the U.S., the European Union and other countries; and
  we may experience a structural shift in the global economy and our demand for crude oil, natural gas and NGLs as a result of changes in the way people work, travel and interact, or in connection with a global recession or depression.

 

We cannot reasonably estimate the period of time that these conditions will persist; the full extent of the impact they will have on our business, results of operations, cash flows, financial condition and liquidity; or the pace or extent of any subsequent recovery.

 

33

 

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

 

After terminating its membership with OPEC in 1995, Gabon re-joined OPEC as a full member in July 2016. Historically and from time to time, members of OPEC have entered into agreements to reduce worldwide production of crude oil, including the agreement reached in April 2020 among OPEC member countries and other leading allied producing countries (collectively, “OPEC+”) 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. As a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production beginning July 2020 and continuing through April 20, 2021 in compliance with the OPEC+ mandate, and we took measures to temporarily reduce our production. 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. However, as a result of the recent decline in oil prices, on October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. We have not received any mandate to reduce current oil production from the Etame Marin block as a result of the OPEC+ initiative and currently, our production is not impacted by OPEC+ curtailments. However, any future reduction in our crude oil production or export activities for a substantial period could materially and adversely affect our revenues, cash flows and results of operations. Gabon remains a member of OPEC+.  There were no required curtailments in 2023.

 

We have less control over our investments in foreign properties than we would have over our domestic investments.

 

Our exploration, development and production activities are subject to various political, economic and other uncertainties, including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them, expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, uncertainties as to whether the laws and regulations will be applicable in any particular circumstance, uncertainty as to whether we will be able to demonstrate to the satisfaction of the applicable governing authorities compliance with governmental or contractual requirements, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, foreign currency availability, royalty and tax increases, changes to tax legislation or the imposition of new taxes, the imposition of production bonuses or other charges and other risks arising out of governmental sovereignty over the areas in which our operations are conducted.

 

Our operations require, and any future opportunistic acquisitions may require, protracted negotiations with host governments, local governments and communities, local competent authorities, national oil companies, and third parties. Host governments may also conduct audits of our operations, the results of which may have a significant negative impact on our reported earnings or cash flows. Host governments may seek to participate in oil, natural gas or NGLs projects in a manner that could be diluted to our interests. Host governments may also require us to hire a specified percentage of local citizens in our operations. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign crude oil ministries and national oil companies, to the jurisdiction of the U.S.

 

In December 2021 and during 2022, the Bank of Central African States (“BEAC”), which is the central bank for the Central African Economic and Monetary Community (CEMAC), passed new regulations and instructions for the CEMAC FX regulations, which were introduced in 2018, that only apply to the extractive industry. The intent of the new regulations is to ensure the application of the FX regulations as of January 1, 2022, without impeding the operations of the extractive industry. Due to the lack of necessary banking infrastructure and preparedness by the banking sector and the various government agencies to apply the new regulations, it is foreseeable that we will run the risk of seeing delays in paying our vendors and domiciliation of goods and services into the CEMAC region throughout 2024 and beyond.

 

As part of securing the first of two five-year extensions to the Etame PSC in 2016, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. On February 28, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar-denominated account transferred the funds to the Central Bank for CEMAC and later converted, at the request of BEAC, the funds in U.S. dollars to franc CFA, the currency of the CEMAC, of which Gabon is one of the six member states. The Etame PSC provides that these payments must be denominated in U.S. dollars. After continued discussions with CEMAC, they agreed to the return of the USD funds and on January 12, 2023, the abandonment funds were returned to the USD account of the Gabonese branch of the international commercial bank. We were allowed to re-establish a USD denominated account and made whole for the original USD amount. Pursuant to Amendment No. 5 of the Etame PSC, we are working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.

 

Private ownership of crude oil reserves under crude oil leases in the U.S. differs distinctly from our rights in foreign reserves where the state generally retains ownership of the minerals, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the U.S. may be materially affected by host governments. While the laws of each of Gabon and Equatorial Guinea recognize private and public property and the right to own property is protected by law, the laws of each country reserve, at the respective government’s discretion, the right to expropriate property and terminate contracts (including the Etame PSC and the Block P PSC) for reasons of public interest, subject to reasonable compensation, determinable by the respective government in our discretion. The terms of the Etame PSC include provisions for, among other things, payments to the government of Gabon for a 13% Royalty Interest based on crude oil production at published prices and payments for a shared portion of “profit oil,” based on daily production rates, which such “profit oil” has been and can continue to be taken in-kind through taking crude oil barrels rather than making cash payments.

 

34

 

We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

 

The respective applicable laws governing the exploration and production of hydrocarbons in Gabon and Equatorial Guinea (Law No. 002/2019 in Gabon and Law No. 8/2006 in Equatorial Guinea) each provide their respective government officials with significantly broad regulatory, inspective and auditing powers with respect to the performance of petroleum operations, which include the powers to negotiate, sign, amend and perform all contracts entered into between the respective governments and independent contractors. The executive branches of each respective government also retain significant discretionary powers, giving considerable control over the executive, judiciary and legislative branches of each government, and the ability to adopt measures with a direct impact on private investments and projects, including the right to appoint ministers responsible for petroleum operations. Further, in Equatorial Guinea, any new PSC or equivalent agreement for the exploration and exploitation of hydrocarbons is subject to presidential ratification before it can become effective.

 

We are also now subject to political, economic and other uncertainties in Egypt.

 

Any of the factors detailed above or similar factors could have a material adverse effect on our business, results of operations or financial condition. If our operations are disrupted and/or the economic integrity of our projects are threatened for unexpected reasons, our business may be harmed. Prolonged problems may threaten the commercial viability of our operations.

 

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

 

Our operations are subject to risks of loss due to civil strife, acts of war, acts of terrorism, piracy, disease, guerrilla activities, insurrection, military activities and other political risks, including tension and confrontations among political parties, that may result in:

 

 

volatility in global crude oil prices, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;

 

negative impact on the world crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;

 

difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;

 

the inability of our personnel or supplies to enter or exit the countries where we are conducting operations;

 

disruption of our operations due to evacuation of personnel;

 

the inability to deliver our production due to disruption or closing of transportation routes;

 

a reduced ability to export our production due to efforts of countries to conserve domestic resources;

 

damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;

 

the incurrence of significant costs for security personnel and systems;

 

damage to or destruction of property belonging to our commodity purchasers leading to interruption of deliveries, claims of force majeure, and/or termination of commodity sales contracts, resulting in a reduction in our revenues;

 

the inability of our service and equipment providers to deliver items necessary for us to conduct our operations resulting in a halt or delay in our planned exploration activities, delayed development of major projects, or shut-in of producing fields;

 

a lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region;

 

the imposition of U.S. government or international sanctions that limit our ability to conduct our business;

 

a shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and

 

a capital market reassessment of risk and reduction of available capital making it more difficult for us and our joint owners to obtain financing for potential development projects.

 

Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Gabon, Equatorial Guinea and Egypt.

 

For example, in September 2023, Gabon experienced a largely non-violent, military coup d’état and the country’s leadership changed hands.  The group leading the coup created a Committee for the Transition and Restauration of Institutions and a new president was sworn in on the basis of a transition charter adopted by the group leading the coup. The new president has indicated that a new constitution for Gabon will be adopted and that elections will be held after a transition period. No assurance can be given that any such new constitution will be adopted or if adopted, that the content thereof will be in line with Gabon’s existing laws. Any of these developments may have an adverse effect on our operations and financial results.

 

While we monitor the economic and political environments of the countries in which we operate, loss of property and/or interruption of our business plans resulting from civil or political unrest could have a significant negative impact on our earnings and cash flow. In addition, losses caused by these disruptions may not be covered by insurance, or even if they are covered by insurance, we may not have enough insurance to cover all of these losses. If any violent action causes us to become involved in a dispute, we may be subject to the exclusive jurisdiction of courts outside the U.S. or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S. or international arbitration, which could adversely affect the outcome of such dispute.

 

35

 

Inflation could adversely impact our ability to control costs, including operating expenses and capital costs.

 

Inflation rose significantly in the second half of 2021 and through 2023. In addition, global and industry-wide supply chain disruptions have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase, as well as a scarcity of certain products and raw materials. To the extent inflation remains elevated, we may experience further cost increases for our operations, including oilfield services and equipment as increasing prices of oil, natural gas and NGLs, increased drilling activity in our areas of operations, as well as increased labor costs. An increase in the prices of oil, natural gas and NGLs may cause the costs of materials and services we use to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, could negatively impact our business, financial condition and results of operation.

 

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

 

We are exposed to foreign currency risk from our foreign operations. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency. A weakening U.S. dollar will have the effect of increasing costs, while a strengthening U.S. dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in recent years in response to international political conditions, general economic conditions, the European sovereign debt crisis and other factors beyond our control. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. In addition, currency devaluation can result in a loss to us for any deposits of that currency, such as our deposits in the Etame PSC abandonment account, which have been converted from U.S. dollars to the Gabonese local currency.

 

We are also exposed to foreign currency exchange risk related to certain cash, accounts receivable, long-term debt, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars, and on cash balances denominated in Egyptian pounds. Some collections of our accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances.

 

In addition, from time to time, emerging market countries such as those in which we operate adopt measures to restrict the availability of the local currency or the repatriation of capital across borders. These measures are imposed by governments or central banks, in some cases during times of economic instability, to prevent the removal of capital or the sudden devaluation of local currencies or to maintain in-country foreign currency reserves. In addition, many emerging markets countries require consents or reporting processes before local currency earnings can be converted into U.S. dollars or other currencies and/or such earnings can be repatriated or otherwise transferred outside of the operating jurisdiction. These measures may have a number of negative effects on us, including the reduction of the immediately available capital that we could otherwise deploy for investment opportunities or the payment of expenses. In addition, measures that restrict the availability of the local currency or impose a requirement to operate in the local currency may create other practical difficulties for us.

 

We do not utilize derivative instruments to manage these foreign currency risks. As a result, our consolidated earnings and cash flows may be impacted by movements in the exchange rates.

 

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

 

We are subject to the provisions of the U.S. Foreign Corrupt Practices Act, the UK Bribery Act, the Corruption of Foreign Public Officials Act (Canada) and other similar laws. The foregoing laws prohibit companies and their intermediaries from making improper payments to officials for the purpose of obtaining or retaining business. In addition, such laws require the maintenance of records relating to transactions and an adequate system of internal controls over accounting. There can be no assurance that our internal control policies and procedures, compliance mechanisms or monitoring programs will protect us from recklessness, fraudulent behavior, dishonesty or other inappropriate acts or adequately prevent or detect possible violations under applicable anti-bribery and anti-corruption legislation.

 

Our failure to comply with anti-bribery and anti-corruption legislation could result in severe criminal or civil sanctions and may subject us to other liabilities, including fines, prosecution, potential debarment from public procurement and reputational damage, all of which could have a material adverse effect on our business, results of operations and financial condition. Investigations by governmental authorities could have a material adverse effect on our business, results of operations and financial condition.

 

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.

 

While our management has concluded that our internal control over financial reporting is effective, we do not expect that the relevant internal controls and disclosure controls will prevent or detect all possible errors or all instances of fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, have been or will be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistakes. Further, controls can be circumvented by the individual acts of some persons or by two or more persons acting in collusion. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in any control system designed under a cost-effective approach, misstatements due to error or fraud may occur and not be detected. A failure of the controls and procedures to detect error or fraud could seriously harm our business and results of operations.

 

36

 

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

 

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing, and transportation of crude oil, natural gas and NGLs, including blowouts, cratering and fire, any of which could result in damage to, or destruction of, crude oil, natural gas and NGLs wells or formations, production facilities, and other property, as well as injury to persons. For protection against financial loss resulting from these 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. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, nationalization, business interruption, war, terrorism, and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event that we are not fully insured against could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

 

37

 

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

 

We are highly dependent upon the efforts of our senior management and other key employees. The loss of the services of our Chief Executive Officer or Chief Financial Officer, as well as any loss of the services of one or more other members of our senior management, could delay or prevent the achievement of our objectives. We do not maintain any “key-man” insurance policies on any of our senior management, and do not intend to obtain such insurance. In addition, due to the specialized nature of our business, we are highly dependent upon our ability to attract and retain qualified personnel with extensive experience and expertise in evaluating and analyzing drilling prospects and producing crude oil, natural gas and NGLs from proved properties and maximizing production from crude oil, natural gas and NGLs properties. There is competition for qualified personnel in the areas of our activities, and we may be unsuccessful in attracting and retaining these personnel.

 

We are subject to relinquishment obligations under certain of our title documents.

 

We are subject to relinquishment obligations under our title documents which oblige us to relinquish certain proportions of our concession lease and license areas and thereby reduce our acreage. Additionally, we may be unable to drill all of our prospects or satisfy our minimum work commitments prior to relinquishment and may be unable to meet our obligations under the title documents. Failure to meet such obligations could result in concessions, leases and licenses being suspended, revoked or terminated which could have a material adverse effect on our business.

 

We may be exposed to the risk of earthquakes in Alberta.

 

The AER monitors seismic activity across the province of Alberta in Canada to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further. The AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface Order Nos. 2, 6, and 7 (the “Seismic Protocol Regions”). While we do not have operations in the Seismic Protocol Regions, we own production and working interest facilities and assets in the Harmattan area of west central Alberta and are exposed to the risks of earthquakes in that region. We routinely conduct hydraulic fracturing in our drilling and completion programs.

 

There may be valid challenges to title or legislative changes which affect our title to the oil, natural gas and NGLs properties we control in Canada.

 

Although title reviews may be conducted in Canada prior to the purchase of oil, natural gas and NGLs producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. Due in part to the nature of property rights development historically in Canada as well as the common practice of splitting legal and beneficial title, public registries are not determinative of actual rights held by parties. Further, the fragmented nature of oil and gas rights, which may be held by the government or private individuals and companies, and may be split among a great number of different granting documents, means that despite best efforts of parties, latent defects may not be immediately discoverable. As such, our actual interest in properties may accordingly vary from our records. If a title defect does exist, it is possible that we may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on our business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect our title to the oil and natural gas properties that we control in Canada that could impair our activities and result in a reduction of the revenue we receive. Additionally, title claims by Indigenous groups could, among other things, delay or prevent the exploration or development of our properties, which in turn could have a material adverse effect on our business, financial condition, results of operations and prospects.

 

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

 

From time to time, emerging market countries such as those in which we operate adopt measures to restrict the availability of the local currency or the repatriation of capital across borders. These measures are imposed by governments or central banks, in some cases during times of economic instability, to prevent the removal of capital or the sudden devaluation of local currencies or to maintain in-country foreign currency reserves. In addition, many emerging markets countries require consents or reporting processes before local currency earnings can be converted into U.S. dollars or other currencies and/or such earnings can be repatriated or otherwise transferred outside of the operating jurisdiction. These measures may have a number of negative effects on us, including the reduction of the immediately available capital that we could otherwise deploy for investment opportunities or the payment of expenses. In addition, measures that restrict the availability of the local currency or impose a requirement to operate in the local currency may create other practical difficulties for us.

 

Our results of operations, financial condition and cash flows could be adversely affected by changes to interest rates.

 

Our Facility Agreement is for $43.8 million, none of which had been drawn as of December 31, 2023. An increase in interest rates could result in a significant increase in the amount we pay to service any subsequently drawn, and any future other debt taken out by us, resulting in a reduced amount available to fund our exploration and development activities and, if applicable, the cash available for dividends. Such an increase could also negatively impact the market price of the shares of common stock. 

 

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.

 

At December 31, 2023, approximately 22% of our total estimated proved reserves were undeveloped reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserves data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be recognized only if they relate to wells planned to be drilled within five years of the date of their initial recognition, we may be required to write-off any proved undeveloped reserves that are not developed within this five-year time frame.

 

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Risks Relating to Our Industry 

 

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

 

Our revenues, cash flow, profitability, crude oil, natural gas and NGLs reserves value and future rate of growth are substantially dependent upon prevailing prices for crude oil, natural gas and NGLs. Our ability to enter into debt financing arrangements and to obtain additional capital on reasonable terms, or at all, is substantially dependent on crude oil, natural gas and NGLs prices.

 

World-wide crude oil, natural gas and NGLs prices and markets have been volatile and may continue to be volatile in the future. Prices for crude oil, natural gas and NGLs are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control. These factors include, but are not limited to, increases in supplies from U.S. shale production, international political conditions, including war, uprisings, terrorism and political unrest in the Middle East and Africa, slowdowns to the global supply chain, the domestic and foreign supply of crude oil, natural gas and NGLs, actions by OPEC+ member countries and other state-controlled oil companies to agree upon and maintain crude oil price and production controls, the level of consumer demand that is impacted by economic growth rates; weather conditions; domestic and foreign governmental regulations and taxes; the price and availability of alternative fuels; technological advances affecting energy consumption; the health of international economic and credit markets; and changes in the level of demand resulting from global or national health epidemics and concerns. In addition, various factors including the effect of federal, state and foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect our ability to market our crude oil, natural gas and NGLs production.

 

In a period of depressed or declining crude oil, natural gas and NGLs prices, we are subject to numerous risks, including but not limited to the following:

 

 

our revenues, cash flows and profitability may decline substantially, which could also indirectly impact expected production by reducing the amount of funds available to engage in exploration, drilling and production;

 

third party confidence in our commercial or financial ability to explore and produce crude oil, natural gas and NGLs could erode, which could impact our ability to execute on our business strategy;

 

our suppliers, hedge counterparties (if any), vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us;

 

we may take measures to preserve liquidity, such us our decision to cease or defer discretionary capital expenditures during such periods of depressed or declining oil prices; and

 

it may become more difficult to retain, attract or replace key employees.

 

The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.

 

If crude oil, natural gas or NGLs prices decline, we expect that the estimated quantities and present values of our reserves will be reduced, which may necessitate further write-downs. Any future write-downs or impairments could have a material adverse impact on our results of operations. A material decline in prices could also result in a reduction of our net production revenue. Any substantial and extended decline in the price of oil, natural gas and NGLs would have an adverse effect on the carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on our business, financial condition, results of operations and prospects. Volatile oil, natural gas and NGLs prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil, natural gas and NGLs producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for, and project the return on, acquisitions and development and exploitation projects.

 

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

 

We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells that we drill will be productive or that we will recover all or any portion of our investment. Drilling for crude oil, natural gas and NGLs may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. In particular, offshore drilling and development operations require highly capital-intensive techniques.

 

Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including weather conditions, equipment failures or accidents, elevated pressure or irregularities in geologic formations, compliance with governmental requirements and shortages or delays in the delivery of or increased costs for equipment and services. If we are unable to continue drilling operations and we do not replace the reserves we produce or acquire additional reserves, our reserves, revenues and cash flow will decrease over time, which could have a material effect on our ability to continue as a going concern.

 

Our costs could escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and additional government intervention through stimulus spending or additional regulations. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial performance and cash flows.

 

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

 

The crude oil, natural gas, and NGLs industry is intensely competitive. Our competitors include major integrated oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than we do.

 

We may be outbid by our competitors in our attempts to acquire exploration and production rights in crude oil, natural gas and NGLs properties. These properties include exploration prospects as well as properties with proved reserves. Our competitors may also use superior technology that we may be unable to afford or that would require costly investment in order to compete. There is also competition for contracting for drilling equipment and the hiring of experienced personnel. Factors that affect our ability to compete in the marketplace include, among other things:

 

 

our access to the capital necessary to drill wells and acquire properties;

 

our ability to acquire and analyze seismic, geological and other information relating to a property;

 

our ability to retain and hire experienced personnel, especially for our engineering, geoscience and accounting departments; and

 

the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport crude oil, natural gas and NGLs production.

 

In addition, competition due to advances in renewable fuels may also lessen the demand for our products and negatively impact our profitability.

 

Alternatives to petroleum-based products and production methods are continually under development. For example, a number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean-burning gaseous fuels that may address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns, which if successful could lower the demand for crude oil, natural gas and NGLs. If these non-petroleum based products and crude oil alternatives continue to expand and gain broad acceptance such that the overall demand for crude oil, natural gas and NGLs is decreased, it could have an adverse effect on our operations and the value of our assets.

 

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

 

The crude oil, natural gas and NGLs business involves a variety of operating risks, including fire; explosions; blow-outs; pipe failure, casing collapse; abnormally pressured formations; and environmental hazards such as crude oil spills, natural gas leaks, ruptures and discharges of toxic gases, underground migration, and surface spills or mishandling of well fluids, including chemical additives, the occurrence of any of which could result in substantial losses due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

 

Climate change could have an effect on the severity of weather (including hurricanes, floods and wildfires), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations may be adversely affected. Potential adverse effects could include damages to our facilities, disruption of our production activities, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship.

 

We maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict whether insurance will continue to be available to us at a reasonable cost or at all.

 

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.

 

An increased expectation that companies address environmental (including climate change), social and governance (“ESG”) matters may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from engaging with us in favor of companies in other industries, which could negatively impact our share price or our access to capital.

 

Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

 

Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows.

 

In Canada, opposition by Indigenous groups to our operations, development or exploration activities may negatively impact us. Opposition by Indigenous groups to the conduct of our operations, development or exploratory activities in any of the jurisdictions in which we conduct business may negatively impact us in terms of public perception, diversion of management’s time and resources, legal and other advisory expenses, and could adversely impact our progress and ability to explore and develop properties.

 

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Some Indigenous groups have established or asserted Indigenous treaty and title rights to portions of Canada. Although there are no Indigenous treaty or title rights claims on lands where we operate, no certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Such claims, if successful, could have a material adverse impact on our operations and pace of growth.

 

Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect asserted or proven Indigenous treaty or title rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of litigation. The fulfilment of the duty to consult Indigenous people and any associated duties of accommodation may adversely affect our ability, or increase the time required to obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals.

 

Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines that could adversely impact our progress and ability to explore and develop properties in Canada. For example, Canada is a signatory to the United Nations Declaration of the Rights of Indigenous Peoples (“UNDRIP”) and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and gas industry in Western Canada. In June 2021, the United Nations Declaration on the Rights of Indigenous Peoples Act (Canada) (“UNDRIP Act”) came into force in Canada. The UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP’s objectives. Adding further uncertainty, on June 29, 2021, the British Columbia Supreme Court issued a judgement in Yahey v British Columbia (the “Blueberry Decision”), in which it determined that the cumulative impacts of industrial development on the traditional territory of the Blueberry River First Nation (“BRFN”) in northeast British Columbia had breached BRFN’s treaty rights. The Blueberry Decision may lead to similar claims of cumulative effects across Canada in other areas covered by treaties.

 

We face various risks associated with increased opposition to and activism against crude oil, natural gas and NGLs exploration and development activities.

 

The oil and natural gas exploration, development and operating activities that we conduct may, at times, be subject to public opposition. Opposition against crude oil, natural gas and NGLs drilling and development activity has been growing globally. Companies in the crude oil, natural gas and NGLs industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability and business practices. Anti-development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.

 

Such public opposition could expose us to higher costs, delays or even project cancellations, due to increased pressure on governments and regulators by special interest groups, including Indigenous groups, landowners, environmental interest groups (including those opposed to oil and natural gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support from the federal, provincial or municipal governments, reputational damage, delays in, challenges to or the revocation of regulatory approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. There is no guarantee that we will be able to satisfy the concerns of the special interest groups and non-governmental organizations, and attempting to address such concerns may require us to incur significant and unanticipated capital and operating expenditures.

 

Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders in our industry have introduced shareholder proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for us to engage in exploration and production activities.

 

Risks Relating to Legal and Regulatory Matters

 

Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our product.

 

Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce the emissions of GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG emissions reporting obligations and other regulatory programs that limit or require control of GHG emissions from certain sources. These programs may limit our ability to produce crude oil, natural gas and NGLs, limit our