SEC Form 20-F filed by Indonesia Energy Corporation Limited

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 20-F

 

(Mark One)

 

☐	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

 

OR

 

☒	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

 

OR

 

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

 

Date of event requiring this shell company report: Not applicable

 

For the transition period from _______ to _______

 

Commission file number: 001-39164

 

Indonesia Energy Corporation Limited

(Exact name of Registrant as specified in its charter)

 

n/a

(Translation of Registrant’s name into English)

 

Cayman Islands

(Jurisdiction of incorporation or organization)

 

GIESMART PLAZA 7^th Floor

Jl. Raya Pasar Minggu No. 17A

Pancoran – Jakarta 12780

Indonesia

(Address of principal executive offices)

 

James J. Huang

Chief Investment Officer

GIESMART PLAZA 7^th Floor

Jl. Raya Pasar Minggu No. 17A

Pancoran – Jakarta 12780

Indonesia

Phone: +62 21 576 8888

Email: [email protected]

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

 

Securities registered or to be registered pursuant to Section 12(b) of the Act:

 

Title of class		Trading Symbol		Name of exchange on which registered
Ordinary shares, $0.00267 par value per share		INDO		NYSE American LLC

 

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or ordinary shares as of the close of the period covered by the annual report: As of December 31, 2023, there were 10,142,694 of the registrant’s ordinary shares, $0.00267 par value per share, issued and outstanding. As of April 23, 2024, there were 10,202,694 ordinary shares outstanding.

 

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

 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐ Yes ☒ No

 

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

 

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, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☒
		Emerging growth company ☒

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, 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. ☐

 

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

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 which basis of accounting the registrant has used to prepare the financial statements included in this filing:

 

U.S. GAAP ☒

International Financial Reporting Standards as issued by the International Accounting Standards Board ☒

Other ☐

 

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

 

☐ Item 17 ☐ Item 18

 

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

☐ Yes ☒ No

 

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

 

☐ Yes ☐ No

 

 

 

TABLE OF CONTENTS

 

		Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	-ii-
	GLOSSARY OF TERMS	-iii-
	SUMMARY OF RISK FACTORS	-v-
PART I		1
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	1
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	1
ITEM 3.	KEY INFORMATION	1
ITEM 4.	INFORMATION ON THE COMPANY	31
ITEM 4A.	UNRESOLVED STAFF COMMENTS	73
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	73
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	84
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	102
ITEM 8.	FINANCIAL INFORMATION	103
ITEM 9.	THE OFFER AND LISTING	104
ITEM 10.	ADDITIONAL INFORMATION	104
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	109
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	110
PART II		110
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	110
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OR PROCEEDS	110
ITEM 15.	CONTROLS AND PROCEDURES	110
ITEM 16.	RESERVED	112
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	112
ITEM 16B.	CODE OF ETHICS	112
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	113
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	113
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	113
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	113
ITEM 16G.	CORPORATE GOVERNANCE	113
ITEM 16H.	MINE SAFETY DISCLOSURE	113
PART III		114
ITEM 17.	FINANCIAL STATEMENTS	114
ITEM 18.	FINANCIAL STATEMENTS	114
ITEM 19.	EXHIBITS	114

 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

This annual report contains certain forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements include, but are not limited to, statements regarding our or our management’s expectations, hopes, beliefs, intentions or strategies regarding the future and other statements that are other than statements of historical fact. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate”, “believe”, “continue”, “could”, “estimate”, “expect”, “intend”, “may”, “might”, “plan”, “possible”, “potential”, “predict”, “project”, “should”, “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking.

 

The forward-looking statements in this annual report are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management’s examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections. As a result, you are cautioned not to rely on any forward-looking statements.

 

Many of these statements are based on our assumptions about factors that are beyond our ability to control or predict and are subject to significant risks and uncertainties that are described more fully in “Item 3. Key Information—D. Risk Factors”. Any of these factors or a combination of these factors could materially affect our future results of operations and the ultimate accuracy of the forward-looking statements. Fluctuations in our future financial results may negatively impact the value of our ordinary shares. In addition to these important factors, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include among other things:

 

	●	Our overall ability (including our anticipated timing) to meet our goals and strategies, including our plans to continue to conduct seismic interpretation activities, and drill additional wells, at Kruh Block, to develop Citarum Block or acquire rights in additional oil and gas assets in the future;
	●	The economic and capital markets impact of macro-economic and other conditions beyond our control (such as the war between Russia and Ukraine, the conflict between Israel and Hamas, inflation, interest rates and the political situation in Indonesia) on the demand for our oil and gas products in Indonesia and the price of our oil and gas products;
	●	Our ability to estimate our oil reserves;
	●	Our ability to anticipate our financial condition and results of operations;
	●	The anticipated prices for, and volatility in the prices for, oil and gas products and the growth of the oil and gas market in Indonesia and worldwide;
	●	Our expectations regarding our relationships with the Indonesian government (“Government”) and its oil and gas regulatory agencies;
	●	Relevant Government policies and regulations relating to our industry; and
	●	Our corporate structure and related laws, rules and regulations.

 

Should one or more of the foregoing risks or uncertainties materialize, should any of our assumptions prove incorrect, or should we be unable to address any of the foregoing factors, our actual results may vary in material and adverse respects from those projected in these forward-looking statements. Consequently, there can be no assurance that actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected consequences to, or effects, on us. Given these uncertainties, prospective investors are cautioned not to place undue reliance on such forward-looking statements.

 

We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable laws. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

 

 

GLOSSARY OF TERMS

 

The following is a glossary of oil and gas industry and other defined terms used in this annual report.

 

In addition, in this annual report, when we refer to a particular well with the designation of “K” (such as “K-25”), we are referring to a numbered well at Kruh Block.

 

“AMDAL”		Environmental Impact Assessment Report (Analisis Mengenai Dampak Lingkungan).
“Bbl” or “bbl”		Barrel of oil, with “bbls” referring to the plural.
“BP Migas”		Badan Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi, the non-profit Government-owned operating board that succeeded to Pertamina’s role as regulator of upstream oil and gas activities under the Oil and Gas Law.
“BPH Migas”		Badan Pengatur Hilir Minyak dan Gas Bumi, the non-profit Government-owned operating board that succeeded to Pertamina’s role as regulator of downstream oil and gas activities under the Oil and Gas Law.
“BPJS Kesehatan”		Indonesian Health Social Security Administrative Body.
“BPJS Ketenagakerjaan”		Indonesian the Manpower Social Security Administrative Body.
“CNE”		PT Cogen Nusantara Energi, our indirect, wholly-owned subsidiary.
“Company”		Indonesia Energy Corporation Limited.
“Companies Act”		The Cayman Islands Companies Act, as amended and revised from time to time.
“Cost Recovery”		The arrangement with the Government under which oil and gas contractors are allowed to recover their costs from the revenue. Different contracts may impose different ceiling on the percentage of revenue recoverable.
“delineation well”		A well that is drilled to exploit the hydrocarbon accumulation defined by an appraisal or delineation well.
“DGOG”		The Indonesian Director-General of Oil and Gas.
“DMO”		Domestic market obligation.
“exploration well”		A well that is designed to test the validity of a seismic interpretation and to confirm the presence of hydrocarbons in an undrilled formation.
“FTP”		First tranche petroleum.
“GHG”		Regulation of greenhouse gas.
“Government”		The Government of the Republic of Indonesia.
“GWN”		PT Green World Nusantara, our indirect, wholly-owned subsidiary.
“HNE”		PT Harvel Nusantara Energi, our indirect, wholly-owned subsidiary.
“HSSE”		Health, safety, security and environment activities.
“HWE”		PT Hutama Wiranusa Energi, our indirect, wholly-owned subsidiary.
“ICP”		Indonesian Crude Price for the “Talang Akar Pendopo (TAP) / Air Hitam” crude oil type.
“IDR” or “Rupiah”		Indonesian Rupiah.
“Indonesia”		The Republic of Indonesia.
“ITB”		Bandung Institute of Technology.

 

 

“JOB”		Joint Operating Body.
“Joint Study”		A program with the Government whose objective is to determine oil and gas potential within a proposed working area by conducting geological and geophysical work.
“KSO”		Kerja Sama Operasi/Joint Operation with Pertamina, a type of contract between Pertamina and exploration companies.
“LNG”		Liquefied natural gas.
“LPG”		Liquefied petroleum gas.
“medium-sized blocks”		We use a three-tier classification for the size of blocks in Indonesia. The mean reserve size of middle third class (medium-sized field) of 610 oil fields in Indonesia is 5.1 MMBO reserve with a range of 2 to 11 MMBO. With a proved and probable reserves of 7.57 MMBO, Kruh Block is considered a medium-sized oil production block.
“MEMR”		The Ministry of Energy and Mineral Resources of Indonesia.
“MK”		The Constitutional Court of the Republic of Indonesia.
“Oil and Gas Law”		The oil and gas law enacted on November 23, 2001 by the Government.
“OPEC”		The Organization of Petroleum Exporting Countries.
“Pertamina”		PT Pertamina (Persero), the Indonesia state-owned oil and gas company.
“Profit Sharing”		The revenue remaining after cost recovery is profit petroleum which is shared between the Government and the exploration company.
“Program Legislasi Nasional”		The Indonesian National Legislation Program.
“PRMS”		Petroleum Resources Management System.
“proved reserves”		Those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and Government regulations.
“PSC”		Production Sharing Contract, a type of contract between Pertamina and exploration companies.
“SEC”		The United States Securities and Exchange Commission.
“SKK Migas”		Special Task Force for Upstream Oil and Gas Business Activities, an institution established by the Government.
“TAC”		Technical Assistance Contract, a contract between Pertamina and an exploration company.
“U.S. GAAP”		Generally accepted accounting principles in the United States.
“UPL”		Environmental monitoring effort plan.
“US$”		United States dollars.
“USGS”		United States Geological Survey.
“WJ Energy”		WJ Energy Group Limited, our direct, wholly-owned subsidiary.
Units of Measurement
“BOPD”		Barrels of oil production per day.
“BSCF”		Billion standard cubic feet.
“MMBO”		Million barrels of oil.
“MMSCFD”		Million standard cubic feet per day.
“TCF”		Trillion cubic feet.

 

 

SUMMARY OF SIGNIFICANT RISK FACTORS

 

An investment in our ordinary shares is highly speculative and involves a significant degree of risk. The following is a summary of risks, uncertainties and other factors related to our company. As the following is just a summary, you are encouraged to carefully consider all of the risk factors presented in “Item 1A. Risk Factors” and all other information contained in this Report including the financial statements.

 

●	Our operations are solely in Indonesia, and our lack of asset and geographic diversification increases the risk of an investment in us, and our financial condition and results of operations may deteriorate if we fail to diversify.
●	We have previously experienced delays in and, as a result, have been required to modify, our proposed exploration and drilling schedule. There is a material risk that we will experience such delays and required modifications in the future.
●	Oil and gas price volatility has and may continue to adversely affect our results of operations and financial condition.
●	The war in Ukraine and the Israel-Hamas conflict could materially and adversely affect our business and results of operations.
●	Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.
●	There is inherent credit risk in any gas sales arrangements with the Government to which we may become a party in the future.
●	Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all.
●	Our estimated oil reserves are based on assumptions that may prove inaccurate, and thus our estimates of proved reserves and future net revenue are inherently imprecise.
●	We may not find any commercially productive oil and gas reservoirs in connection with our exploration activities.
●	We are subject to complex laws, rules and regulations common to the oil and natural gas industry, including those specific to operating in Indonesia, which can have a material adverse effect on our business, financial condition and results of operations.
●	Our production sharing contract for Citarum Block requires or may require us to relinquish portions of the subject contract area in certain circumstances, which would potentially leave us with less area to explore.
●	Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce.
●	We are faced with the high risks inherent in the drilling of oil and natural gas wells, including the risk that we may encounter no commercially productive natural gas or oil reservoirs even if we expend significant costs on such exploration.
●	You may face difficulties in protecting your interests, and your ability to protect your rights through the U.S. Federal courts may be limited, as a result of our company being incorporated under the laws of the Cayman Islands.
●	We have identified a material weakness in our internal control over financial reporting for the year ended December 31, 2023. If we fail to adequately remediate this weakness or otherwise develop and maintain an effective system of internal control over financial reporting, or if we experience additional material weaknesses in the future, we may be unable to accurately report our financial results or prevent fraud, or comply with the accounting and reporting requirements applicable to public companies, which may adversely affect investor confidence in us and the market price of our shares.
●	The market for our ordinary shares has been volatile, and an active, liquid and orderly trading market for our ordinary shares may not be maintained in the United States, which could limit your ability to sell our ordinary shares.
●	As a foreign private issuer, we are subject to different U.S. securities laws and NYSE American governance standards than domestic U.S. issuers. This may afford less protection to holders of our ordinary shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it.
●	Liquidity risk is the risk that we will encounter difficulty in raising funds to meet commitments associated with financial assets and liabilities. Liquidity risk may result from an inability to sell a financial asset quickly at an amount close to its fair value.

 

 

PART I

 

Unless the context otherwise requires, as used in this annual report, the terms “the Company”, “we”, “us”, and “our” refer to Indonesia Energy Corporation Limited and any or all of its subsidiaries. References to our “management” or our “management team” refers to our officers and directors. Unless otherwise noted, all industry and market data in this annual report on Form 20-F (this “annual report”) is presented in U.S. dollars. Unless otherwise noted, all financial and other data related to the Company in this annual report is presented in U.S. dollars. All references to “$” or “US” in this annual report refer to U.S. dollars.

 

Please see “Glossary of Terms” for a listing of oil and gas-related and other defined and capitalized terms used throughout this annual report.

 

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

 

Not applicable.

 

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

 

Not applicable.

 

ITEM 3. KEY INFORMATION

 

A.	[Reserved]

 

B.	Capitalization and Indebtedness

 

Not applicable.

 

C.	Reasons for the Offer and Use of Proceeds

 

Not applicable.

 

D.	Risk Factors

 

An investment in our ordinary shares is highly speculative and involves a significant degree of risk. You should carefully consider the risks described below, as well as the other information in this report, including our consolidated financial statements and the related notes and all other disclosures in this annual report before deciding whether to invest in our ordinary shares. The occurrence of any of the events or developments described below could materially and adversely affect our business, financial condition, results of operations and growth prospects. In such an event, the market price of our ordinary shares could decline, and you may lose all or part of your investment. Additional risks and uncertainties not presently known to us or that we currently believe are not material may also impair our business, financial condition, results of operations and growth prospects.

 

Risks Related to Our Business

 

Our lack of asset and geographic diversification increases the risk of an investment in us, and our financial condition and results of operations may deteriorate if we fail to diversify.

 

Our business focus is on oil and gas exploration in limited areas in Indonesia and exploitation of any significant reserves that are found within our license areas. As a result, we lack diversification, in terms of both the nature and geographic scope of our business. We will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified. If we are unable to diversify our operations, our financial condition and results of operations could deteriorate.

 

 

Exploring and drilling oil and natural gas wells is a high-risk activity. These risks have delayed the implementation of our drilling program in the past and may continue to do so in the future.

 

Our ability to generate revenue and grow our company is materially dependent upon the success of our exploration and drilling programs. Drilling for oil and natural gas involves numerous risks, many of which are beyond our control, including risks associated with delays in our drilling program and the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of and timing for exploring, drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

 

	●	Unexpected drilling conditions, pressure or irregularities in formations;
	●	Equipment failures or accidents;

 

	●	Adverse weather conditions;
	●	Volatility (significant increase and decreases) in natural gas and oil prices;
	●	Surface access restrictions;
	●	Loss of title or other title related issues;
	●	Compliance with, or changes in, governmental requirements and regulation; and
	●	Costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials (which we experienced in recent past years as a result of COVID-19).

  

We experienced difficulties in drilling in 2021 at our K-25 well when the well collapsed during the rainy season, and at K-28 in 2022 when significant amount of gas was encountered during drilling which required additional effort to protect the well and operations. Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule has varied and may in the future vary from the schedule set forth in our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

 

	●	The timing for and results of exploration efforts and the acquisition, review and analysis of the seismic data;
	●	The availability of sufficient capital resources to us to fund the exploration and drilling oil and gas prospects;
	●	The approval of the prospects by other participants after additional data has been compiled;
	●	Economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
	●	Our financial resources and results; and
	●	The availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits.

 

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil. This would have a material adverse effect on our results of operations and liquidity.

 

 

Oil and gas price volatility has and may continue to adversely affect our results of operations and financial condition.

 

Our revenues, cash flow, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, over which we have no control. If oil prices are higher, we can generate more cash from our drilling operations, and if oil prices are lower, our ability to generate cash is reduced. In addition, our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. Historically and recently, world-wide oil and gas prices and markets have been very volatile and are likely to continue to be volatile in the future.

 

Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include international political conditions (including wars, conflicts, trade and other disputes, cyberattacks and similar occurrences), the domestic and foreign supply of oil and gas, the level of consumer demand and factors effecting such demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels and overall economic conditions. In addition, various factors, including the effect of domestic 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 oil and gas production. Any significant decline in the price of oil or gas would adversely affect our revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our oil and gas properties and our planned level of capital expenditures. This risk was demonstrated in 2021 and 2022 with very significant swings in the price of oil as a result of rising interest rates and inflation, the ongoing Russia-Ukraine conflict, the ongoing Israel-Hamas conflict, high demand for oil in China and India, the actions taken by oil-related intergovernmental organizations such as OPEC to effect the supply and price of oil, and the recovery of the global economy after the COVID-19 pandemic. We may continue to be subject to oil and gas price-related risks while these or similar conditions persist and the global economy remains uncertain.

 

The war in Ukraine and the Israel-Hamas conflict could materially and adversely affect our business and results of operations.

 

The 2022 invasion of Ukraine by Russia and resulting war has materially affected global economic markets, including a dramatic increase in the price of oil and gas, and the uncertain resolution of this conflict could result in protracted and/or severe damage to the global economy. Russia’s military interventions in Ukraine have led to, and may continue to lead to, additional sanctions being levied by the United States, European Union and other countries against Russia. Russia’s military incursion and the resulting sanctions could adversely affect global energy and financial markets and thus could affect the global markets, our customers or suppliers’ businesses and potentially our business.

 

As we are an oil and gas exploration and production company, our performance is affected by global economic conditions as well as geopolitical issues and other conditions. Macroeconomic weakness and uncertainty make it more difficult for us to manage our operations and accurately forecast financial results. As a result of the recent movement of Russian military units into provinces in Ukraine, the United States, the European Union, the United Kingdom and other jurisdictions have imposed sanctions on certain Russian and Ukrainian persons and entities, including certain Russian banks, energy companies and defense companies, and have imposed restrictions on exports of various items to Russian and certain regions of Ukraine (including the self-proclaimed Donetsk People’s Republic and Luhansk People’s Republic and Crimea). Moreover, on February 22, 2022, the Office of Foreign Assets Control of the United States issued sanctions aimed at limiting Russia’s ability to raise funds through sovereign debt. These geopolitical issues have resulted in increasing global tensions and create uncertainty for global commerce. Any or all of these factors could negatively affect our business, financial condition and result of operations. In addition, new requirements or restrictions could come into effect which might increase the scrutiny on our business or result in one or more of our business activities being deemed to have violated sanctions. Our business and reputation could be adversely affected if the authorities of United States, the European Union, the United Nations, or other jurisdictions were to determine that any of our activities constitutes a violation of the sanctions they impose or provides a basis for a sanction designation of us.

 

Also, on October 7, 2023, Hamas terrorists infiltrated Israel’s southern border from the Gaza Strip and conducted a series of attacks on civilian and military targets. Hamas also launched extensive rocket attacks on Israeli population and industrial centers located along Israel’s border with the Gaza Strip and in other areas within the State of Israel. These attacks resulted in extensive deaths, injuries and kidnapping of civilians and soldiers. Following the attack, Israel’s security cabinet declared war against Hamas and a military campaign against these terrorist organizations commenced in parallel to their continued rocket and terror attacks. Following the attack by Hamas on Israel’s southern border, Hezbollah in Lebanon has also launched missile, rocket, and shooting attacks against Israeli military sites, troops, and Israeli towns in northern Israel. In response to these attacks, the Israeli army has carried out a number of targeted strikes on sites belonging to Hezbollah in southern Lebanon. Any hostilities involving Israel or the interruption or curtailment of trade between Israel and its trading partners could adversely affect our operations and results of operations.

 

However, as of the date of this report, we do not have any business, operation or assets in Russian, Ukraine, Israel, Hamas, or Hezbollah, nor do they have any direct or indirect business or contracts with any Russian, Ukraine, Israel, Hamas, or Hezbollah entity as a supplier or customer. Consequently, we do not expect that Russia’s invasion of Ukraine or the Israel-Hamas conflict will have any material impact on our business operations, including but not limited to our product pricing, supply, consumer demand, and the supply chain. Additionally, we believe the cybersecurity risks in the supply chain are not material to our business, and there is no new or heightened risk of potential cyberattacks on the Company by state actors or others since Russia’s invasion of Ukraine.

 

 

The extent and duration of the military actions or campaigns, wars, terrorist attacks, sanctions and resulting market disruptions are impossible to predict, but could be substantial. Any such disruptions caused by Russian military actions or resulting sanctions or the Israel-Hamas conflict may magnify the impact of other risks described in this section. We cannot predict the progress or outcome of the situation in Ukraine or Israel, as the conflict and governmental reactions are rapidly developing and beyond their control. Prolonged unrest, intensified military activities or more extensive sanctions impacting the region could have a material adverse effect on the global economy, and such effect could in turn have a material adverse effect on our business, financial condition, results of operations and prospects.

 

There is inherent credit risk in any gas sales arrangements with the Government to which we may become a party in the future.

 

Natural gas supply contracts in Indonesia are negotiated on a field-by-field basis among SKK Migas, an oil, energy, and government company organized and authorized by the Government to manage natural oil and gas upstream business activities, gas buyers and sellers. The common clause in gas supply contracts is a “take-or-pay arrangement” in which the buyer is required to either pay the price corresponding to certain pre-agreed quantities of natural gas and offtake such quantities or pay their corresponding price regardless of whether it purchases them. Under certain circumstances, such as industrial or economic crisis in Indonesia or globally, the buyer may be unwilling or unable to make these payments, which could trigger a renegotiation of contracts and become the subject of legal disputes between parties. When and if we establish natural gas production and enter into related contracts with the Government, this contract term could have a material adverse effect on our business, financial condition and result of operation by reducing our net profit or increasing our total liabilities in the future, or both.

 

We face credit risk from the Government and the ability of Pertamina to pay our company for the operating costs and profit sharing split in a timely manner.

 

Our current cash inflow is dependent on a “cost recovery” and profit-sharing arrangement with Pertamina, an Indonesian state-owned oil and natural gas corporation based in Jakarta, meaning that all operating costs (expenditures made and obligations incurred in the exploration, development, extraction, production, transportation, marketing, abandonment and site restoration) are advanced by our company and later repaid by Pertamina plus a share of the profit from operations. Any delay of payment by Pertamina may adversely affect our operations and delay the schedule of capital investments which could have otherwise have an adverse effect on our business, prospects, financial condition and results of operations.

 

 

Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.

 

Sustained substantial declines in oil and/or gas prices may render a significant portion of our exploration, development and exploitation projects unviable from an economic perspective, which may result in us having to make significant downward adjustments to our estimated proved reserves. As a result, a prolonged or substantial decline in oil and/or gas prices, such as what we have experienced since mid-2014, which was exacerbated during the COVID-19 pandemic and thereafter caused, and would likely in the future cause, a material and adverse effect on our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures. Additionally, if we experience significant sustained decreases in oil and gas prices such that the expected future cash flows from our oil and gas properties falls below the net book value of our properties, we may be required to write down the value of our oil and gas properties. Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our ordinary shares.

 

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

 

We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures primarily through related and non-related party financings as well as funds raised from our initial public offering in December 2019, our financing with L1 Capital and ATM financing with H.C. Wainwright & Co., LLC (the “Sales Agent”) in 2022. We expect to continue to utilize these or similar resources (as well as funds from potential equity and debt financings and any future net positive cash flow) in the future.

 

However, we cannot assure you that we will have sufficient capital resources in the future to finance all of our planned capital expenditures. During 2022 and 2023, we have had to modify our drilling and other operational plans due in part to limitations on our capital resources.

 

Moreover, volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production could also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our capital expenditures would, by necessity, be decreased.

 

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

 

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we have and will continue to consider allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also have and will continue to consider our likely sources of capital. Our ability to fund our current business plan is dependent on our available capital. As we raised less funds than we had anticipated in our December 2019 initial public offering, we have been faced with challenges relative to the allocation of those funds, which has required us to modify our business plan and which could create challenges for our ability to fully fund our plans. In addition, notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

 

 

Our expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

 

We have identified drilling locations and prospects for future drilling opportunities, including development and exploratory drilling activities, at both Kruh Block and Citarum Block. These drilling locations and prospects represent a significant part of our future drilling plans. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. There can be no assurance that we will drill these locations or that we will be able to produce oil from these locations or any other potential drilling locations. Changes in the laws or regulations on which we rely in planning and executing its drilling programs could adversely impact our ability to successfully complete those programs.

 

Our estimated oil reserves are based on assumptions that may prove inaccurate.

 

Oil engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out herein. Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil, including projecting future rates of production, timing and amounts of development expenditures and prices of oil and gas, many of which are beyond our control. Results of drilling, testing and production after the date of the estimate may require revisions to be made. Accordingly, reserves estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and if such recovered quantities are substantially lower that the initial reserves estimates, this could have a material adverse impact on our business, financial condition and results of operations.

 

We may not find any commercially productive oil and gas reservoirs in connection with our exploration activities.

 

Our business prospects are currently dependent on extracting assets from our Kruh Block and on finding sufficient reserves in our Citarum Block. Drilling involves numerous risks, including the risk that the new wells we drill will be unproductive or that we will not recover all or any portion of our capital investment. Drilling for oil and gas may be unprofitable. Wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and completion operations. In addition, our properties may be susceptible to drainage from production by other operations on adjacent properties. If the volume of oil and gas we produce decreases, our cash flow from operations may decrease.

 

We may be unable to expand operations by securing rights to additional producing our exploration blocks.

 

One of our key business strategies is to expand our asset portfolio, which may include producing our exploration blocks. We have currently identified one such potential block – the Rangkas Area – and our goal will be to secure rights to conduct activities in Rangkas and other areas in Indonesia, However, due to the competitive tender process and uncertainties around Government contracting, among other factors, we may be unable to secure rights to conduct exploration or production activities in any additional areas. In particular, we face competition from other oil and gas companies in the acquisition of new oil blocks through the Indonesian government’s tender process. Our competitors for these tenders include Pertamina (who can tender for blocks on its own), and other well-established large international oil and gas companies. Such companies have substantially greater capital resources and are able to offer more attractive terms when bidding for concessions. If we are unable to secure rights to additional blocks, we would be left without additional opportunities for revenue and profit and remain subject to the risks associated with our current lack of asset diversification, all of which would harm our results of operations.

 

 

We may not be able to keep pace with technological developments in our industry.

 

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

 

We have previously experienced delays in, and, as a result, have been required to modify, our proposed exploration and drilling schedule. There is a material risk that we will experience such delays and required modifications in the future.

 

While we have internally approved plans for development of Kruh Block and have publicly stated our intentions with respect to new drilling activity for Kruh Block, we have had to modify our drilling schedule in the past, and may be required to do so again in the future.

 

Our final determination of whether and when to drill any scheduled or budgeted wells (whether in Kruh Block or otherwise) from time to time will be dependent on a number of factors, including:

 

	●	Prevailing and anticipated prices for oil and gas;
	●	The availability and costs of drilling and service equipment and crews;
	●	Economic and industry conditions at the time of drilling;
	●	The availability of sufficient capital resources;
	●	The results of our exploration efforts;
	●	The acquisition, review and interpretation of seismic data;
	●	Our ability to obtain permits for and to access drilling locations; and
	●	Continuous drilling obligations.

 

Although we have identified or budgeted for numerous drilling locations, we may not be able to drill those locations within our expected time frame or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

 

Moreover, conditions (such as COVID-19, weather, equipment failures, well collapses, delays in Government permitting, limitations on activity due to our lack of, and need to preserve, capital resources, and similar factors) have in the past required us, and may in the future require us, to modify or delay our exploration and drilling programs. Some of the factors that impact the timing of our exploration and drilling plans are beyond our control. Any additional delays in implementing our exploration and drilling programs could damage our reputation and share price, and could also have a material adverse effect on our results of operations (including our cash flows).

 

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

 

Our operations could be adversely affected by weather conditions. Severe weather conditions limit and may temporarily halt our ability to operate during such conditions. We experienced weather related challenges with the collapse of our K-25 well in 2021, which set back our production in 2021, and at K-28 in 2022 when a significant amount of gas was encountered during drilling which required additional effort to protect the well and operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

 

 

The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.

 

Our industry is cyclical and, from time to time, there has been a shortage of drilling rigs, equipment, supplies, oil field services or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfield services will also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could be materially and adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of production from new wells.

 

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control.

 

Our drilling operations are subject to a number of risks, including:

 

	●	Unexpected drilling conditions;
	●	Facility or equipment failure or accidents;
	●	Adverse weather conditions;
	●	Unusual or unexpected geological formations;
	●	Fires, blowouts and explosions;
	●	Geopolitical conflicts including the recent military in Ukraine and sanctions on certain oil and gas exporting countries;
	●	Unforeseen delays in the Government permit processing or the timing for the tendering of necessary third party services;
	●	Uncontrollable pressures or flows of oil or gas or well fluids; and
	●	Public health risks and pandemic outbreaks, such as COVID-19 and its variants.

 

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

 

We do not insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and gas operations.

 

We do not insure against all risks. Our oil and gas exploitation and production activities are subject to hazards and risks associated with drilling for, producing and transporting oil and gas, and any of these risks can cause substantial losses resulting from:

 

	●	Environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, shoreline contamination, underground migration and surface spills or mishandling of chemical additives;
	●	Abnormally pressured formations;

 

 

	●	Mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
	●	Leaks of gas, oil, condensate, and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilities in our operations or at delivery points to third parties;
	●	Fires and explosions;
	●	Personal injuries and death;
	●	Regulatory investigations and penalties; and
	●	Natural disasters and pandemics.

 

We have general insurance covering typical industry risks with an insured limit per event of US$35,000,000 with an insured limit per block of US$100,000,000. However, we do not know the extent of the losses caused by any occurrence and there is a risk that our insurance may be inadequate to cover all applicable losses, to the extent losses are covered at all. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

 

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas.

 

Even when properly used and interpreted, seismic data and visualization techniques are tools only used to assist geoscientists in identifying subsurface structures as well as eventual hydrocarbon indicators, and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of these expenditures. Because of these uncertainties associated with our use of seismic data, some of our drilling activities may not be successful or economically viable, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline, which could have a material adverse effect on us. While we have announced our strategic plan to defer additional new drilling at Kruh Block in order to collect new seismic data acquisition, processing and interpretation during 2023 to provide better quality data, and in turn reduce the uncertainty to some degree in interpretation of reserves estimate and prospective drilling locations, we will continue to be faced with the a risk that this new data will be unreliable or may lead to drilling operations which do not result in oil or gas discoveries.

 

We may suffer delays or incremental costs due to difficulties in the negotiations with landowners and local communities where our reserves are located.

 

Access to the sites where we operate require agreements (including, for example, assessments, rights of way and access authorizations) with the landowners and local communities. If we are unable to negotiate agreements with landowners, we may have to go to court to obtain access to the sites of our operations, which may delay the progress of our operations at such sites. There can be no assurance that disputes with landowners and local communities will not delay our operations or that any agreements we reach with such landowners and local communities in the future will not require us to incur additional costs, thereby materially adversely affecting our business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected government to restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites.

 

 

Unfavorable credit and market conditions could negatively impact the Indonesian economy and may negatively affect our ability to access capital, our business generally and results of operations.

 

Global financial crises and related turmoil in the global financial system may have a negative impact on our business, financial condition and results of operations. In particular, if disruptions in international credit markets, exacerbated by the sovereign debt crises or global pandemics, adversely impact the Indonesian economy (where our oil and gas products are sold by the Government), our business may suffer and may adversely affect our ability to access the credit or capital markets at a time when we would need financing, which could have an impact on our flexibility to react to changing economic and business conditions. Any of the foregoing factors or a combination of these factors, or similar factors not known to us presently, could have an adverse effect on our liquidity, results of operations and financial condition.

 

The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines, storage and processing facilities.

 

The marketability of our production depends in part upon processing and storage. Transportation space on such gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by Indonesian law, regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If our access to these transportation and storage options dramatically changes, the financial impact on us could be substantial and adversely affect our ability to produce and market our oil and gas.

 

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

 

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. In addition, computer technology controls nearly all of the oil and gas distribution systems in Indonesia, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

 

While we have not experienced significant cyber-attacks, we may suffer such attacks in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

 

We rely on independent experts and technical or operational service providers over whom we may have limited control.

 

We use independent contractors to provide us with certain technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. We also rely upon the services of other third parties to explore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

 

Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows, profitability and growth.

 

Our revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also make it uneconomical for us to increase or even continue current production levels of oil and gas.

 

 

Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of other factors beyond our control, including:

 

	●	Changes in foreign and domestic supply and demand for oil and gas;
	●	Political stability and economic conditions in oil producing countries, particularly in the Middle East and also in Russia (particularly given the February 2022 invasion of Ukraine by Russia);
	●	Weather conditions;
	●	Price and level of foreign imports;
	●	Terrorist activity in Indonesia or elsewhere;
	●	Availability of pipeline and other secondary capacity;
	●	General economic conditions;
	●	Global risks of more coronavirus or other viral outbreaks, or other global or local public health uncertainties;
	●	Domestic and foreign governmental regulation; and
	●	The price and availability of alternative fuel sources.

 

Estimates of proved reserves and future net revenue are inherently imprecise.

 

The process of estimating oil reserves in accordance with the requirements of the United States Securities and Exchange Commission (“SEC”) is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

 

Unless we replace our oil reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.

 

Production from oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Accordingly, our current proved reserves will decline as these reserves are produced. Our future oil reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. While we have had success in identifying and developing commercially exploitable deposits and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable deposits or successfully drill, complete or produce more oil reserves, and the wells which we have drilled and currently plan to drill within our blocks or concession areas may not discover or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be materially adversely affected.

 

 

Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all.

 

The oil and natural gas industry is capital intensive and we expect to make substantial capital expenditures in our business and operations for the exploration and production of oil reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other equipment and services, and regulatory, technological and competitive developments. In response to increases in commodity prices, we may increase our actual capital expenditures. We will likely need to raise additional financing to support our business, and we intend to finance our future capital expenditures through cash generated by our operations and potential future financing arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. We also face the risk that financing arrangements (including bank loans or public or private offerings of debt or equity securities) may not be available to us when needed on favorable terms or at all, which could adversely impact our ability to operate our company.

 

If our capital requirements vary materially from our current plans, we would likely require further investment (which may be unavailable to the extent to do not generate positive cash flows) or equity financing (which may be unavailable on desirable terms, or at all). In addition, we will likely incur significant financial indebtedness in the future, which may involve restrictions on other financing and operating activities. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.

 

Our estimates regarding our market are based on our research but may prove incorrect.

 

This report contains certain data and information that we obtained from private publications. Statistical data in these publications also include projections based on a number of assumptions. Our industry may not grow at the rate projected by market data, or at all. Failure of this market to grow at the projected rate may have a material and adverse effect on our business and the market price of our ordinary shares. In addition, the rapidly changing nature of the oil and gas industry results in significant uncertainties for any projections or estimates relating to the growth prospects or future condition of our market. Furthermore, if any one or more of the assumptions underlying the market data are later found to be incorrect, actual results may differ from the projections based on these assumptions. You should not place undue reliance on these or other forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements.”

 

Risks Related to Regulation of Our Oil and Gas Business

 

We are subject to complex laws common to the oil and natural gas industry, particularly in Indonesia, which can have a material adverse effect on our business, financial condition and results of operations.

 

The oil and natural gas industry is subject to extensive regulation and intervention by governments throughout the world, including extensive Indonesian regulations, in such matters as the award of exploration and production interests, the imposition of specific exploration and drilling obligations, allocation of and restrictions on production, price controls, required divestments of assets and foreign currency controls, and the development and nationalization, expropriation or cancellation of contract rights.

 

We have been required in the past, and may be required in the future, to make significant expenditures to comply with governmental laws and regulations, including with respect to the following matters:

 

	●	Licenses, permits and other authorizations for drilling operations;
	●	Reports concerning operations;

 

 

	●	Compliance with environmental, health and safety laws and regulations;
	●	Compliance with the requirements to divest parts of our interest to domestic parties;
	●	Compliance with requirements to sell certain portion of our production to domestic market;
	●	Adjustment to the split between the contractor and the Government in respect of the production;
	●	Compliance with local content requirements;
	●	Drafting and implementing emergency planning;
	●	Plugging and abandonment costs; and
	●	Taxation.

 

Under these laws and regulations, we could be liable for, among other things, personal injury, property damage, environmental damage and other types of damage. Failure to comply with these laws and regulations may also 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. Any such liabilities, obligations, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our business, financial condition or results of operations.

 

In addition, the terms and conditions of the agreements under which our oil and gas interests are held generally reflect negotiations with governmental authorities and can vary significantly. These agreements take the form of special contracts, concessions, licenses, associations or other types of agreements. Any suspensions, terminations or regulatory changes in respect of these special contracts, concessions, licenses, associations or other types of agreements could have a material adverse effect on our business, financial condition or results of operations.

 

Our production sharing contract, or PSC, for Citarum Block requires or may require us to relinquish portions of the subject contract area in certain circumstances, which would potentially leave us with less area to explore.

 

Pursuant to our PSC with SKK Migas for Citarum Block, there are circumstances under which we are required or may be required to relinquish portions of the contract area back to the Government, with such portions being subject to be agreed to between us and the Government. Such circumstances include our inability to complete the work programs agreed to in our PSC for Citarum. If we relinquish or are required to relinquish portions of Citarum, we could be left with fewer areas to explore and a resulting diminishment of potential resources we could capitalize on. See “Business—Our Assets—Citarum Block” for further information. We may be required to agree to similar provisions in future contracts with the Government.

 

The interpretation and application of laws and regulations in Indonesia involves uncertainty.

 

The courts in Indonesia may offer less certainty as to the judicial outcome or a more drawn out judicial process than is the case in more established legal systems. Businesses can become involved in lengthy judicial proceedings over simple issues when rulings are not clearly defined. Moreover, such problems can be compounded by the poor quality of legal drafting and excessive delays in the legal process for resolving issues or disputes. These characteristics of the legal system in Indonesia could expose us to several kinds of risks, including the possibility that effective legal redress may be more difficult to obtain; a higher degree of discretion on the part of the Government; the lack of judicial or administrative guidance on interpreting the relevant laws or regulations; inconsistencies and conflicts between and within various laws, regulations, decrees, orders and resolutions; or the relative inexperience or lack of predictability of the judiciary and courts in such matters.

 

 

The enforcement of laws in Indonesia may depend on and be subject to the interpretation of the relevant local authority. Such authority may adopt an interpretation of an aspect of local law which differs from the advice given to us by local lawyers or even previous advice given by the local authority itself. Matters of local autonomy are extremely controversial in Indonesia, adding further uncertainty to the interpretation and application of the relevant legal and regulatory requirements. Furthermore, there is limited or no relevant case law providing guidance on how courts would interpret such laws and the application of such laws to its concessions, join operations, licenses, license applications or other arrangements. Even where such case law exists, it lacks the binding precedential value found in the U.S. legal system.

 

For example, on November 13, 2012, the Constitutional Court of the Republic of Indonesia (Mahkamah Konstitusi Republic Indonesia, or MK) issued Decision 36/PUU-X/2012 (or MK Decision 36/2012). In it, the MK declared several articles in the Oil and Gas Law of 2001 invalid and dissolved Badan Pelaksana Minyak dan Gas Bumi (or BP Migas) for failing to directly manage oil and gas resources as required by its interpretation of Article 33 of the Constitution of the Republic of Indonesia. In response to MK Decision 36/2012, the Government created SKK Migas and authorized it to take over the functions of BP Migas pursuant to Presidential Regulation No. 9 of 2013 on the Implementation of Management of Natural oil and Gas Upstream Business Activities. However, while these arrangements have not been challenged to date, there is a risk that future challenge to the current arrangements, and changes in Indonesian law generally, could require us to modify our operation and development plans, and could adversely impact our results of operations.

 

Increased regulation by the Government and governmental agencies may increase the cost of regulatory compliance and have an adverse impact on our business, financial condition and results of operations.

 

Our business operations in Indonesia are subject to an expanding system of laws, rules and regulations issued by numerous government bodies. The evolving roles of SKK Migas and The Ministry of Energy and Mineral Resources of Indonesia (or MEMR), together with political changes in Indonesia, has allowed other governmental agencies such as the Ministry of Trade, the Ministry of Forestry, the Ministry for Environment and Bank Indonesia to increase their roles in regulating the oil and gas industry in Indonesia. In addition, the Indonesian tax authorities have recently initiated additional tax audits and implemented measures to increase tax revenues from the oil and gas industry.

 

The continued expansion of the roles of governmental agencies may result in the adoption of new legislation, regulations and practices with which we would be required to comply. Such legislation, regulations and practices may be more stringent and may cause the amount and timing of future legal and regulatory compliance expenditures to vary substantially from their current levels. They could also require changes to our operations and development plans, which could adversely impact our results of operations.

 

The interpretation and application of the Oil and Gas Law of 2001 and the anticipated enactment of a new oil and gas law is uncertain and may adversely affect our business, financial condition and results of operations.

 

In Indonesia, the complexity of the laws and regulations relating to oil and gas activities is compounded by uncertainties in the legal and regulatory framework. Indonesia’s Oil and Gas Law of 2001 went into effect on November 23, 2001 (or the Oil and Gas Law), which was amended on March 31, 2023 by Law No. 6 of 2023 on Stipulation of Government Regulation In Lieu of Law No. 2 of 2022 on Job Creation (known as Law 6/2023). The Oil and Gas Law sets forth a statutory body of general principles governing oil and gas activities, which are further developed and implemented in a series of government regulations, presidential decrees and ministerial decrees. The provisions of the Oil and Gas Law are generally broad, and few sources of interpretative guidance are available. In addition, not all of the implementing regulations to the Oil and Gas Law have been issued and some have only recently been enacted. It is uncertain how these regulations will affect us and our operations without clear instances of their application, while the uncertainty surrounding the Oil and Gas Law and its implementing regulations has increased the risks, and may result in increases in the costs, of conducting oil and gas activities in Indonesia.

 

The Government may also adopt new laws and/or policies regarding oil and gas exploration, development and production that differ from the policies currently in place and that adversely impact the cost of doing business in Indonesia. If and to the extent any changes to the current legal and regulatory framework are detrimental to our business and our position, our business, development plans, financial condition and results of operations could be adversely affected.

 

 

We and our operations are subject to numerous environmental, health and safety laws and regulations which may result in material liabilities and costs.

 

We and our operations are subject to various international, domestic and foreign local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation and disposal of regulated materials; and human health and safety. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry and which may arise unexpectedly and result in material adverse effects on our business, financial condition and results of operations. Breach of environmental laws, as well as impacts on natural resources and unauthorized use of such resources, could result in environmental administrative investigations and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal environmental actions.

 

We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We may not be at all times in complete compliance with these permits and the environmental and health and safety laws and regulations to which we are subject. If we violate or fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain, maintain or renew permits in a timely manner or at all (such as due to opposition from partners, community or environmental interest groups, governmental delays or any other reasons) or if we face additional requirements due to changes in applicable laws and regulations, our operations could be adversely affected, impeded, or terminated, which could have a material adverse effect on our business, financial condition or results of operations.

 

For example, Law No. 32 of 2009 on Protection and Management of Environment (or the Environmental Law) as amended by Law 6/2023 and its implementing regulation, Government Regulation No. 22 of 2021 on Environmental Protection and Management (or GR 22/2021), require an entity conducting oil and gas business operations have its environmental impact assessment report (known as AMDAL), as well as an environmental management effort plan (Upaya Pengelolaan Lingkungan Hidup, or UKL) or an environmental monitoring effort plan (Upaya Pemantauan Lingkungan Hidup or UPL), approved. Under the Environmental Law, should we fail to meet the obligations contained in the relevant AMDAL or UKL or UPL, it can lead to the nullification of our business license.

 

We, as the owner, shareholder or the operator of certain of our past, current and future discoveries and prospects, could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors, predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended, terminated or otherwise adversely affected. We have also contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of the acts or omissions of our contractors, which could have a material adverse effect on our results of operations and financial condition.

 

Releases of regulated substances may occur and can be significant. Under certain environmental laws and regulations applicable to us in Indonesia, we could be held responsible for all of the costs relating to any contamination at our past and current facilities and at any third party waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species or sensitive environmental areas. Environmental laws and regulations also require that wells be plugged and sites be abandoned and reclaimed to the satisfaction of the relevant regulatory authorities. We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in which we operate, which could result in substantial costs.

 

As in other areas, the interpretation and application of environmental laws in Indonesia involves a degree of uncertainty. Such changes in the interpretation and application of existing laws and regulations, or the enactment of new, more stringent requirements, may have and result in an adverse impact on our business, development plans, financial condition and results of operations.

 

 

We may be unable to obtain or maintain special permits to conduct drilling and seismic activities in forest areas in Indonesia.

 

Some of our proposed drilling locations are situated within forestry areas. In order to conduct drilling and seismic activities in the forest area within Indonesia, we will need to obtain “Approval for the Utilization of Forest Area (Persetujuan Penggunaan Kawasan Hutan or PPKH) or as previously known as “Borrow-to-use permit of forest area (Izin Pinjam Pakai Kawasan Hutan, or IPPKH)” from the Indonesian Ministry of Forestry. PPKH is granted for companies to use the forest area other than forestry activities. The Indonesian government has provided for such requirements in several laws and regulations since 1990 concerning conservation of natural resources, natural primary forest and the ecosystem.

 

The application for a PPKH must satisfy both administrative and technical requirements. The maximum validity period for a PPKH for an exploration or production activity is no more than the validity period of the relevant license for the exploration and the production activities. However, in respect of a follow through exploration during a production period, the PPKH may be granted for a maximum period of two years and it is extendable. The application process of PPKH of forest area is complex because applicants had to comply with different requirements at different offices in the Ministry of Forestry, and between government agencies and local administrations, frequently with no certainty of processing time and cost.

 

With the announcement of an “online single submission” (or OSS) processing system in 2018 by the Coordinating Minister for Economic Affairs, the application for a PPKH is processed through the OSS. While the OSS is supposed to shorten the period required for the application, there are numerous documents and other permits (including the local governor’s recommendation and environmental permits) as well as a work program and maps which are required before a PPKH application can be submitted. Any delay in the issuance to us of the PPKH, or our inability to obtain such permit for any reason, would cause delays in our ability to conduct drilling and seismic activities in the subject area, which in turn could adversely impact our business plans and results of operations.

 

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce.

 

Climate change, the costs that may be associated with its effects, and the regulation of greenhouse gas (or GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHG emissions and climate change may increase our operating costs.

 

Moreover, experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by global climate change, GHG emissions or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable. Moreover, the regulation of GHGs and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.

 

 

Labor laws and regulations in Indonesia and labor unrest may materially adversely affect our results of operations.

 

Laws and regulations which facilitate the forming of labor unions, combined with weak economic conditions, have resulted and may result in labor unrest and activism in Indonesia. In 2000, the Government issued Law No. 21 of 2000 regarding Labor Unions (or the Labor Union Law). The Labor Union Law permits employees to form unions without intervention from an employer, the government, a political party or any other party. On March 25, 2003, President Megawati enacted Law No. 13 of 2003 regarding Employment (or the Labor Law) which, among other things, increased the amount of severance, pension, medical coverage, service and compensation payments payable to employees upon termination of employment. The Labor Law requires further implementation of regulations that may substantively affect labor relations in Indonesia. The Labor Law requires companies with 50 or more employees establish bipartite forums with participation from employers and employees. The Labor Law also requires a labor union to have participation of more than half of the employees of a company in order for a collective labor agreement to be negotiated and creates procedures that are more permissive to the staging of strikes. Following the enactment, several labor unions urged the Indonesian Constitutional Court to declare certain provisions of the Labor Law unconstitutional and order the Government to revoke those provisions. The Indonesian Constitutional Court declared the Labor Law valid except for certain provisions, including relating to the right of an employer to terminate its employee who committed a serious mistake and criminal sanctions against an employee who instigates or participates in an illegal labor strike. The Labor Law was amended by Law 6/2023 and the amendments include, amongst others, the reduction in the statutory severance payments payable to the employees in the event of employment termination.

 

Labor unrest and activism in Indonesia could disrupt our operations, our suppliers or contractors and could affect the financial condition of Indonesian companies in general.

 

Risks Related to Doing Business in Indonesia

 

As the domestic Indonesian market constitutes the major source of our revenue, the downturn in the rate of economic growth in Indonesia or other countries due to the unprecedented and challenging global market and economic conditions will be detrimental to our results of operations.

 

The performance and growth of our business are necessarily dependent on the health of the overall Indonesian economy. Any downturn in the rate of economic growth in Indonesia, whether due to political instability or regional conflicts, global health crisis, economic slowdown elsewhere in the world or otherwise, may have a material adverse effect on demand for the commodities we produce. The Indonesian economy is also largely driven by the performance of the agriculture sector, which depends on the impact of the monsoon season, which is difficult to predict. In the past, economic slowdowns have harmed manufacturing industries, including companies engaged in oil and gas extraction. During 2023, Indonesian gross domestic demand increased by 5.3% according to the International Monetary Fund, but any future slowdown in the Indonesian economy could have a material adverse effect on the demand for the commodities we produce and, as a result, on our business, financial condition and results of operations.

 

In addition, the Indonesian securities market and the Indonesian economy are influenced by economic and market conditions in other countries. Although economic conditions are different in each country, investors’ reactions to developments in one country can have adverse effect on the securities of companies in other countries, including Indonesia. A loss of investor confidence in the financial systems of other emerging markets may cause volatility in Indonesian financial markets and, indirectly, in the Indonesian economy in general. Any worldwide financial instability could also have a negative impact on the Indonesian economy, including the movement of exchange rates and interest rates in Indonesia. Any slowdown in the Indonesian economy, or future volatility in global commodity prices, could adversely affect the growth of our business in Indonesia.

 

The Indonesian economy and financial markets are also significantly influenced by worldwide economic, financial and market conditions. Any financial turmoil, especially in the United States, United Kingdom, Europe or China, may have a negative impact on the Indonesian economy. Although economic conditions differ in each country, investors’ reactions to any significant developments in one country can have adverse effects on the financial and market conditions in other countries. A loss in investor confidence in the financial systems, particularly in other emerging markets, may cause increased volatility in Indonesian financial markets.

 

 

The effect and impact of the recently enacted Omnibus Law on job creation in Indonesia are not immediately known and subject to ongoing review.

 

On November 2, 2020, the Government of Indonesia issued the Omnibus Law No. 11 of 2020 on Job Creation (or the Omnibus Law), which aims to attract investment, create new jobs, and stimulate the economy by, among other things, simplifying the licensing process and harmonizing various laws and regulations, and making policy decisions faster for the central government to respond to global or other changes or challenges. The Omnibus Law amended more than 75 laws (including aspects of the Oil and Gas Law) and up to March 2022, the central government has issued at least 51 implementing regulations making the Omnibus Law one of the most sweeping regulatory reforms in Indonesian history. The Omnibus Law introduces a number of new concepts, including a new risk-based assessment (i.e. low, medium and high risks) in issuing licenses for businesses, removes foreign ownership restrictions in various industries, simplifies environmental assessment requirements and licensing procedures, and provides a more flexible manpower regulations. On November 25, 2021, the Constitutional Court declared the Omnibus Law to be conditionally unconstitutional, and it was subsequently revised and replaced with the issuance of Government Regulation in Lieu of Law No. 2 of 2022 on Job Creation, also known as the new Omnibus Law. Given the extensive breadth of changes introduced by the Omnibus Law, the full impact of various regulation and policy changes on our business and operation in Indonesia are presently unknown and subject to our ongoing review. Therefore, we are subject to the risk that compliance with the Omnibus Law may be challenging and may distract our management, and may also require us to alter operations, which in turn could impact our results of operations.

 

On November 25, 2021, the Constitutional Court through Decision Number 91/PUU-XIII of 2020 declared the Omnibus Law to be “conditionally unconstitutional” and would need rectification. The Omnibus Law shall remain valid until the rectification is made within a period of two years. In response to such decision, on December 30, 2022, the Government of Indonesia enacted Government Regulation In Lieu of Law No. 2 of 2022 on Job Creation (known as GR 2/2022). The previous Omnibus Law is deemed revoked and declared invalid. However, GR2/2022 retains most of the changes and concepts adopted in the Omnibus Law, such as the risk-based licensing process, and all regulations that have been amended by Omnibus Law shall remain valid as long as they are not in contravention of GR 2/2022. Furthermore, any implementing regulations enacted to implement the Omnibus Law also remain valid, as long as it does not contravene GR 2/2022.

 

On March 31, 2023, the House of Representative (Dewan Perwakilan Rakyat or DRP) ratified GR 2/2022 turning it into law (undang-undang) through Law 6/2023. The issuance of Law 6/2023 is expected to harmonize existing legislation and address current legal needs, thereby maintaining the stability of the national economy by providing a clear legal basis for government policies.

 

Current political and social events in Indonesia may adversely affect our business.

 

Since 1998, Indonesia has experienced a process of democratic change, resulting in political and social events that have highlighted the unpredictable nature of Indonesia’s changing political landscape. In 1999, Indonesia conducted its first free elections for representatives in parliament. In 2004, 2009 and 2014, elections were held in Indonesia to elect the President, Vice-President and representatives in parliament. Indonesia also has many political parties, without any one party holding a clear majority. Due to these factors, Indonesia has, from time to time, experienced political instability, as well as general social and civil unrest.

 

 

On February 14, 2024, Indonesia held its most recent election, a pivotal event in the country’s democratic process. The election not only aimed to determine the future leadership but also the direction of the nation. On March 20, 2024, the General Election Commission (Komisi Pemilihan Umum or KPU) finally completed the tabulation of the national vote count. The Prabowo Subianto-Gibran Rakabuming Raka ticket garnered a total of 96,214,691 votes (58.58%). Based on the tabulation of these voting results, the presidential and vice-presidential candidate pair Number 2, Prabowo Subianto and Gibran Rakabuming Raka, emerged victorious in the 2024 presidential election, confirming their position to lead Indonesia.

 

Despite the fraud allegations raised by other presidential candidates, the Constitutional Court has dismissed all claims. Nevertheless, lingering concerns remain regarding the surfaced allegations of election fraud. As the nation prepares for the upcoming swearing-in ceremony in October 2024, uncertainties continue to loom over the political landscape. Therefore, there can be no assurance that social, political and civil disturbances will not occur in the future and on a wider scale, or that any such disturbances will not, directly or indirectly, materially and adversely affect our business, financial condition, results of operations and prospects.

 

Deterioration of political, economic and security conditions in Indonesia may adversely affect our operations and financial results.

 

Any major hostilities involving Indonesia, a substantial decline in the prevailing regional security situation or the interruption or curtailment of trade between Indonesia and its present trading partners could have a material adverse effect on our operations and, as a result, our financial results.

 

Prolonged and/or widespread regional conflict in the South East Asia could have the following results, among others:

 

	●	Capital market reassessment of risk and subsequent redeployment of capital to more stable areas making it more difficult for us to obtain financing for potential development projects;
	●	Security concerns in Indonesia, making it more difficult for our personnel or supplies to enter or exit the country;
	●	Security concerns leading to evacuation of our personnel;
	●	Damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;

 

	●	Inability of our service and equipment providers to deliver items necessary for us to conduct our operations in Indonesia, resulting in delays; and
	●	The lack of availability of drilling rig and experienced crew, oilfield equipment or services if third party providers decide to exit the region.

 

Loss of property and/or interruption of our business plans resulting from hostile acts could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.

 

Terrorist activities in Indonesia could destabilize Indonesia, which would adversely affect our business, financial condition and results of operations, and the market price of our securities.

 

There have been a number of terrorist incidents in Indonesia in the past, including but not limited to the May 2005 bombing in Central Sulawesi, the Bali bombings in October 2002 and October 2005. There is a risk that terrorist incidents may recur and, if serious or widespread, might have a material adverse effect on investment and confidence in, and the performance of, the Indonesian economy and may also have a material adverse effect on our business, financial condition, results of operations and prospects and the market price of our securities.

 

 

Negative changes in global, regional or Indonesian economic activity could adversely affect our business.

 

Changes in the Indonesian, regional and global economies can affect our performance. Two significant events in the past that impacted Indonesia’s economy were the Asian economic crisis of 1997 and the global economic crisis which started in 2008. The 1997 crisis was characterized in Indonesia by, among others, currency depreciation, a significant decline in real gross domestic product, high interest rates, social unrest and extraordinary political developments. While the global economic crisis that arose from the subprime mortgage crisis in the United States did not affect Indonesia’s economy as severely as in 1997, it still put Indonesia’s economy under pressure. The global financial markets have also experienced volatility as a result of expectations relating to monetary and interest rate policies of the United States, concerns over the debt crisis in the Eurozone, and concerns over China’s economic health. Uncertainty over the outcome of the Eurozone governments’ financial support programs and worries about sovereign finances generally are ongoing. If the crisis becomes protracted, we can provide no assurance that it will not have a material and adverse effect on Indonesia’s economic growth and consequently on our business.

 

Adverse economic conditions in Indonesia could result in less business activity, less disposable income available for consumers to spend and reduced consumer purchasing power, which may reduce demand for communication services, including our services, which in turn would have an adverse effect on our business, financial condition, results of operations and prospects. There is no assurance that there will not be a recurrence of economic instability in future, or that, should it occur, it will not have an impact on the performance of our business.

 

Fluctuations in the value of the Indonesian Rupiah may materially and adversely affect us.

 

Although our functional currency is the U.S. Dollar, depreciation and volatility of the Indonesian Rupiah could potentially affect our business. A sharp depreciation of Indonesian Rupiah may potentially create difficulties in purchasing imported goods and services which are critical for our operation. As shown during the Asian monetary crisis in 1998, imported goods became scarce as suppliers often chose to keep their stocks in anticipation of further deterioration of the Indonesian Rupiah.

 

In addition, while the Indonesian Rupiah has generally been freely convertible and transferable, from time to time, Bank Indonesia has intervened in the currency exchange markets in furtherance of its policies, either by selling Indonesian Rupiah or by using its foreign currency reserves to purchase Indonesian Rupiah. We can give no assurance that the current floating exchange rate policy of Bank Indonesia will not be modified or that the Government will take additional action to stabilize, maintain or increase the Indonesian Rupiah’s value, or that any of these actions, if taken, will be successful. Modification of the current floating exchange rate policy could result in significantly higher domestic interest rates, liquidity shortages, capital or exchange controls, or the withholding of additional financial assistance by multinational lenders. This could result in a reduction of economic activity, an economic recession or loan defaults, and as a result, we may also face difficulties in funding our capital expenditures and in implementing our business strategy. Any of the foregoing consequences could have a material adverse effect on our business, financial condition, results of operations and prospects.

 

Downgrades of credit ratings of the Government or Indonesian companies could adversely affect our business.

 

As of the date of this report, Indonesia’s sovereign foreign currency long-term debt was rated “Baa2 (Stable)” by Moody’s, “BBB (Stable)” by Standard & Poor’s and “BBB (Stable)” by Fitch Ratings. Indonesia’s short-term foreign currency debt is rated “A-2” by Standard & Poor’s and “F2” by Fitch Ratings.

 

 

We can give no assurance that Moody’s, Standard & Poor’s or Fitch Ratings will not change or downgrade the credit ratings of Indonesia. Any such downgrade could have an adverse impact on liquidity in the Indonesian financial markets, the ability of the Government and Indonesian companies, including us, to raise additional financing, and the interest rates and other commercial terms at which such additional financing is available. Interest rates on our floating rate Rupiah-denominated debt would also likely increase. Such events could have material adverse effects on our business, financial condition, results of operations, prospects and/or the market price of our securities.

 

Indonesia is vulnerable to natural disasters and events beyond our control, which could adversely affect our business and operating results.

 

Many parts of Indonesia, including areas where we operate, are prone to natural disasters such as floods, lightning strikes, cyclonic or tropical storms, earthquakes, volcanic eruptions, droughts, power outages and other events beyond our control. The Indonesian archipelago is one of the most volcanically active regions in the world as it is located in the convergence zone of three major lithospheric plates. It is subject to significant seismic activity that can lead to destructive earthquakes, tsunamis or tidal waves. Flash floods and more widespread flooding also occur regularly during the rainy season from November to April. Cities, especially Jakarta, are frequently subject to severe localized flooding which can result in major disruption and, occasionally, fatalities. Landslides regularly occur in rural areas during the wet season. From time to time, natural disasters have killed, affected or displaced large numbers of people and damaged our equipment. We cannot assure you that future natural disasters, such as the spread of the novel coronavirus, will not have a significant impact on us, or Indonesia or its economy. A significant earthquake, other geological disturbance or weather-related natural disaster in any of Indonesia’s more populated cities and financial centers could severely disrupt the Indonesian economy and undermine investor confidence, thereby materially and adversely affecting our business, financial condition, results of operations and prospects.

 

We may be affected by uncertainty in the balance of power between local governments and the central government in Indonesia.

 

The structural and functional relationships between the central and local governments in Indonesia are guided by the principles of decentralization and regional autonomy. These principles are outlined in Law No. 23 of 2014 regarding Regional Autonomy, which was most recently amended by Law 6/2023, along with Law No. 1 of 2022 concerning Fiscal Relations between Central and Regional Governments.

 

However, currently, there is uncertainty in respect of the balance between the local and the central governments and the procedures for renewing licenses and approvals and monitoring compliance with environmental regulations. In addition, some local authorities have sought to levy additional taxes or obtain other contributions. There can be no assurance that a balance between local governments and the central government will be effectively established or that our business, financial condition, results of operations and prospects will not be adversely affected by dual compliance obligations and further uncertainty as to legal authority to levy taxes or promulgate other regulations affecting our business.

 

Failure to comply with the U.S. Foreign Corrupt Practices Act of 1977 (or FCPA) could result in fines, criminal penalties, and an adverse effect on our business.

 

We operate in Indonesia, which is a jurisdiction known to be challenged by corruption. As such, we are subject, however, to the risk that we, our affiliated entities or our or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the FCPA. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our management.

 

 

Risks Related to Our Corporate Structure

 

We are a holding company, with all of our operations conducted through our operating subsidiaries in Indonesia. Should our operations generate positive cash flows in the future, and should we desire to cause our operating subsidiaries to make dividends or distributions to our parent company in the future, limitations on the ability of our subsidiaries to do so, or any tax implications of doing so, could limit our ability to pay our parent company expenses or pay dividends to holders of our ordinary shares.

 

We are a holding company and conduct substantially all of our business through our operating subsidiaries, which are limited liability companies established in Indonesia. Should our operations generate positive cash flows in the future, and should we desire to cause our operating subsidiaries to make dividends or distributions to our parent company in the future, we might be limited in our ability to do so for regulatory or tax reasons. If applicable laws, rules and regulations in Indonesia or Hong Kong (where our holding subsidiary WJ Energy is domiciled) in the future limit or preclude our Indonesian subsidiaries from making dividends to us, our ability to fund our holding company obligations or pay dividends on our ordinary shares could be materially and adversely affected. In addition, we may also enter into debt arrangements in the future which limit our ability to receive dividends or distributions from our operating subsidiaries or pay dividends to the holders of our ordinary shares. Indonesian, Hong Kong or Cayman Island tax laws, rules and regulations may also limit our future ability to receive dividends or distributions from our operating subsidiaries or pay dividends to the holders of our ordinary shares.

 

We may become subject to taxation in the Cayman Islands which would negatively affect our results of operations.

 

We have received an undertaking from the Financial Secretary of the Cayman Islands that, in accordance with section 6 of the Tax Concessions Act (Revised) of the Cayman Islands, until the date falling 20 years after November 2, 2018, being the date of such undertaking, no law which is enacted in the Cayman Islands imposing any tax to be levied on profits, income, gains or appreciations shall apply to us or our operations and, in addition, that no tax to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable (i) on or in respect of the shares, debentures or other obligations of our company or (ii) by way of the withholding in whole or in part of a payment of any “relevant payment” as defined in section 6(3) of the Tax Concessions Act (Revised). If we otherwise were to become subject to taxation in the Cayman Islands, our financial condition and results of operations could be materially and adversely affected. See “Taxation—Cayman Islands Taxation.”

 

You may face difficulties in protecting your interests, and your ability to protect your rights through the U.S. Federal courts may be limited, as a result of our company being incorporated under the laws of the Cayman Islands.

 

We are a Cayman Islands exempted company with limited liability and substantially all of our assets will be located outside the United States. In addition, most of our directors and officers are nationals or residents of jurisdictions other than the United States and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors to effect service of process within the United States upon us or our directors or executive officers, or enforce judgments obtained in the United States courts against us or our directors or officers.

 

Further, mail addressed to us and received at our registered office will be forwarded unopened to the forwarding address supplied by our directors. Our directors will only receive, open or deal directly with mail which is addressed to them personally (as opposed to mail which is only addressed to us). We, our directors, officers, advisors or service providers (including the organization which provides registered office services in the Cayman Islands) will not bear any responsibility for any delay, howsoever caused, in mail reaching this forwarding address.

 

Our corporate affairs are governed by our amended and restated memorandum and articles of association, the Companies Law (Revised) (as the same may be supplemented or amended from time to time) and the common law of the Cayman Islands. The rights of shareholders to take action against the directors, actions by minority shareholders and the fiduciary responsibilities of our directors to us under Cayman Islands law are to a large extent governed by the common law of the Cayman Islands. The common law of the Cayman Islands is derived in part from judicial precedent in the Cayman Islands as well as from English common law, the decisions of whose courts are of persuasive authority, but are not technically binding on a court in the Cayman Islands. The rights of our shareholders and the fiduciary responsibilities of our directors under Cayman Islands law are not as clearly established as they would be under statutes or judicial precedent in some jurisdictions in the United States. In particular, the Cayman Islands has a less developed body of securities laws as compared to the United States, and certain states, such as Delaware, have more fully developed and judicially interpreted bodies of corporate law. As a result, there may be significantly less protection for investors than is available to investors in companies organized in the United States, particularly Delaware. In addition, Cayman Islands companies may not have standing to initiate a shareholders derivative action in a Federal court of the United States.

 

 

The Cayman Islands courts are also unlikely:

 

	●	To recognize or enforce against us judgments of courts of the United States based on certain civil liability provisions of United States securities laws; and
	●	To impose liabilities against us, in original actions brought in the Cayman Islands, based on certain civil liability provisions of United States securities laws that are penal in nature.

 

There is no statutory recognition in the Cayman Islands of judgments obtained in the United States, although the courts of the Cayman Islands will in certain circumstances recognize and enforce a non-penal judgment of a foreign court of competent jurisdiction without retrial on the merits. The Grand Court of the Cayman Islands may stay proceedings if concurrent proceedings are being brought elsewhere.

 

Like many jurisdictions in the United States, Cayman Islands law permits mergers and consolidations between Cayman Islands companies and between Cayman Islands companies and non-Cayman Islands companies and any such company may be the surviving entity for the purposes of mergers or the consolidated company for the purposes of consolidations. For these purposes, (a) “merger” means the merging of two or more constituent companies and the vesting of their undertaking, property and liabilities in one of such companies as the surviving company and (b) a “consolidation” means the combination of two or more constituent companies into a consolidated company and the vesting of the undertaking, property and liabilities of such companies to the consolidated company. In order to effect such a merger or consolidation, the directors of each constituent company must approve a written plan of merger or consolidation, which must, in most instances, then be authorized by a special resolution of the shareholders of each constituent company and such other authorization, if any, as may be specified in such constituent company’s articles of association. A merger between a Cayman parent company and its Cayman subsidiary or subsidiaries does not require authorization by a resolution of shareholders. For this purpose a subsidiary is a company of which at least 90% of the votes cast at its general meeting are held by the parent company. The consent of each holder of a fixed or floating security interest over a constituent company is required unless this requirement is waived by a court in the Cayman Islands. The plan of merger or consolidation must be filed with the Registrar of Companies together with a declaration as to the solvency of the consolidated or surviving company, a list of the assets and liabilities of each constituent company and an undertaking that a copy of the certificate of merger or consolidation will be given to the members and creditors of each constituent company and published in the Cayman Islands Gazette. Dissenting shareholders have the right to be paid the fair value of their shares (which, if not agreed between the parties, will be determined by the Cayman Islands court) if they follow the required procedures, subject to certain exceptions. Court approval is not required for a merger or consolidation which is effected in compliance with these statutory procedures.

 

In addition, there are statutory provisions that facilitate the reconstruction and amalgamation of companies, provided that the arrangement is approved by a majority in number of each class of shareholders and creditors with whom the arrangement is to be made, and who must in addition represent three-fourths in value of each such class of shareholders or creditors, as the case may be, that are present and voting either in person or by proxy at a meeting, or meetings, convened for that purpose. The convening of the meetings and subsequently the arrangement must be sanctioned by the Grand Court of the Cayman Islands. While a dissenting shareholder has the right to express to the court the view that the transaction ought not be approved, the court can be expected to approve the arrangement if it determines that:

 

	●	The statutory provisions as to the required majority vote have been met;
	●	The shareholders have been fairly represented at the meeting in question, the statutory majority are acting bona fide without coercion of the minority to promote interests adverse to those of the class and that the meeting was properly constituted;
	●	The arrangement is such that it may reasonably be approved by an intelligent and honest man of that share class acting in respect of his interest; and
	●	The arrangement is not one which would be more properly sanctioned under some other provision of the Companies Act.

 

 

If the arrangement and reconstruction is approved, the dissenting shareholder would have no rights comparable to appraisal rights, which would otherwise ordinarily be available to dissenting shareholders of U.S. corporations, providing rights to receive payment in cash for the judicially determined value of the shares.

 

In addition, there are further statutory provisions to the effect that, when a take-over offer is made and approved by holders of 90.0% in value of the shares affected (within four months after the making of the offer), the offeror may, within two months following the expiry of such period, require the holders of the remaining shares to transfer such shares on the terms of the offer. An objection can be made to the Grand Court of the Cayman Islands, but this is unlikely to succeed unless there is evidence of fraud, bad faith, collusion or inequitable treatment of shareholders.

 

As a result of all of the above, public shareholders may have more difficulty in protecting their interests in the face of actions taken by management, members of our board of directors or controlling shareholders than they would as public shareholders of a U.S. company.

 

Provisions of our charter documents or Cayman Islands law could delay or prevent an acquisition of our company, even if the acquisition may be beneficial to our shareholders, could make it more difficult for you to change management, and could have an adverse effect on the market price of our ordinary shares.

 

Provisions in our amended and restated memorandum and articles of association may discourage, delay or prevent a merger, acquisition or other change in control that shareholders may consider favorable, including transactions in which shareholders might otherwise receive a premium for their shares. In addition, these provisions may frustrate or prevent any attempt by our shareholders to replace or remove our current management by making it more difficult to replace or remove our board of directors. Such provisions may reduce the price that investors may be willing to pay for our ordinary shares in the future, which could reduce the market price of our ordinary shares. These provisions include:

 

	●	A requirement that extraordinary general meetings of shareholders be called only by the directors or, in limited circumstances, by the directors upon shareholder requisition;
	●	An advance notice requirement for shareholder proposals and nominations to be brought before an annual general meeting;
	●	The authority of our board of directors to issue preferred shares with such terms as our board of directors may determine; and
	●	A requirement of approval of not less than 66 2/3% of the votes cast by shareholders entitled to vote thereon in order to amend any provisions of our amended and restated memorandum and articles of association.

 

We may be classified as a passive foreign investment company, which could result in adverse U.S. federal income tax consequences to U.S. holders of our ordinary shares.

 

A foreign corporation will be treated as a “passive foreign investment company” (or PFIC) for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets produce or are held for the production of those types of “passive income”. For purposes of these tests, “passive income” includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business. U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale of other disposition of their shares in the PFIC.

 

 

Based upon our current and anticipated method of operations, we do not believe that we should be a PFIC with respect to our 2023 taxable year, and we do not expect to become a PFIC in any future taxable year. However, no assurance can be given that the U.S. Internal Revenue Service (or IRS) or a court of law will accept this position, and there is a risk that the IRS or a court of law could determine that we are a PFIC. Moreover, no assurance can be given that we would not constitute a PFIC for any future taxable year if the nature and extent of our operations change.

 

If the IRS were to find that we are or have been a PFIC for any taxable year, our U.S. shareholders would face adverse U.S. federal income tax consequences and certain information reporting requirements. Under the PFIC rules, unless those shareholders make an election available under the United States Internal Revenue Code of 1986 as amended (or the Code) (which election could itself have adverse consequences for such shareholders), such shareholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of their shares of our ordinary shares, as if the excess distribution or gain had been recognized ratably over the shareholder’s holding period of the shares of our ordinary shares.

 

The future development of national security laws and regulations in Hong Kong could impact our Hong Kong holding subsidiary. 

 

WJ Energy is our wholly-owned holding company subsidiary which is incorporated in Hong Kong. On June 30, 2020, the Hong Kong Special Administrative Region of the People’s Republic of China implemented a new national security law. The implementation of the national security law and its development may trigger sanctions or other forms of penalties by foreign governments, which may cause economic and other hardship for Hong Kong, including companies such as WJ Energy. As of the date of this annual report, we are not aware of any restrictions under this law that would preclude the transfer of corporate funds of our company through WJ Energy, nor have there been any sanctions or any forms of penalties imposed by foreign governments related to the Hong Kong national security law that would impact WJ Energy. However, it is difficult to predict the impact in the future, if any, that the national security law or similar measures will have on WJ Energy, including, without limitation, the ability of WJ Energy to pay dividends or make distributions to our company, as such impact will depend on future developments, which are highly uncertain and cannot be predicted. Any restrictions or limitations on funds passing through WJ Energy could have a material adverse effect on our ability to finance our operations in accordance with our past and current practices.

 

 

Risks Related to Our Ordinary Shares

 

Our 2022 financing with L1 Capital Global Opportunities Master Fund, Ltd. (“L1 Capital”) could cause dilution and pressure on the public price of our ordinary shares as the outstanding warrants can be exercised at discounted price to market.

 

Any exercise by L1 Capital of the warrants that were issued to them in connection with our January 2022 financing will cause dilution to shareholders since it is likely that those warrants will only be exercise at a discount to the prevailing market price. Moreover, the ordinary shares underlying the L1 Capital warrants have been registered for resale pursuant to a Registration Statement on Form F-1 filed with the SEC on March 9, 2022, as amended (the “L1 Registration Statement”), effective June 1, 2022. After the L1 Registration Statement was declared effective, L1 Capital commenced sales of such shares in the public market. Any future such sales could cause pressure on the public price of our ordinary shares and could force such price downwards, perhaps significantly. During the year ended December 31, 2022, $9,900,000 of the total $10,000,000 principal amount of the convertible notes were converted into ordinary shares at $6.00 per share at L1 Capital’s election and 325,000 of the total 767,240 warrants were exercised. During the year ended December 31, 2023, the remaining $100,000 principal amount of the convertible notes were fully repaid and no warrants were exercised. As of the date of this report, there are still certain warrants outstanding under the L1 Capital financing, which will cause dilution and pressure on the price of our ordinary shares and affect your investment in us.

 

The market for our ordinary shares has been volatile, and an active, liquid and orderly trading market for our ordinary shares may not be maintained in the United States, which could limit your ability to sell our ordinary shares.

 

The market for our ordinary shares has been volatile, with times of significant trading volume and times of minimal trading volume. Although our ordinary shares are listed on the NYSE American, an active, liquid and orderly U.S. public market for our ordinary shares may not be achieved or sustained, and the market for our ordinary shares may remain unpredictable. If an active, liquid and orderly market is not sustained, you may experience difficulty selling your ordinary shares. Moreover, the price of our publicly-listed shares has been subject to significant price fluctuations, which creates the risk of loss of your investment in our ordinary shares.

 

Our ordinary share price has been and may in the future be volatile and, as a result, you could lose a significant portion or all of your investment.

 

The market price of our ordinary shares on the NYSE American has fluctuated, and may in the future fluctuate (in each case to a significant extent), as a result of several factors, including the following:

 

	●	Fluctuations in oil and other commodity prices (including but not limited to as a result of external events such as the Russia-Ukraine war and the Israel-Hamas war);
	●	Volatility in the energy industry, both in Indonesia and internationally;
	●	Variations in our operating results;
	●	Risks relating to our business and industry, including those discussed above;
	●	Strategic actions by us or our competitors;
	●	Reputational damage from accidents or other adverse events related to our company or its operations;
	●	Investor perception of us, the energy sector in which we operate, the investment opportunity associated with the ordinary shares and our future performance;
	●	Addition or departure of our executive officers or directors;
	●	Changes in financial estimates or publication of research reports by analysts regarding our ordinary shares, other comparable companies or our industry generally;
	●	Trading volume of our ordinary shares;
	●	Future sales of our ordinary shares by us or our shareholders;
	●	Domestic and international economic, legal and regulatory factors unrelated to our performance; or
	●	The release or expiration of lock-up or other transfer restrictions on our outstanding ordinary shares.

 

 

Furthermore, the stock markets often experience significant price and volume fluctuations that have affected and continue to affect the market prices of equity securities of many companies. These fluctuations often have been unrelated or disproportionate to the operating performance of those companies. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions or interest rate changes may cause the market price of ordinary shares to decline.

 

We may not be able to maintain the listing of our ordinary shares on the NYSE American, which could adversely affect our liquidity and the trading volume and market price of our ordinary shares, and decrease the value of your investment.

 

Our ordinary shares are currently traded on the NYSE American. In order to maintain our NYSE American listing, we must maintain certain share price, financial and share distribution targets, including maintaining a minimum amount of shareholders’ equity and a minimum number of public shareholders. In addition to these objective standards, the NYSE American may delist the securities of any issuer (i) if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; (ii) if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; (iii) if the issuer sells or disposes of principal operating assets or ceases to be an operating company; (iv) if an issuer fails to comply with the NYSE American’s listing requirements; (v) if an issuer’s securities sell at what the NYSE American considers a “low selling price” and the issuer fails to correct this via a reverse split of shares after notification by the NYSE American; or (vi) if any other event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable. If the NYSE American delists either our ordinary shares, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.

 

We require significant capital to realize our business plan.

 

Our ongoing work program is expensive, and we will require significant additional capital in order to fully realize our business plan. This is particularly true because we raised less funding than we had anticipated in our December 2019 initial public offering.

 

We cannot assure you that our actual cash requirements will not exceed our estimates. Even if we were to discover be successful in our exploration operations, we will require additional financing to bring our interests into commercial operation and pay for operating expenses until we achieve a positive cash flow. Additional capital also may be required in the event we incur any significant unanticipated expenses.

 

Under the current capital and credit market conditions, we may not be able to obtain additional equity or debt financing on acceptable terms. Even if financing is available, it may not be available on terms that are favorable to us or in sufficient amounts to satisfy our requirements.

 

If we are unable to obtain additional financing, we may be unable to implement our business plan and our growth strategies, respond to changing business or economic conditions and withstand adverse operating results. If we are unable to raise further financing when required, our planned production and exploration activities may have to be scaled down or even ceased, and our ability to generate revenues in the future would be negatively affected.

 

Additional financing could cause your relative interest in our assets and potential earnings to be significantly diluted. Even if we have success, we may not be able to generate sufficient revenues to offset the cost of our operational plans and administrative expenses.

 

An entity controlled by our Chairman owns a substantial majority of our ordinary shares and voting power.

 

Maderic Holding Limited, an entity controlled by our Chairman Wirawan Jusuf (or Maderic), owns and exercises voting and investment control of approximately 51.34% of our ordinary shares as of the date of this report. As a result of this concentration of share ownership, investors may be prevented from affecting matters involving our company, including:

 

	●	Fluctuations in oil and other commodity prices;
	●	Volatility in the energy industry, both in Indonesia and internationally;
	●	Variations in our operating results;
	●	Risks relating to our business and industry, including those discussed above;

 

 

Furthermore, this concentration of voting power could have the effect of delaying, deterring or preventing a change of control or other business combination that might otherwise be beneficial to our shareholders. This significant concentration of share ownership may also adversely affect the trading price for our ordinary shares because investors may perceive disadvantages in owning shares in a company that is controlled by a company insider. This concentration of ownership could also create conflicts of interests for Dr. Jusuf that may not be resolved in a manner that all shareholders agree with.

 

We have identified a material weakness in our internal control over financial reporting for the year ended December 31, 2023. If we fail to adequately remediate this weakness or otherwise develop and maintain an effective system of internal control over financial reporting, or if we experience additional material weaknesses in the future, we may be unable to accurately report our financial results or prevent fraud, or comply with the accounting and reporting requirements applicable to public companies, which may adversely affect investor confidence in us and the market price of our shares.

 

We have identified a material weakness in our internal control over financial reporting for the year ended December 31, 2023. As defined in the standards established by the Public Company Accounting Oversight Board of the United States (“PCAOB”), a “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

 

In connection with the audits of our consolidated financial statements for the years ended December 31, 2023 and 2022, a material weakness that have been identified in our internal control over financial reporting as of such dates related to our lack of sufficient financial reporting and accounting personnel with appropriate knowledge of U.S. GAAP and SEC reporting requirements to properly address complex U.S. GAAP accounting issues and to prepare and review our consolidated financial statements and related disclosures to fulfill U.S. GAAP and SEC financial reporting requirements. We have implemented and are continuing to implement a number of measures to address the material weakness identified. As a result of the material weakness, our management has concluded that as of December 31, 2023, our disclosure controls and procedures were ineffective in ensuring that the information required to be disclosed by us in this annual report is recorded, processed, summarized and reported to them for assessment, and that the required disclosure is made within the time period specified in the rules and forms of the SEC. We cannot assure you that we will be able to continue to implement an effective system of internal control, or that we will not identify additional material weaknesses or significant deficiencies in the future.

 

We are subject to the Sarbanes-Oxley Act of 2002. Section 404 of the Sarbanes-Oxley Act, or Section 404, requires that we include a report from management on the effectiveness of our internal control over financial reporting in this report. In addition, once we cease to be an “emerging growth company” as such term is defined under the JOBS Act, our independent registered public accounting firm must attest to and report on the effectiveness of our internal control over financial reporting. Our management may conclude that our internal control over financial reporting is not effective. Moreover, even if our management concludes that our internal control over financial reporting is effective, our independent registered public accounting firm, after conducting its own independent testing, may issue a report that it is not satisfied with our internal controls or the level at which our controls are documented, designed, operated or reviewed. In addition, as we are a public company, our reporting obligations may place a significant strain on our management, operational and financial resources and systems on an ongoing basis. We may be unable to timely complete our evaluation testing and any required remediation.

 

During the course of documenting and testing our internal control procedures, in order to satisfy the requirements of Section 404, we may identify other weaknesses and deficiencies in our internal control over financial reporting. In addition, if we fail to develop and maintain the adequacy of our internal control over financial reporting, as these standards are modified, supplemented or amended from time to time, we may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404. If we fail to achieve and maintain an effective internal control environment, we could suffer material misstatements in our financial statements and fail to meet our reporting obligations, which would likely cause investors to lose confidence in our reported financial information. This could in turn limit our access to capital markets, harm our results of operations, and lead to a decline in the trading price of our ordinary shares. Additionally, ineffective internal control over financial reporting could expose us to increased risk of fraud or misuse of corporate assets and subject us to potential delisting from the stock exchange on which we list, regulatory investigations and civil or criminal sanctions. We may also be required to restate our financial statements from prior periods, which would further damage our reputation and likely adversely impact our share price.

 

 

As a foreign private issuer, we are subject to different U.S. securities laws and NYSE American governance standards than domestic U.S. issuers. This may afford less protection to holders of our ordinary shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it.

 

As a “foreign private issuer” for U.S. securities laws purposes, the rules governing the information that we will be required to disclose differ materially from those governing U.S. corporations pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The periodic disclosure required of foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. For example, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly (should we provide them) or current reports may contain less or different information than required under U.S. filings. In addition, as a foreign private issuer, we are exempt from the proxy rules under Section 14 of the Exchange Act, and proxy statements that we distribute are not subject to review by the SEC. Our exemption from Section 16 rules under the Exchange Act regarding sales of ordinary shares by our insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. Also, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales of our ordinary shares.

 

Moreover, as a foreign private issuer, we are exempt from complying with certain corporate governance requirements of the NYSE American applicable to a U.S. issuer, including the requirement that a majority of our board of directors consist of independent directors. For example, we follow Cayman Islands law with respect to the requirements for meetings of our shareholders, which are different from the requirements of the NYSE American. Additionally, in January 2022 in connection with our financing with L1 Capital, we formally adopted home country practice and thereby opted out of the NYSE American rule that would otherwise require shareholder approval should we issue more than 19.99% of our then outstanding ordinary shares in a financing that is not a “public offering” at less than the then current market value; and in December 2023, we adopted home country practice and opted out of the NYSE American rule that would otherwise require each issuer listing common stock or voting preferred stock, and/or their equivalents, to hold an annual meeting of shareholders no later than one year after the end of the issuer’s fiscal year. As the corporate governance standards applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under U.S. law and the NYSE American rules as shareholders of companies that do not have such exemptions.

 

Other future issuances and sales of additional ordinary shares could cause dilution of ownership interests and adversely affect our share price.

 

Beyond our ATM financing with the Sales Agent, we may choose to raise additional capital due to market conditions or strategic considerations even if we believe we have sufficient funds for our current or future operating plans. To the extent that additional capital is raised through the sale of equity or convertible debt securities, the issuance of these securities could result in further dilution to our stockholders or result in downward pressure on the price of our ordinary shares.

 

Shares eligible for future, including as a result of our financing with the Sales Agent, sale may depress our stock price.

 

As of April 23, 2024, we had 10,202,694 ordinary shares outstanding, 5,464,402 of which were held by our officers, directors and affiliates. In addition, 200,000 ordinary shares are subject to outstanding options granted under certain stock option agreements entered into with our management team. All of the ordinary shares held by affiliates (notably Maderic, which is controlled by our Chairman) are restricted or control securities under Rule 144 promulgated under the Securities Act. Our affiliates may, subject to compliance with applicable law, choose to sell ordinary shares held by them. Sales of these ordinary shares under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the ordinary shares and could impair our ability to raise additional capital through the sale of equity securities.

 

 

On July 22, 2022, we entered into an At The Market Offering Agreement (the “ATM Agreement”) with the Sales Agent, pursuant to which we may offer and sell, from time to time, to or through the Sales Agent, ordinary shares (the “ATM Shares”) having an aggregate gross offering price of up to $20,000,000. Under the ATM Agreement, the ATM Shares, if offered and sold by us, will be offered and sold pursuant to a prospectus dated February 16, 2021 and a prospectus supplement, dated July 22, 2022, that form a part of our shelf registration statement on Form F-3 (File No. 333-252520), which registration statement was declared effective by the SEC on February 16, 2021 (“Prior Registration Statement”). On August 25, 2022, we sold 177,763 ATM Shares at $10.7407 per share for net proceeds (after Sales Agent commissions) of $1,801,193. On August 25, 2022, we sold an additional 280,612 ATM Shares at $10.1090 per share for net proceeds (after Sales Agent commissions) of $2,750,449. As of December 31, 2023, there are no ATM Shares sold under the ATM Agreement. On March 22, 2024, we filed a new shelf registration statement on Form F-3 (the “New F-3 Registration Statement”, File No. 333-278175), which includes a Prospectus Supplement and a base prospectus supplemented by the Prospectus Supplement, covering (i) the offering, issuance and sale by us of up to a maximum aggregate offering price of $50,000,000 of our ordinary shares, preferred shares, warrants, debt securities, rights, depositary shares, and/or units from time to time in one or more offerings, and (ii) up to a maximum aggregate offering price of $4,267,622 of our ordinary shares that may be issued and sold from time to time under the ATM Agreement, as amended by the First Amendment to the ATM Agreement (“ATM Amendment No.1”) on March 22, 2024, with Sales Agent. We are not permitted to sell any ATM Shares prior to the effectiveness of the New F-3 Registration Statement. As of the date of this report, the New F-3 Registration Statement has not been declared effective. The sales of such ATM Shares could also have a material adverse effect on the price of our ordinary shares.

 

We may issue preferred shares with greater rights than our ordinary shares.

 

Our amended articles of association authorize our board of directors to issue one or more series of preferred shares and set the terms of the preferred shares without seeking any further approval from our shareholders. Any preferred shares that are issued may rank ahead of our ordinary shares, in terms of dividends, liquidation rights and voting rights.

 

If securities or industry analysts do not publish or cease publishing research reports about us, if they adversely change their recommendations regarding our ordinary shares or if our operating results do not meet their expectations, the price of our ordinary shares could decline.

 

The trading market for our ordinary shares will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. Securities and industry analysts currently publish limited research on us. If there is limited or no securities or industry analyst coverage of our company, the market price and trading volume of our ordinary shares would likely be negatively impacted. Moreover, if any of the analysts who may cover us downgrade our ordinary shares, provide more favorable relative recommendations about our competitors or if our operating results or prospects do not meet their expectations, the market price of our ordinary shares could decline. If any of the analysts who may cover us were to cease coverage or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our share price or trading volume to decline.

 

As an “emerging growth company” under the JOBS Act, we are allowed to postpone the date by which we must comply with some of the laws and regulations intended to protect investors and to reduce the amount of information we provide in our reports filed with the SEC, which could undermine investor confidence in our company and adversely affect the market price of our ordinary shares.

 

For so long as we remain an “emerging growth company” as defined in the JOBS Act, we intend to take advantage of certain exemptions from various requirements that are applicable to public companies that are not “emerging growth companies” including:

 

	●	Not being required to comply with the auditor attestation requirements for the assessment of our internal control over financial reporting provided by Section 404 of the Sarbanes-Oxley Act of 2002;
	●	Not being required to comply with any requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and our financial statements;
	●	Reduced disclosure obligations regarding executive compensation; and
	●	Not being required to hold a nonbinding advisory vote on executive compensation or seek shareholder approval of any golden parachute payments not previously approved.

 

 

We intend to take advantage of these exemptions until we are no longer an “emerging growth company.” We will remain an emerging growth company until the earlier of: (1) the last day of the fiscal year (a) following the fifth anniversary of the completion of our initial public offering, (b) in which we have total annual gross revenue of at least $1.235 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our ordinary shares that is held by non-affiliates exceeds $700 million as of the prior June 30, and (2) the date on which we have issued more than $1 billion in non-convertible debt during the prior three-year period.

 

Because the likelihood of paying cash dividends on our ordinary shares is remote at this time, investors must look solely to appreciation of our ordinary shares in the market to realize a gain on their investments.

 

We do not know when or if we will pay dividends to our shareholders, and the likelihood that we will be paying dividends on our ordinary is remote at this time. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. Accordingly, investors must look solely to appreciation of our ordinary shares in the market to realize a gain on their investment. This appreciation may not occur.

 

ITEM 4. INFORMATION ON THE COMPANY

 

Overview and History and Development of the Company

 

Indonesia Energy Corporation Limited is an oil and gas exploration and production company focused on Indonesia. Alongside operational excellence, we believe we have set the highest standards for ethics, safety and corporate social responsibility practices to ensure that we add value to society. Led by a professional management team with extensive oil and gas experience, we seek to bring forth the best of our expertise to ensure the sustainable development of a profitable and integrated energy exploration and production business model.

 

We currently have rights through contracts with the Government to one oil and gas producing block (Kruh Block) and one oil and gas exploration block (Citarum Block). We may seek to acquire or otherwise obtain rights to additional oil and gas producing assets.

 

We produce oil through PT Green World Nusantara (“GWN”), our indirect wholly-owned subsidiary which operates the Kruh Block under an agreement with PT Pertamina (Persero), the Indonesian state-owned oil and gas company (“Pertamina”). Our operatorship Kruh Block previously ran until May 2030 under a ten-year Operations Cooperation Agreement, known as Joint Operation Partnership (the “KSO”), between GWN and Pertamina. Kruh Block covers an area of 258 km2 (63,753 acres) and is located onshore 16 miles northwest of Pendopo, Pali, South Sumatra. In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed an amendment to the KSO (the “Amended KSO”) that moved the expiration date of our operatorship of Kruh Block to September 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%.

 

Our mission is to efficiently manage targeted profitable energy resources in Indonesia. Our vision is to be a leading company in the Indonesian oil and gas industry for maximizing hydrocarbon recovery with the minimum environmental and social impact possible.

 

We were incorporated on April 24, 2018 as an exempted company with limited liability under the laws of the Cayman Islands and are a holding company for WJ Energy Group Limited (or WJ Energy), which in turn owns our Indonesian holding and operating subsidiaries.

 

Indonesia’s Oil and Gas Industry and Economic Information

 

The largest economy in Southeast Asia, Indonesia (located between the Indian and Pacific oceans and bordered by Malaysia, Singapore, East Timor and Papua New Guinea) has charted impressive economic growth since overcoming the Asian financial crisis of the late 1990s. According to the Word Bank, Indonesia experienced resilient growth of 5.0 percent in 2023 with inflation on a declining trend and a stable currency, with growth expected to be maintained on average at 4.9 percent over the medium term between 2024 and 2026. Indonesia has the world’s 7^th largest economy, is a member of the G-20 and is the world’s fourth most populous nation with an estimated 2023 population of over 279 million according to the Central Intelligence Agency’s World Factbook. Indonesia also has a prominent presence in other commodities markets such as thermal coal, copper, gold and tin, with Indonesia being the world’s second largest tin producer and largest tin exporter, as well as in the agriculture industry as a producer of rice, palm oil, coffee, medicinal plants, spices and rubber according to the Indonesia Commodity & Derivatives Exchange and the World Factbook.

 

 

The Indonesian oil and gas industry is among the oldest in the world. Indonesia has been active in the oil and gas sector for over 130 years after its first oil discovery in North Sumatra in 1885. The major international energy companies began their significant exploration and development operations in the mid-20^th century. According to the Special Taskforce for Upstream Oil and Gas Business Activities (SKK Migas - Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi) Company Profile 2023, Indonesia held proven oil reserves of 4.17 billion barrels in July 2023. According to its public filings, Chevron has been very active in Indonesia for over 50 years. Chevron has produced a very large amount of oil — 12 billion barrels — over this period with billions of those barrels having been produced in Sumatra (the location of our Kruh Block, as described below. The following map shows the area in which international major companies operate within Indonesia:

 

The following map shows the area in which international major companies operate within Indonesia:

 

 

Source: Indonesia Energy Corporation Limited

 

Indonesia’s early entry into the energy industry helped the country become a global pioneer in developing a legal, commercial and financial framework to support a very stable, growing industry that encouraged the hundreds of billions of dollars made in investment. The Indonesian energy industry was the model of the global industry, having been the founder of the model form of PSC which is still used around the world as a preferred contract form; and this is the form of contract under which we operate our Citarum Block, as described below.

 

 

 

Indonesia’s oil and gas sector is governed by Law No. 22 of 2001 regarding Oil and Gas (November 22, 2001) as amended by Law 6/2023 (or the Oil and Gas Law). The Government retains mineral rights throughout Indonesian territory and the government controls the state mining authority. The oil and gas sector is comprised of upstream (namely exploration and production) and downstream activities (namely refining and processing), which are separately regulated and organized. The upstream sector is managed and supervised by SKK Migas. Private companies earn the right to explore and exploit oil and gas resources by entering into cooperation contracts, mainly based upon a production sharing scheme, with the government through SKK Migas, thus acting as a contractor to SKK Migas. One entity can hold only one PSC, and a PSC is normally granted for 30 years, typically comprising six plus four years of exploration and 20 years of exploitation.

 

The oil and gas industry, however, both in Indonesia and globally, has experienced significant volatility in the last four years. Global geopolitical and economic considerations play a significant role in driving the sensitivity of oil prices. From its peak in mid-2014 (US$105.72 per barrel), the Indonesia Crude Price (the “ICP”) for the type of crude oil we produce collapsed to an average price of US$37.58 per barrel for the year ended December 31, 2020 due to COVID-19 but rose again to reach a yearly average price of US$96.94 per barrel in 2022, 45% higher than 2021 yearly average price of US$67.02 per barrel. For the year ended December 31, 2023, the average Indonesia Crude Price was US$77.61 per barrel. According to the International Energy Agency (“IEA”) December 2023 Oil Market Report, world oil demand is on track to rise 2.3 mb/d to 101.7 mb/d in 2023, but this masks the impact of a further weakening of the macroeconomic climate. Global 4Q23 demand growth has been revised down by almost 400 kb/d, with Europe making up more than half the decline. The slowdown is set to continue in 2024, with global gains halving to 1.1 mb/d, as GDP growth stays below trend in major economies.

 

Since the decline of oil price at over $100 in July 2022, Brent oil price remains relatively stable around $80 except for a spike of $93.72 in September 2023 when Saudi Arabia and Russia decided to extend the output cut of 1.3 mb/d. The average ICP in 2022 was $96.94 while the average ICP in 2023 was $77.61. Although the regional conflicts of the ongoing Russia-Ukraine war and Israel-Hamas war may potentially result in an oil price exceeding $100, we expect the oil price is likely to remain around $80 per barrel in 2024 and 2025 because of the relatively balanced supply and demand.

 

The problem of a lack of new reserve discoveries and reserve depletion still remains, resulting in a decline in the contribution to state revenue from the Indonesian oil and gas sector. According to an article titled “Oil and Gas in Indonesia: Investment and Taxation Guide 2023” released on pwc.com, in 2022, investment in the oil and gas industry in Indonesia increased to $12.3 billion for the upstream sector, or 93% of the $13.2 billion target. On a gas reserve basis, as stated in the BP Statistical Review of World Energy 2021 (or the BP 2021 Report), Indonesia ranks 20^th in the world and the 4^th in the Asia-Pacific region, following China, Australia and India.

 

According to the Directorate General of Oil and Gas (“DGOG”), in 2022, investment of US$12.33 billion has been realized in upstream activities in Indonesia. The SKK Migas company profile report recorded that at the end of July 2023, Indonesia had a total of 171 Contract Areas, comprising 103 Contract Areas in production stage and the remaining 68 in the exploration stage. SKK Migas Annual Report also reported that total investment in 2022 was US$ 12.11 billion, reflecting an increase of 11% from 2021. This growth rate surpassed the average increase in global investment of only 5%. Apart from the gradual recovery of the worldwide economy, the rise in investment can also be attributed to several incentives provided by the Government of the Republic of Indonesia to the upstream oil and gas industry to maintain project economics and increase production. The gross split scheme allocates oil and gas production to contracting parties based on gross production, whereas in cost recovery, oil and gas production was shared between the government and contractors after deducting the production costs. The government remains keen to attract more foreign investment into the domestic oil and gas industry due to insufficient production against rising demand.

 

To further improve the oil and gas investment and to reverse the current trend in production, in 2021, the Government offered a stimulus package which provides fiscal incentives for the upstream oil production sector including, among others, an exemption to allow PSC contractors to offer discounts to buyers (known as “offtakers”) who agree to buy all or a portion of the future production for the oil quantities taken in excess of the offtakers’ “take or pay” arrangement (under which an offtaker takes an agreed-upon amount of oil on a certain date or pays a set fee if it does not) and a reduction of up to 100% of indirect taxes. Additionally, the Government also provided contractors with the flexibility to choose between the cost recovery PSC and the gross split PSC, discontinued the previous requirement of mandatory relinquishment by the third contract year, granted access to data in the Migas Data Repository and offered additional tax incentives to contractors.

 

 

According to the BP 2023 Report, Indonesia’s oil consumption in 2022 reached 1.59 million barrels per day, 40.6% of which was met by domestic production. The MEMR specified that Indonesia exported 15.49 million barrels of oil and imported 104.72 million barrels of oil in 2022. SKK Migas recorded Thailand and Australia as the top two countries Indonesia exported oil and condensate to in 2022, at 11,818 million barrels and 1,473 million barrels, respectively.

 

Further, we believe that Indonesia’s expanding economy, in combination with the government’s intention to lower reliance on coal as a source for energy supply in industries, power generation and transportation, will cause Indonesian domestic demand for gas to rise in the future. Indonesia’s power infrastructure needs substantial investment if it is not to inhibit Indonesia’s economic growth. According to the MEMR 2022 Report, generating capacity at the end of 2022 was standing at around 83.8 gigawatts or an increase of 12.5% compared to 74.5 gigawatts generating capacity in 2021.

 

According to Indonesia Energy Outlook 2023, a report published by the Secretariate General of The National Energy Council, in the next ten years from 2023 to 2033, Indonesia’s final energy demand is projected to grow 4.6% in average, natural gas consumption average growth rate is estimated at 3.2%, and total electricity demand is expected to increase 53% by 2033.

 

In terms of gas distribution, Indonesia still lacks an extensive gas pipeline network because the major gas reserves are located away from the demand centers due to the particular territorial composition of the archipelagic state of Indonesia. Indonesian gas pipeline networks have been developed based on business projects; thus, they are composed of a number of fragmented systems. The developed gas networks are located mostly near consumer centers. Total gas transmission and distribution pipeline infrastructure in 2023 was 22,478.62 km which is 4.97% higher compared to 2022 with an additional of 1,064.68 km pipeline length. Based on the total pipe length achieved in 2023, the medium- and long-term target in 2024 of 17,300 km has been exceeded according to Oil and Gas Downstream Regulatory Agency (BPH MIGAS) 2023 Performance Report.

 

 

In West Java, where the Citarum Block is located, the total natural gas demand is expected to increase significantly from 2,521 MMSCFD in 2020 to 3,032 MMSCFD by 2035 according to Petromindo, an Indonesian petroleum, mining and energy news outlet. This will require additional gas supply of 603 MMSCFD in 2020 and 1,836 MMSCFD in 2028 including import. Being relatively low-carbon compared to coal, as well as being medium-cost, gas is likely to remain a favored fuel for at least the next decade, especially given Indonesia’s extensive gas reserves. Moreover, energy demand in Indonesia is expected to increase as Indonesia’s economy and population grow.

 

Our Opportunity

 

Beginning in 2014, our management team identified a significant opportunity in the Indonesian oil and gas industry through the acquisition of medium-sized producing and exploration blocks. In general terms, our goal was to identify assets with the highest potential for profitable oil and gas operations. As described further below, we believe that our two current assets — Kruh and Citarum — represent just these types of assets.

 

We believe these medium-sized blocks were available for two main reasons: (i) a general lack of investment in the industry by smaller companies such as ours and (ii) the fact that these blocks are overlooked by the major oil and gas exploration companies; many of which operate within Indonesia.

 

The fundamentals for the lack of investment in our target sector are the industry’s intensive capital requirements and high barriers to entry, including high startup costs, high fixed operating costs, technology, expertise and strict government regulations. We have and will continue to seek to overcome this through the careful deployment of investor capital as well as cash from our producing operations.

 

In addition, the medium-sized blocks we target are overlooked by the larger competitors because their asset selection is subject to a higher threshold criterion in terms of reserve size and upside potential to justify the deployment of their human resources and capital. This means that a very small company is not capable of operating these blocks, a new investor is unlikely to enter this sector and the major producers are competing for the larger assets.

 

This scenario creates our corporate opportunity: the availability of overlooked assets including producing and exploration projects with untapped potential resources in Indonesia that creates the potential to both generate economic profit and expand our operations in the years to come.

 

An important fact is that, since we started our operations in 2014, the natural resources industry has gone through a dramatic change due to oil price volatility. The challenges imposed by low oil prices during this period created an incentive for us to operate efficiently by driving our business to make the most use of the resources available within our organization to lower costs and improve operational productivity. More recently, with an improvement in oil prices, we believe are in a good position to take advantage of our lower producing costs.

 

Asset Portfolio Management

 

Our asset portfolio target is to establish an optimum mix between medium-sized producing blocks and exploration blocks with significant potential resources. We believe that the implementation of this diversification technique provides our company the ability to invest in exploration assets with substantial upside potential, while also protecting our investments via cash flow producing assets.

 

We consider a producing block an oil and gas asset that produces cash flow or has the potential to produce positive cash flows in a short-term period. An exploration block refers to an oil and gas block that requires a discovery to prove the resources and, once these resources are proven, such project can generate multiple returns on capital.

 

Our portfolio management approach requires us to acquire assets with different contracting structures and maturity stage plays. Another key factor is that we believe the diversification provided by our asset portfolio gives us the ability to better face the challenges posed by the industry, such as uncertainties in macroeconomic factors, commodity price volatility and the overall future state of the oil and gas industry.

 

 

We believe this strategy also allows us to maintain a sustainable oil and gas production business (a so-called “upstream” business) by holding a portfolio of production, development and exploration licenses supported by a targeted production level. We believe that, in the long-term, this should allow us to generate excess returns on investment along with reducing risk exposure.

 

Our Assets

 

We currently hold two oil and gas assets through our operating subsidiaries in Indonesia: one producing block (the Kruh Block) and one exploration block (the Citarum Block). We also have identified a potential third exploration block (the Rangkas Area).

 

Kruh Block

 

We acquired rights to the Kruh Block in 2014 and started its operations in November 2014 through our Indonesian subsidiary PT Green World Nusantara (or GWN). Kruh Block operated under a Technical Assistance Contract (or TAC) with Pertamina, until May 2020 and the operatorship of Kruh Block shall continue as a Joint Operation Partnership (or KSO) from May 2020 until September 2035 after the extension. This block covers an area of 258 km² (63,753 acres) and is located 16 miles northwest of Pendopo, Pali, South Sumatra. This block produced an average of about 6,044 barrels of oil per month in 2020, about 5,053 barrels oil per month in 2021, about 5,206 barrels oil per month in 2022, and about 4,885 barrels oil per month in 2023. Out of the total eight proved and potentially oil bearing structures in the block, three structures (North Kruh, Kruh and West Kruh fields) have combined proved developed and undeveloped gross crude oil reserves of 3.14 million barrels (net crude oil proved reserves of 2.33 million barrels) and probable undeveloped gross crude oil reserves of 3.17 million barrels as of December 31, 2023 determined on a September 2035 contract expiration date. In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed an amendment to the KSO (the “Amended KSO”) that moved the expiration date of our operatorship of Kruh Block to September 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%. We received Pertamina’s signature to the Amended KSO in early September 2023. The additional 5 years production and higher profit split lead to a significant increase of proved and probable reserves from 2.06 and 2.44 million barrels, respectively, as of December 31, 2022 to 3.14 and 3.17 million barrels, respectively, as of December 31, 2023. Due to the lengthy negotiations with the Government on the contract amendment, the seismic program was rescheduled from 2023 to 2024. The new drilling program after the completion of 3D seismic program is expected to increase the proved reserves and probable reserves.

 

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. While proved undeveloped reserves include locations directly offsetting development spacing areas, probable reserves are locations directly offsetting proved reserves areas and where data control or interpretations of available data are less certain. There should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. The estimate of probable reserves is more uncertain than proved reserves and has not been adjusted for risk due to the uncertainty. Therefore, estimates of proved and probable reserves may not be comparable with each other and should not be summed arithmetically.

 

The estimate of the proved reserves for the Kruh Block was prepared by representatives of our company (a team consisting of engineering, geological and geophysical staff) based on the definitions and disclosure guidelines of the SEC contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Our proved oil reserves have not been estimated or reviewed by independent petroleum engineers.

 

 

 

The following map shows the Kruh Block and its producing fields:

 

 

Our two main objectives in acquiring Kruh Block was to initiate our operations with a cash producing asset and for our legal entity to earn the required experience to participate in bids and direct tenders with the Government.

 

We selected Kruh based on certain criteria according to our strategy: (i) selecting an area with proven hydrocarbons; (ii) finding a currently producing structure which is not overdeveloped; and (iii) operating an asset located in the western part of Indonesia.

 

Pursuant to the Kruh TAC, our subsidiary GWN was a contractor with the rights to operate in the Kruh area with an economic interest in the development of the petroleum deposits within the block until May 2020. The contract was based on a “cost recovery” system, meaning that all operating costs (expenditures made and obligations incurred in the exploration, development, extraction, production, transportation, marketing, abandonment and site restoration) were advanced by GWN and later repaid to GWN by Pertamina. Pursuant to the Kruh TAC, all the oil produced in Kruh Block was delivered to Pertamina and, subsequently, GWN recovered the operating costs through the proceeds of the sale of the crude oil produced in the block in a monthly basis, but capped at 65% of such monthly proceeds. GWN was also entitled to an additional 26.7857% of the remaining proceeds from the sale of the crude oil after monthly cost recovery repayment as part of the profit sharing. Together with our share split, our net revenue income was around 74% of the total production times the ICP. On a monthly basis, we submitted to Pertamina an Entitlement Calculation Statement (ECS) stating the amount of money that we were entitled to base on the oil lifting, ICP, cost recovery and profit sharing of the respective month. In connection with our acquisition (by which we mean our entry into the TAC) of Kruh Block, approximately $15 million of the acquisition costs were carried to our financial statements from the previous contractor. The cost recovery scheme is illustrated and described in “—Legal Framework for the Oil and Gas Industry in Indonesia” below. Since our recoverable cost balance will not be fully recovered up to the expiry of the contract, our net income is not subject to any tax whatsoever.

 

 

Historically, the cooperation agreement between Pertamina and its contractors were established via a TAC, but after the regulatory reform in the early 2000’s and the reorganization of Pertamina, the contractual relationship between Pertamina and its partners was changed into KSO.

 

On May 22, 2020, we commenced the continuation of our operatorship of Kruh Block under a KSO contract that has a term until May 2030, which was extended to 2035. In essence, the TAC and KSO are very similar in nature due to its “cost recovery” system, with a few important differences to note. The main differences between both contracts are that: (1) in the TAC, all oil produced is shareable between Pertamina and its contractor, while in the KSO, a Non-Shareable Oil (NSO) production is determined and agreed between Pertamina and its partners so that the baseline production, with an established decline rate, belongs entirely to Pertamina, so that the partners’ revenue and production sharing portion shall be determined only from the production above the NSO baseline; (2) in the TAC, the cost recovery was capped at 65% of the proceeds from the sale of the oil produced in the block, while in the KSO, the cost recovery is capped at 80% of the proceeds from the sale of the oil produced within Kruh Block for the cost incurred during the term under the KSO plus 80% of the operating cost per bbl multiplying non-shareable oil (NSO). Also, similar to the TAC contract, under the KSO terms, we have committed to a 3 years’ work program to drill additional wells and perform exploration activities such as 2D and 3D seismic within the Kruh Block. If we fail to fulfill our obligations, including the performance of the work program commitment, Pertamina will have the right to terminate our KSO contract and our bank guarantee shall be deemed forfeited. As of December 2022, we have fulfilled the obligation of drilling commitment specified in the KSO contract.

 

In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed an amendment to the KSO (the “Amended KSO”) that moved the expiration date of our operatorship of Kruh Block to September 15, 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from the 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%. We received Pertamina’s signature to the Amended KSO in early September 2023. To maximize the benefits from the amended KSO contract, we have rescheduled the 2023 seismic program to 2024 when the amended contract went effective. We will resume drilling program after the 3D seismic program and evaluation is completed, subject to the availability of funding.

 

With respect to our drilling program at Kruh Block, in March 2021 we announced our plan to drill a total of 5 wells in 2021, 6 wells in 2022 and 7 wells in 2023, for a total of 18 new wells on Kruh Block. Due to delays in the Government permitting process and COVID-19 related delays experienced during 2021 and 2022, our overall drilling program for Kruh Block has similarly been delayed. We continue to plan on drilling a total of 18 new wells at Kruh Block, and current estimation is that this will be completed by the end of 2029 (we previously estimated that this goal would be completed earlier, but as discussed elsewhere in this report, we have experienced delays in our exploration and drilling programs). Four of these 18 new Kruh Block wells have already been completed as of the date of this report. We expect to finance additional exploration and drilling activities through short-term and long-term borrowings from third parties or related parties as well as further use of our ATM.

 

We commenced the drilling of a well named “K-25” at Kruh Block on April 21, 2021 and another well named “K-26” at Kruh Block on August 22, 2021. As a result of our successful drilling program at K-26, our production rate increased by over 50% from approximately 160 barrels of oil per day during the first 10 months of 2021 to approximately 245 barrels of oil per day as of late December 2021. On April 7, 2022, we spudded the K-27 well and reached the total depth of 3,359 feet on May 9, 2022. In December 2022, a hydraulic fracturing stimulation was conducted at the K-27 well. The well is currently producing 38 BOPD. The fourth of the 18 new well program, K-28, was spudded on June 22, 2022 and reached the total depth of 3,359 feet on July 14, 2022. Due to the unexpected large amount of gas was encountered causing well bore instability, we side-tracked the K-28 well at 1,230 feet on September 4, 2022 and the K-28ST well, the side-tracked portion of the K-28 well, reached a total depth of 3,475 feet on September 16, 2022. In addition to the proved oil-bearing Lamat B sand, several other potential oil and gas bearing reservoirs were encountered. We plan to complete the testing of K-28ST well in the first half of 2024.

 

When we acquired the Kruh Block in 2014, it had seven producing wells in 2014 and produced 200 barrels of oil per day (BOPD) with an average cost of production per barrel of US$60.25, while 90% of the production relied on only one well, K-20.

 

Our development plan for the Kruh Block was to increase the production by drilling proved undeveloped (PUD) wells which we considered a low risk investment due to the higher probability of these wells to produce commercial levels of oil compared to drilling wells with unproved reserves. Finding ways to increase the production is particularly important in maturing fields as producing volumes inevitably decline due to the normal decline rate of production in these fields. In financial terms, our target was to produce the highest cash inflow within the remaining period of the contract.

 

With this target in mind, following execution of Kruh TAC we started to collect data through a passive seismic survey in 80 locations and by reactivating an old well (K-19) to obtain additional geological information. After seismic data re-interpretation and modelling, we initiated our drilling campaign for 2 wells, K-21 and K-22.

 

 

In October 2015, we started drilling K-21 with a targeted depth of 3,418 feet that resulted in a daily production of only 45 BOPD due to a permeability and tortuosity (a measure of how convoluted a well is) issues.

 

In November 2015, we started drilling K-22 with a targeted depth of 4,600 feet which resulted in a 30 BOPD due to the same permeability and tortuosity issue discovered in K-21.

 

In the beginning of 2016, we focused on finding solutions to increase the production in K-21 and K-22. From February to May, we performed an acidizing and sand fracturing operation to bypass the challenges in production efficiency that affected the wells K-21 and K-22. This resulted in a multiple production gain in both K-21 and K-22, increasing the production of these wells to 95 BOPD and 98 BOPD, respectively.

 

During 2016, oil price crisis hit its bottom with an ICP of only $25.83 in the month of January. As a result of this low price, our operations went through a cost analysis procedure in order to determine the economic limit of each of our producing wells by identifying their respective direct production cost. Accordingly, we closed a total of 6 wells that were producing less than 10 BOPD that year. We were required to find solutions to enhance our operating margins in a tough oil price environment, so we discontinued operations of 6 out of the 9 wells we had at that time.

 

As such, 2016 represented our effort to consolidate our operations in terms of efficiency that resulted in the reduction of operating costs, allowing our company to go through the crude oil price turmoil. The cost reduction and efficiency measures taken include (i) setting an economic limit for each operating well and closing wells that has exceeded $40 per barrel production cost; (ii) increased production from the remaining wells through stimulation activities; (iii) renegotiating contracts with service providers; (iv) establishing a fuel utilization plan that allowed us to use the gas produced from our wells as engine fuel and (v) optimized surface facilities equipment and system.

 

In May 2017, we drilled our third development well (K-23) with a cost of approximately US$ 1.5 million in Kruh Block with total depth of 3,315 feet that resulted in a production of 30 BOPD due to same issues encountered in K-21 and K-22, permeability and tortuosity issues.

 

In October 2017, a stimulation operation of sand fracturing by Halliburton was performed in two wells, K-21 and K-23, in order to improve the flow of hydrocarbons into these wells. Following completion, the production of K-23 was increased from 30 BOPD to 170 BOPD and in K-21 from 20 BOPD (production in K-21 declined back to 20 BOPD due to increase in the water cut from 2016 to 2017) to 95 BOPD. This stimulation resulted in an increase of 3,844 barrels oil per month, resulting on our peak total production of more than 11,000 barrels oil per month or 380 BOPD during the subsequent month.

 

One well service was completed in June 2018 for K-21 to restore the production by cleaning the well from the sand material that filled the borehole carried by the formation fluid. No development wells were drilled in 2016 and 2018 and no exploratory wells were drilled by our company up to date.

 

Other major activities in the Kruh field during 2018 were well services and necessary work for maintaining production. The work included well cleaning and production string replacement.

 

In December 2018, we initiated a pilot project with the application of electrical stimulation oil recovery method (ESOR) for an attempt of increasing the oil production in the Kruh field. The basic function of the ESOR process is to increase the mobility of the oil by reducing its viscosity, which in turn helps move the oil toward producing wells. By inducing direct current power through existing oil wells, the electric field drives the oil from the anode to the cathode, a process commonly referred to as electrokinetics. During the trial period in 2019, we did not observe significant increases of production rate from the 4 producing wells. Therefore, we terminated the pilot project in February 2020.

 

During the period of our operatorship, we have incurred total expenditures of at least $15 million, including drilling costs of three wells. We were able to produce oil from all three wells drilled during our operatorship, which represents a 100% drilling success ratio. We also improved our water treatment system, installed a thermal oil heater to increase the speed in which the water is separated from the oil, as Pertamina allows a maximum of 0.5% of water content in the oil transferred to them, and upgraded our power generating facilities to gas fueled engines.

 

 

Since 2014, we have increased the gross production from 250 BOPD (gross) in early 2014 and reached a peak of 400 BOPD in 2018, which we achieved by the drilling of three new wells and upgrade of the production facilities. Our production is our primary source of revenue. At a per barrel crude price of US$61.89 (historical 12-month average price calculated as the average ICP for each month in 2019) and a production of 7,582 barrels of oil per month, we were able to generate approximately US$470,000 per month of gross revenue from Kruh. We intend to gradually increase production on the block over the next few years, with an anticipated nominal amount of additional capital expenditure required.

 

During 2019, Kruh Block produced an average of about 7,582 barrels per month (gross). This represented an average of 26.9% decline from the 4 producing wells. The two major producing wells K-22 and K-23 wells, however, only declined at 14.9% rate. During the period of December 2014 to December 2019, we have produced a total of 497,398 barrels of oil from the Kruh structure.

 

During 2020, Kruh Block produced an average of about 6,044 barrels per month (gross), slightly less than in 2019 due to an anticipated decline of 20.3%. For the year ended December 31, 2020, we have produced a total of 72,524 barrels of oil from the Kruh structure.

 

During 2021, Kruh Block produced an average of about 5,053 barrels per month (gross), which is less than in 2020 due to further anticipated decline of 16.4%. For the year ended December 31, 2021, we have produced a total of 60,637 barrels of oil from the Kruh structure.

 

During 2022, we discovered two back-to-back discovery wells, K-27 and K-28 wells, at our 63,000-acre Kruh Block. The fourth well K-28 is still waiting for final flow test. For the year ended December 31, 2022, we have produced a total of 62,467 barrels of oil from the Kruh structure.

 

During 2023, we concentrated on the negotiation of the 5 year contract extension for Kruh Block with the Government providing for a higher profit split. To maximize the benefit from the amended contract terms, major work programs such as seismic acquisition and drilling were rescheduled after the amended contract terms became effective. In the meantime, our operations team effectively managed the reservoir and production to minimize the decline. As a result, we produced an average of about 4,885 barrels per month of oil in 2023 compared to about 5,206 barrels per month in 2022, a 6.1% annual decline.

 

Historically, the average gross initial production of the 29 oil wells drilled in Kruh Block is 191 BOPD, with an average gross production of 173 BOPD throughout the wells’ first year of production, considering an exponential decline rate per year of 21%. The decline rate of 21% was estimated based on the decline curve analysis of field-wide production history from 2017 to December 2019. Based on this data, a well in Kruh Block would be expected to produce, on average, a total gross amount of approximately 63,112 bbls of crude oil in its first year. Also, due to the successful stimulation and maintenance, wells K-22 and K-23 have significantly lower decline rate than 21%. Based on the data above, the KSO cost recovery terms and using an average oil price of US$61.89 (the previous 12-months average monthly ICP as of December 31, 2019), on average, a well would generate US$ 3.24 million net revenue in its first year (US$ 1.70 million in its first 6 months).

 

In October 2017, we formally started negotiations with Pertamina to obtain an extension for the operatorship of the Kruh Block after the expiry of our term in May 2020 through a KSO contract with Pertamina. Through a performance appraisal, we successfully qualified to continue the operatorship of Kruh Block. In October 2018, Pertamina has sent us the Direct Offering Invitation of Kruh Block attached with the contract draft for 10 years continuing operatorship period. In July 2019, we received the award from Pertamina to operate the Kruh Block for an additional 10 years under an extended KSO. The KSO contract was signed on July 26, 2019. Thus, the reserve estimation and economic models assumptions, as of December 31, 2019 and 2018, consider that we have the operatorship of the Kruh Block until May 2030, as evidence indicates that renewal is reasonably certain, based on SEC Regulation S-X §210.4-10(a)(22) that defines proved oil and gas reserves. In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed an Amended KSO that moved the expiration date of our operatorship of Kruh Block to September 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%. We received Pertamina’s signature to the Amended KSO in early September 2023.

 

 

As of December 31, 2023 and 2022, considering the operatorship of Kruh Block ending in September 2035, net proved reserves have a net ratio of approximately 74.16% and 57.56% of total reserves, respectively. This net ratio calculation is based on our revenue entitlement, taking into consideration the cost recovery balance estimations and profit sharing portions throughout the Kruh Block operatorship period.

 

As of December 31, 2017, with the Kruh Block operatorship ending in May 2020, the unrecovered expenditures on TAC operations of $20,258,361 would remain unrecovered up to the end of the TAC, hence our entitlement to 74.37% of the revenue from the sales of the crude oil produced until the expiry of the TAC in May 2020 (65% of the proceeds from the sale of the crude oil produced as cost recovery plus 26.7857% profit sharing portion of the remaining 35% of the proceeds from the sale of the crude oil), which resulted in a net proved reserves ratio of 74.37% of total reserves at that point in time. In contrast, as of December 31, 2023, with an extension of the Kruh Block operatorship to September 2035 and with the cost recovery cost recovery cap increased from 80% to 100%., we estimated that we would be entitled to approximately 74.16% of the revenues from the sales of the crude oil produced throughout the operatorship in Kruh Block until September 2035, considering the cost recovery balance estimations and profit sharing portions throughout the Kruh Block operatorship period, resulting on a net proved reserves ratio of 74.16% of total reserves.

 

Following the confirmation of the Kruh Block extension to September 2035, our board of directors approved a development plan for a drilling program of 14 Proved Undeveloped Reserves (or PUD) wells at Kruh Block, according to the schedule we estimate below:

 

		Unit\Year		2026				2027				2028				2029				Total
Planned PUD wells		Gross well			4				4				4				2				14
Future wells costs (1)		US$			6,000,000				6,000,000				6,000,000				3,000,000				21,000,000
Costs already paid		US$			-				-				-								-
Total gross PUD added		Bbls			750,189				727,140				884,661				447,478				2,809,468
Total net PUD added		Bbls			556,365				539,271				656,094				331,864				2,083,594

 

(1)	Future wells costs are the estimated capital expenditures associated with the estimated new wells costs and do not include other capital expenditures such as production facilities.

 

We commenced new drilling operations in Kruh Block in March 2021, and new drilling of 4 wells were completed in 2021 and 2022. The fourth well, K-28, is still waiting for final flow test.

 

In December 2022, we announced that in order to maximize the potential of Kruh Block after several encouraging new oil discoveries made during 2021 and 2022, our plan is to conduct significant new seismic operations across the entire Kruh Block. We believe that this new work, together with what has been learned from recent oil and gas discoveries, will greatly assist us in ascertaining the best locations conduct, conducting a continuous drilling campaign at Kruh Block that will look to develop not only the one oil formation currently being targeted, but to look to develop what appears to be at least three additional oil formations that may contain significant commercial quantities of oil and natural gas. Completion and full interpretation of this seismic operations is currently expected to occur by the middle of 2024 (although it could take longer), after which we plan to re-start our continuous drilling campaign at Kruh Block in 2026 and subject to the availability of funding. We continue to plan on drilling a total of 18 new wells at Kruh Block, and current estimation is that this will be completed by the end of 2029 (we previously estimated that this goal would be completed earlier, but as discussed elsewhere in this report, we have experienced delays in our exploration and drilling programs). Four of these 18 new Kruh Block wells have already been completed as of the date of this report. We expect to finance additional exploration and drilling activities through short-term and long-term borrowings from third parties or related parties as well as further use of our ATM. After the Kruh Block seismic acquisition, processing and interpretation program in 2024, we expect to resume drilling in 2025 with the goal of drilling 14 additional wells and significantly increasing our production rate. The result of the high quality 3D seismic data will also provide strong support of additional PUD locations which will result in additional proved reserves.

 

For Proved Developed (or PDP) reserves, we produced 62,467 bbls and 58,616 bbls for the years ended December 2022 and 2023, respectively. The natural reservoir energy decline and delay in drilling new wells due to COVID-19 slowed down the production rate increase after drilling program.

 

The gross proved oil reserves were increased from 2,056,407 bbls as of December 31, 2022 to 3,144,659 bbls as of December 31, 2023 mostly due to the production from 5 additional years and higher profit split in the Amended KSO. As of December 31,2023, the net reserves were estimated as 2,332,183 bbls using a per barrel crude price of US$77.61 (historical 12-month average price calculated as the average ICP for each month in 2023). In a “cost recovery” system such as the Kruh KSO contract, the production share and net reserves entitlement to our company decreases in periods of higher oil prices (57.56% net share for ICP, US$96.94 in year 2022) and increases in periods of lower oil prices (74.16% net share for ICP, US$77.61 in year 2023). This means that the estimated net proved reserves quantities are subject to oil price related volatility due to the method in which the revenue is derived throughout the contract period. Therefore, the net proved reserves are estimated based on the revenue generated by our company according to the KSO economic models.

 

 

The table below summarizes the gross and net crude oil proved reserves as of December 31, 2023 in Kruh Block:

 

		Crude Oil Proved Reserves at Kruh Block
Gross Crude Oil Reserves
Gross Crude Oil Proved Developed Producing Reserves (PDP)		Bbl	335,191
Gross Crude Oil Proved Undeveloped Reserves (PUD)			2,809,468
Total Gross Crude Oil Reserves		Bbl	3,144,659
Net Crude Oil Reserves
Net Crude Oil Proved Developed Producing Reserves (PDP)		Bbl	248,589
Net Crude Oil Proved Undeveloped Reserves (PUD)			2,083,594
Total Net Crude Oil Reserves		Bbl	2,332,183

 

Our estimates of the proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers, and Pertamina, and revised as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance and governmental restrictions.

 

Our proved oil reserves have not been estimated or reviewed by independent petroleum engineers. The estimate of the proved reserves for the Kruh Block was prepared by IEC representatives, a team consisting of engineering, geological and geophysical staff based on the definitions and disclosure guidelines of the SEC contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.

 

Kruh Block’s general manager and our Chief Operating Officer have reviewed the reserves estimate to ensure compliance to SEC guidelines for (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.

 

Net reserves were estimated using a per barrel crude price of US$77.61 (historical 12-month average price calculated as the average ICP for each month in 2023). In a “cost recovery” system, such as the TAC or KSO, in which Kruh Block operates or will operate, the production share and net reserves entitlement to our company reduces in periods of higher oil price and increases in periods of lower oil price. This means that the estimated net proved reserves quantities are subject to oil price related volatility due to the method in which the revenue is derived throughout the contract period. Therefore, the net proved reserves are estimated based on the revenue generated by our company according to the KSO economic models.

 

As of December 31, 2023, Kruh Block had 6 oil producing wells (K-20, K-21, K-22, K-23, K-26 and K-27 in Kruh field) covering 48.0 acres. K-25 well is temporarily shut-in and K-28 is waiting for testing and completion. There were 14 proved undeveloped oil locations in Kruh (3), North Kruh (6) and West Kruh (5) field covering 381.4 acres. In the Kruh, North Kruh and West Kruh fields, there are additional 7, 5 and 5 probable locations respectively covering 270 acres. See details on table below. Larger oil reserves due to bigger share and 5 years additional production lead to greater acreage of each PDP, PUD and probable location.

 

 

PDP, PUD and Probable Locations and Acreage for the Kruh Block as of December 31, 2023
Reserves Category		Kruh Field								North Kruh Field								West Kruh Field								Total
		Locations				Acreage				Locations				Acreage				Locations				Acreage				Locations				Acreage
Proved Dev Producing (PDP)			8				48				-				-				-				-				8				48
Proved Undeveloped (PUD)			3				24				6				156				5				201				14				381
Total Proved			11				72				6				156				5				201				22				429
Probable			7				49				5				126				5				172				17				346
Total Proved & Probable			18				121				11				282				10				373				39				775

 

The following table summarizes the gross and net developed and undeveloped acreage of Kruh Block based on our TAC and KSO terms, as well as our economic model as of December 31, 2022:

 

Gross and Net Developed and Undeveloped Acreage of Kruh Block as of December 31, 2023
		Developed Acreage								Undeveloped Acreage								Total Acreage
Kruh Block			Gross				Net				Gross				Net				Gross				Net
Kruh Field			131				97				24				18				154				115
North Kruh Field			51				37				156				116				207				153
West Kruh Field			9				7				201				149				211				156
Other			-				-				63,181				46,857				63,181				46,857
Total			191				141				63,562				47,140				63,753				281

 

Citarum Block

 

Citarum Block is an exploration block covering an area of 3,924.67 km2 (969,807 acres). The block is located onshore in West Java with a population of 48.7 million people and only 16 miles south of the capital city of Indonesia, Jakarta, thus placing it within a short distance to the major gas consumption area in Indonesia – the Greater Jakarta region in West Java. We believe this significantly mitigates the logistical and geographical challenges posed by Indonesia’s composition and infrastructure, significantly reducing the commercial risks of our project.

 

Citarum Block is located in onshore Northwest Java basin. In terms of geology, a very effective petroleum system has been proved in the region from the long history of exploration and production efforts since the 1960’s. According to the United States Geological Survey (USGS) assessment (Bishop, Michele G. “Petroleum Systems of The Northwest Java Province, Java and Offshore Southeast Sumatra, Indonesia”, Open-File Report 99-50R, 2000), “Northwest Java province may contain more than 2 billion barrels of oil equivalent in addition to the 10 billion barrels of oil equivalent already identified”. However, little new reserves have been added to the region during the last 15 years due to the lack of investments in exploration programs. We have not engaged independent oil and gas reserve engineers to audit and evaluate the accuracy of the reserve data from the USGS research. Citarum Block also shares its border with the producing gas fields of Subang, Pasirjadi, Jatirarangon and Jatinegara. The combined oil and gas production from more than 150 oil and gas fields in the onshore and offshore Northwest Java basin, operated by Pertamina, is 45,000 BOPD and 450 million standard cubic feet gas per day (MMSCFD). The following graphics show the Citarum Block together with the producing oil and gas fields in the region, as well as the block’s proximity to the West Java gas transmission network:

 

 

 

Source: Indonesia Energy Corporation Limited

 

We started collecting data regarding the Citarum Block in 2016, when we decided it was time to expand our asset base by adding an exploration block to our portfolio. Given our strategy, we had to find a cost-efficient method to acquire a block with the potential to add hydrocarbons reserves to our company as part of the process to maximize our company’s value. With the necessary technical knowledge and regulatory experience from our professionals, we agreed that the best method for us to acquire an exploration block was via a Joint Study proposal to the Government in a “work area” that had not yet been reserved for the bidding process by the Government. The Joint Study objective is to determine oil and gas potential within a proposed working area by conducting geological and geophysical work such as field surveys, magnetic surveys and the reprocessing of existing seismic lines. Upon completion of the Joint Study, if the Government further decided to conduct a bidding process for the working area, we would have the right to change our offer (right to match) in the bidding process if the other bidders gave higher offers.

 

Therefore, following our plans, our team identified Citarum, an open onshore area in West Java that was available for a Joint Study. In September 2016, after we formally expressed our interest to the government to conduct the Joint Study in Citarum and fulfilled all requirements, we obtained the approval to initiate our Joint Study program in conjunction with DGOG and LAPI ITB (a third-party consultancy service provided by Bandung Institute of Technology (or ITB)). The study target was to integrate field geological survey, subsurface mapping, identify stratigraphy and structural geology, perform a basin analysis and petroleum system assessment. As part of our proposal, we engaged a surveyor to perform a passive seismic as an alternative method to fill the gap of the existing two-dimensional seismic survey due to the absence of data on some area on the block. With 111 survey points, the work was completed in two months and covered approximately one third of the area, as shown in the illustration below. The data produced from the passive seismic together with the existing two-dimensional seismic data we acquired from the Indonesian National Data Management Company were the base for the Joint Study.

 

 

 

Between 2009 and 2016, Citarum Block had been operated by Pan Orient Energy Corp. (or POE), a Canadian oil and natural gas company whose shares are listed on the TSX Venture Exchange. POE carried out various exploration work on the Citarum Block, including the drilling of 4 wells in different locations across the block: Pasundan-1, Geulis-1, Cataka-1 and Jatayu-1. Providentially, all 4 wells discovered natural gas and gas flow was recorded for the Pasundan-1 and Jatayu-1 wells. The total investment made by POE on Citarum Block was $40,630,824 during this period.

 

Pasundan-1 encountered gas at a depth between 6,000 feet and 9,000 feet, while the mud log and sidewall cores displayed oil and gas shows. Cataka-1 well had gas indication from approximately 1,000 feet depth to 2,737 feet when the well was abandoned due to drilling problems as a result of inexperience operating in the region. Jatayu-1 well flowed high-pressured gas from approximately 6,000 feet depth and had a strong indication of gas-bearing between 5,800 feet and 6,700 feet depth. Geulis-1 well had gas indication from 1,000 feet to 4,300 feet depth. All 4 wells were suspended and plugged as the equipment and consumables used were not compatible to the drilling conditions, formation or strong gas flow.

 

Also, the gas indication/flowing from the wells would have been much more significant had the formations had not been damaged by high mud weight during drilling. Proper preparation to avoid drilling issues encountered by the previous operator for the up-coming drilling program should lead to an efficient delineation of gas discoveries.

 

The results from the 4 wells drilled in Citarum and the amount of data available regarding the block are the key factors for us in selecting Citarum as the block’s risk profile was significantly reduced with the discovery of gas across the block. Likewise, the fact that gas zones exist at different depths between 1,000 feet and 6,000 feet contributes to the potential of commercially developing these gas discoveries. As a result of this plus the significant amount of capital expenditures incurred by the previous operator, who discovered natural gas and gas flows from the 4 drilled wells. We believe this provides us with a unique de-risked asset to continue exploration on.

 

 

 

In the region, oil and gas have been producing from sandstone and carbonate reservoirs within 5 geologic formations (from old to young, Jatibarang, Talangakar, Baturaja, Upper Cibulakan and Parigi). The carbonate buildups in the Baturaja, Upper Cibulakan and Parigi formations are particularly gas rich. Within the Citarum Block, both sandstone and carbonate reservoirs have been encountered during drilling. Because of the gas-prone type II Kerogen domination in the Talangakar source rock of deltaic origin in the hydrocarbon generating “kitchens” (Ciputat, Kepuh, Pasirbungur and Cipunegara), prospects within the Citarum Block are mostly gas-bearing if discovered. The following illustration shows the northwest java stratigraphy:

 

The Joint Study was completed within a 12-month period (8 months plus a 4-month extension period) and the findings summarized in a report with the following information regarding the area: synopsis of regional geology and petroleum system, play concept, lead and prospect, volumetric of hydrocarbon prospect and economic prospect valuation.

 

 

The following diagram illustrates the full Joint Study process:

 

 

In February 2018, Citarum Block was tendered through a direct offer by the MEMR. Following the tender process, we were awarded the rights to explore the Citarum Block in May 2018. The exploration period for Citarum Block is comprised of a 6-year period that could be extended for an additional 4 years up to 2028.

 

In July 2018, a PSC was signed with respect to Citarum between MEMR and two of our wholly-owned subsidiaries, PT Cogen Nusantara Energi (or CNE) and PT Hutama Wiranusa Energi (or HWE), marking the official commencement of our 30 years operatorship term for the Citarum Block.

 

The following timeline illustrates the Citarum Block acquisition process:

 

 

 

As part of our commitment of conducting a 300 km of seismic survey, we have recently submitted our work program and budget to the Indonesian Interim Taskforce for Upstream Oil and Gas Business Activities (Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi, or SKK Migas). We have also completed an Environmental Base Assessment for the region in conjunction with a local university and will use the result as a base for any exploration activity in the area. This is part of our exploration activity in Citarum. When the exploration program is initiated, we plan to conduct more Geological and Geophysical (“G&G”) studies and a 300km² 2D seismic within the first year of the exploration program and drill our first exploration well in the Jonggol area in its second year. If the drilling is successful, we plan on conducting a 100km² 3D seismic within the second year and drill additional 2 delineation wells in the third year in order to propose a phase 1 development plan for the Citarum Block. If no petroleum in commercial quantities is discovered in Citarum during the exploration period, our PSC would be automatically terminated.

 

The upcoming exploration program for Citarum will begin with the 8 prospects with the lowest risk (38%-48%), 5 in the Jonggol region and 3 in the Purwakarta region, out of the 28 exploration prospects previously identified and evaluated by the Joint Study. According to data published by SKK Migas, from 2012 to 2022, there were a total of 441 exploration wells drilled in Indonesia and 286 out of the 441 resulted in an oil and gas discovery. The most recent complete data is shown in the table below.

 

Description \ Year		2012				2013				2014				2015				2016				2017				2018				2019				2020				2021				2022				Total
Total Exploration Wells			96				75				64				33				33				15				22				26				28				28				21				441
Total Discovery Wells			65				53				47				27				23				10				13				8				12				11				17				286
Success Ratio			68	%			71	%			73	%			82	%			70	%			67	%			59	%			31	%			43	%			39	%			81	%			65	%
Source: SKK Migas

 

Considering the closeness to the oil and gas generating “kitchens”, multiple reservoir horizons, moderate risked faulted anticlinal traps, and proved hydrocarbons in previous drilling and nearby producing fields, we believe that 23 of the 28 prospects have geological chance factors of success in the range of 30%-48%. Geological chance factors for the remaining 11 prospects are between 20% and 30% and 12 are between 10% and 20%.

 

In 2022 and 2023, further technical work in the Citarum Block was conducted to evaluate the additional 9 prospects and 9 exploration leads (T series prospects and leads on the maps below) identified in 2020. The 28 prospects identified in 2019 (J and P series prospects) remain to be the primary prospects for further evaluation by the upcoming new seismic data. The acreage of primary prospects, potential reservoir thickness and net reservoir volume remain no change at this time.

 

 

 

Prospect				Drilling sequence				Acreage (acres)				Reservoir thickness (feet)				Net reservoir volume (acres-feet)
1		J-1							438				192				83,867
2		J-2							1,299				301				390,848
3		J-3							96				28				2,704
4		J-4							229				115				26,374
5		J-5			3rd				2,141				153				327,861
6		J-6			5th				1,130				373				421,131
7		J-7							119				61				7,263
8		J-8							269				379				102,026
9		J-9			7th				1,686				1,479				2,492,477
10		J-10							1,060				353				374,265
11		J-11							89				95				8,418
12		J-12							730				386				282,175
13		J-13							177				235				41,486
14		J-14							262				75				19,701
15		J-15			4th				1,546				798				1,233,162
16		J-16			2nd				1,757				396				695,267
17		J-18							173				17				2,943
18		J-20							1,044				339				353,835
19		J-21							238				59				14,083
20		P-1							707				383				271,013
21		P-2							798				314				250,600
22		P-3			1st				2,274				725				1,648,940
23		P-4							1,567				386				604,920
24		P-5			6th				2,680				405				1,085,879
25		P-6							1,259				665				837,121
26		P-7							1,272				181				230,161
27		P-8			8th				1,079				762				821,361
28		P-9							517				790				408,314
		Total							26,636				10,445				13,038,195

 

 

The following depicts our development plan for Citarum, with the first priority being to confirm the value of the block by proving reserves and later to monetize the asset through the production and sale of gas:

 

 

During 2020, a new geological, geophysical and biostratigraphic study was performed on the Citarum Block. Eighteen additional exploration prospects were identified. This provides additional opportunities for oil and gas exploration in the future.

 

In 2022 and 2023, we continued to evaluate the resource size and risk for the prospects. Design of the 2D seismic acquisition and processing program is underway and our application for the requisite environmental permit for the seismic acquisition program is in progress as of the date of this report. The 2D seismic program will be used to further evaluate the prospects before we begin the drilling program.

 

 

Our Citarum PSC contract is based on the “gross split” regime, in which the production of oil and gas is to be divided between the contractor and the Indonesian Government based on certain percentages in respect of (a) the crude oil production and (b) the natural gas production. Our share will be the Base Split share plus a Variable and Progressive component. Our Crude Oil Base Split share is 43% and our Natural Gas Base Split share is 48%. Our share percentage is determined based on both variable (such as carbon dioxide and hydrogen sulfide content) and progressive (such as crude oil and refined gas prices) components.

 

Thus, pursuant to our Citarum PSC contract, once Citarum commences production, we are entitled to at least 65% of the natural gas produced, calculated as 48% from the Base Split plus a Variable Component of 5% from the first Plan of Development (POD I) in Citarum, a Variable Component of 2% from the use of Local Content, as the oil and gas onshore services are mostly closed or restricted for foreign companies (as described below under “—Legal Framework for the Oil and Gas Industry in Indonesia), and a 10% increase for the first 180 BSCF produced or 30 million barrels of oil equivalent which according to our economic model, the cumulative production of 180 BSCF will only be achieved in 2029 based on an aggressive exploration and development program or in 2033 based on a conservative program.

 

The following table summarizes the gross and net developed and undeveloped acreage of Citarum Block based on our PSC terms and economic model as of December 31, 2023:

 

Gross and Net Developed and Undeveloped Acreage of Citarum Block as of December 31, 2023
		Developed Acreage								Undeveloped Acreage								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
Citarum Block			-				-				969,807				614,239				969,807				614,239
Total			-				-				969,807				614,239				969,807				614,239

 

Pursuant to our PSC for Citarum Block, in order to incentivize and optimize our exploration activities at Citarum, there are circumstances under which we are required or may be required to relinquish portions of the contract area back to the Government, with such portions being subject to be agreed to between us and the Government. For example:

 

	(i)	on or before the end of the initial three (3) contract years beginning with the date the PSC was approved by the Government, we are required to relinquish twenty percent (20%) of the original total contract area in Citarum.
	(ii)	if at the end of the third (3rd) contract year, certain agreed to work programs have not been completed, upon consideration and evaluation of SKK Migas, we would be obliged to relinquish an additional fifteen percent (15%) of the original total contract area at the end of the third contract year.
	(iii)	on or before the end of the sixth (6th) contract year, we are required relinquish additional portions of contract area so that the area retained thereafter shall not be in excess of twenty percent (20%) of the original total contract area; provided, however, that on or before the end of the sixth (6th) contract year, if any part of the contract area corresponding to the surface area in which petroleum has been discovered, is greater than twenty percent (20%) of the original contract area, then we will not be obliged to relinquish such excess area.

 

Due to the high level of COVID-19 cases from late 2020 till the middle of year 2022, populated areas such as Jakarta and Java have enforced the lockdown policy which restricted practically all work activities to home-based. Travelling and mobilization of goods between cities and towns were restricted. In view of this situation, SKKMIGAS has given extension until 2024 of seismic acquisition project and G&G studies in the Citarum Block. Discussions of partial relinquishment of the block have also been postponed due to COVID-19.

 

 

In advance of the date of any relinquishment, we will advise SKK Migas of the portion to be relinquished. For the purpose of such relinquishment, we will consult with SKK Migas regarding the shape and size of each individual portion of the areas being relinquished, provided, however, that so far as reasonably possible, such portion shall each be of sufficient size and convenient shape to enable petroleum operations to be conducted thereon.

 

Potential Additional Block (Rangkas Area)

 

In mid-2018, we identified an onshore open area in the province of West Java, adjacent to our Citarum Block. We believe that this area, also known as the Rangkas Area, holds large amounts of crude oil due to its proven petroleum system. To confirm the potential of Rangkas Area, in July 2018, we formally expressed our interest to the DGOG of MEMR to conduct a Joint Study in the Rangkas Area and we attained the approval to initiate our Joint Study program in this area on November 5, 2018. The Rangkas Joint Study covered an area of 3,970 km2 (or 981,008 acres) and was completed in November 2019. The DGOG accepted the completion of the joint study and inquired IEC’s interest for further process to tender the block. The study result suggested an effective petroleum system for oil and gas accumulations. As of the date of this report, we have not decided when to acquire this block due to our work load in Kruh and Citarum blocks.

 

 

Source: Indonesia Energy Corporation Limited

 

The Rangkas Joint Study includes field geological surveys, geochemical and passive seismic surveys and the reprocessing of existing seismic lines was completed in November 2019. The Joint Study evaluated stratigraphy and structural geology of the area, conducted geochemical techniques to evaluate source rock and oils, performed passive seismic data analysis for identifying hydrocarbon occurrence, and performed basin analyses for assessing the petroleum system of the area with the objective of determining its oil and gas potential. Results of the study suggested (1) data from four wells drilled pre-World War II and two wells drilled in 1991 indicated the presence of hydrocarbon in the area with the discovery of several oil seeps and one gas seep, (2) the petroleum system in the area is proven with the occurrence of Eocene-Oligocene-Miocene source, reservoir and seal rocks similar to adjacent major producing hydrocarbon areas in West Java, and (3) twenty-one petroleum prospects and leads with potentially stacked reservoirs were identified.

 

 

Since the study of Rangkas block suggests high potential of finding hydrocarbons, we plan to continue pursue the PSC contract of the block which would be available through a direct tender process in which we will have the right to change our offer in order to match the best offer following the results of the bidding process, which has not taken place as of the date of this report. The timeline for the tender is contingent upon the DGOG’s plans and schedule.

 

Our Competitive Strengths

 

We believe we have the following competitive strengths:

 

●

Experienced management.

 

◌

Our management and technical team are comprised of some of the brightest and most passionate people in the industry, including with expertise in exploration technology.

 

	◌	Our professional team consistently adopts innovative concepts and technologies to reduce risks in exploring oil and gas, and continually looks for better ways to effectively manage our exploration and production operations.
	◌	Our management team members (Chief Executive Officer, Chief Operating Officer, Chief Business Development Officer and General Manager) collectively have many years of experience in petroleum exploration, development and production operations. Together they have successfully operated more than 17 oil and gas blocks and found and developed more than 10 oil and gas fields over the last 16 years. Our management team located in the United States consists of our President and Chief Financial Officer. Our President brings 43 years of public energy company experience and was the founder of two energy companies that are or were listed on the NYSE American. Our Chief Financial Officer brings 40 years of financial business experience, mostly as either a chief financial officer or controller, including over 18 years working in public companies.
	◌	Our top management team members have certification in “Kepala Teknik Tambang” from the Indonesian government, qualifying them for the implementation and compliance of occupational safety and health legislation in mining and petroleum operations. We are fully committed to conducting our operations according to the best industry practices to ensure the health, safety and security of all our stakeholders as well as the protection of the environment and surrounding communities.

 

	●	Established relationships. Through our management team’s experience in operating blocks in Indonesia, we have established close relationships with central and local governments, service providers and other petroleum companies in Indonesia. The excellent relationship between management members and government agencies provides us extraordinary opportunities of accessing low risk and high potential blocks. In addition, our U.S. management team likewise has established relationships with key participants in the U.S. capital and energy markets that we believe will be an asset to us as a U.S.-listed public company.
	●	Significant network. Our company has built solid alliances and a vast knowledge network within the Indonesian oil and gas industry, which gives us the ability to execute complex projects and traverse Indonesian regulatory and institutional risk.

 

 

●

Niche market. We look to acquire the rights to operate small to “medium sized blocks” onshore that are most likely overseen by the larger competitors. Being an independent and efficient oil and gas company in Indonesia, we have the flexibility and speed necessary to seize opportunities as they arise.

 

●

Strategically located assets. Our company has a proven track record in acquiring assets located close to major infrastructure and populous cities. We believe that being strategically located to major infrastructure will enable higher margins as we scale our business.

 

Our Business Strategies

 

We are an active independent Indonesian exploration and production company with an ultimate goal to generate value for our shareholders. Our overall growth strategy is to actively develop our current blocks and to acquire new assets to boost our growth. We will also evaluate available opportunities to expand our business into the oil and gas downstream industry in Indonesia.

 

The key elements for achieving our goal are set out below.

 

●

Strategic investment allocation in existing blocks. We are focused on validating the reserves of our blocks by continuing to develop high impact exploration activities to add reserves, combined with a plan of development in order to increase production.

 

	●	Commercialization and monetization of oil and gas discoveries. We are a revenue driven company and we strategically adjust our operations and development programs in our blocks by evaluating the market and the Indonesian energy demand.
	●	Develop our “de-risked” 969.807 acres Citarum Block. $40.6 million was invested by the block’s prior owner, Pan Orient Energy Corp. (TSXV.POE) who drilled 4 wells and successfully discovered natural gas and gas flow from each of the 4 wells. We believe this contribution provides us with a unique de-risked asset to continue exploration on.
	●	Expansion of our company’s asset portfolio. We actively seek to acquire blocks to increase our company’s value. The energy demand growth and increase of manufacturing activities in the region could lead us to invest into the downstream oil and gas sector.
	●	Maintain balance sheet strength to offset commodity cyclicality. We intend to fund our exploration and production activities with equity, free cash flow and a moderate use of debt. With the uncertainty within our sector, we believe that maintaining a strong balance sheet will be critical to our growth.

 

Competition

 

We face competition from other oil and gas companies in the acquisition of new oil blocks through the Indonesian government’s tender process. Our competitors for these tenders include Pertamina, the Indonesian state-owned national oil company (who can tender for blocks on its own), and other well-established large international oil and gas companies. Such companies have substantially greater capital resources and are able to offer more attractive terms when bidding for concessions. Therefore, to mitigate the risk of competition, our corporate strategy is to focus on small to “medium sized blocks” onshore that are most likely overseen by the larger competitor.

 

 

Facilities, Distribution and Logistics

 

We do not own any property or facilities. We lease our corporate headquarters in Jakarta, Indonesia, as well as a field office for our operations in Kruh Block. In Kruh Block, due to the cost recovery fiscal terms, the facilities, vehicles, machinery and equipment required for the production of oil and gas are leased by us. The diagram below depicts our current storage, distribution and logistics of the oil from our wells at Kruh to the delivery point to Pertamina:

 

 

Legal Framework for the Oil and Gas Industry in Indonesia

 

Background

 

Under Article 33(3) of the Constitution of the Republic of Indonesia, all natural resources, including all oil and gas resources, in Indonesia belong to the state and should be used for the greatest benefit of the citizens of Indonesia. As a result, while the Government controls and manages oil and gas resources by, among other things, granting licenses or concessions to third party contractors such as our company, it retains ultimate control over all oil and gas activities in Indonesia.

 

 

Prior to the Law No. 22 of 2001 on Oil and Gas (which we refer to herein as the Oil and Gas Law), the Government controlled all oil and gas undertakings in Indonesia and granted Perusahaan Pertambangan Minyak dan Gas Bumi Negara (the predecessor to Pertamina, as described below) the exclusive right to manage and carry out all operations within the territory of Indonesia. Any other enterprise seeking to invest in the Indonesian oil and gas sector required the appointment or approval of the MEMR, and any actual investment would be done through a contractual arrangement with Pertamina. Most of these arrangements took the form of production sharing arrangements such as PSCs, TACs, and KSOs entered into between Pertamina and the contractors.

 

Beginning with the Oil and Gas Law in 2001, the Government adopted a series of measures to introduce market reform into Indonesia’s oil and gas sector. The Oil and Gas Law remains the primary umbrella legislation governing all oil and gas activities in Indonesia. It places control over the oil and gas industry in the hands of the MEMR and the DGOG. It also established two new governmental bodies – the Oil and Gas Upstream Regulatory Body (Badan Pelaksana Minyak dan Gas Bumi, or BP Migas) and the Oil and Gas Downstream Regulatory Body (Badan Pengatur Hilir Minyak dan Gas Bumi, or BPH Migas) – to regulate activities in their respective sectoral areas. The Oil and Gas Law also divides and for the first time distinguishes between upstream and downstream activities. Further regulations elaborate and implement important aspects of the Oil and Gas Law.

 

Following the transfer of Pertamina’s control over exploration and production activities in the territory of Indonesia to BP Migas, Pertamina was converted under Government Regulation No. 31 of 2003 converted Perusahaan Pertambangan Minyak dan Gas Bumi Negara into a for-profit, state-owned company in the form of a limited liability company (known as a Perseroan). Further, Government Regulation No. 35 of 2004 on Upstream Oil and Gas Business as amended several times, most recently by Government Regulation No. 55 of 2009 on Second Amendment to the Upstream Oil and Gas Business (or GR 35/2004), transferred Pertamina’s responsibility for managing all production sharing arrangements (except TACs) to BP Migas. These changes have left the reformed Pertamina free to tender for contracts on an equal basis with other companies. Pertamina also split its upstream and downstream operations by incorporating subsidiaries which specifically engage in either upstream or downstream activities. Pertamina’s subsidiary in charge of the upstream activities is PT Pertamina EP (or Pertamina EP) while there are several Pertamina’s subsidiaries established for the downstream activities.

 

On November 13, 2012, the Constitutional Court of the Republic of Indonesia (Mahkamah Konstitusi Republic Indonesia, or MK) issued Decision 36/PUU-X/2012 (which we refer to as MK Decision 36/2012), which found the transfer of authority to BP Migas under the Oil and Gas Law unconstitutional, ordering the regulatory body be dissolved and all its authority and responsibilities be transferred to the Government through the MEMR. Following a series of Presidential and Ministerial regulations, the duties and functions of BP Migas ultimately were transferred to the Interim Taskforce for Upstream Oil and Gas Business Activities (Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi, or SKK Migas) in 2013. As a consequence, production sharing contracts (except TACs) that had previously been transferred to BP Migas from Pertamina were then transferred to SKK Migas. As for TACs, they remain with Pertamina.

 

Executing Agency for Upstream Activities

 

Indonesian law currently distinguishes between upstream activities (encompassing the exploration and exploitation of oil and gas resources) and downstream activities (comprising the processing, transporting, storing, and trading of oil and gas). As described above, the distinction between the two types of activities was introduced in the Oil and Gas Law in 2001. Prior to this, Indonesian law did not recognize any market segmentation, and Pertamina was responsible for all aspects of oil and gas operation activities.

 

The Oil and Gas Law extends this sectoral division to the regulatory bodies established under such law, with BP Migas assuming responsibility for regulating upstream activities and BPH Migas assuming responsibility for downstream activities and both reporting to the DGOG. Furthermore, the Oil and Gas Law and Government Regulation No. 42 of 2002 on Executing Agency for upstream Oil and Gas Business Activities together required that, once established, BP Migas take over Pertamina’s existing production sharing arrangements and that BP Migas become the Government party to subsequent arrangements.

 

MK Decision 36/2012 dissolved BP Migas and transferred its authority and responsibility back to the MEMR until a new oil and gas law is adopted. In reaching its decision, the MK found that Article 33(3) of the Indonesian Constitution required the Government to manage oil and gas resources directly and that the supervisory duties given to BP Migas fell short of that requirement. It also found that the Government’s monitoring and regulatory activities under BP Migas had deteriorated to the point where it no longer met its constitutional obligations.

 

 

On the same day as the MK’s decision, both the President and the MEMR responded to MK Decision 36/2012 by issuing, in order, Presidential Regulation No. 95 of 2012 on the Transfer of Duties and Functions of Upstream Oil and Gas Activities (or PR 95/2012), which transfers BP Migas’ authority and responsibilities to the MEMR. In addition, PR 95/2012 upholds existing arrangements by confirming that all PSCs signed by BP Migas would remain valid until their respective expiration dates. MEMR Regulation No. 3135 K/08/MEM/2012 on Transfer of Duties, Functions and Organizations in Execution of Oil and Gas Business (or MEMR Regulation 3135/2012), which transfers those duties to the Interim Task Force for Upstream Oil and Gas Business Activities (Satuan Kerja Sementara Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi) as the implementation regulation of PR 95/2012. The Interim Task Force for Upstream Oil and Gas Business Activities is accountable to the MEMR.

 

Following the enactment of PR 95/2012 and MEMR Regulation 3135/2012, on January 10, 2013 the President issued Presidential Regulation No. 9 of 2013 on the Implementation of Management of Natural oil and Gas Upstream Business Activities, as amended by the Presidential Regulation No. 36 of 2018 (or PR 9/2013), which established SKK Migas and transferred the authorities to manage upstream oil and gas activities which are based on cooperation contracts to the new regulatory body. PR 9/2013 also establishes a Supervisory Commission, whose membership consists of the MEMR as Chairman, the Vice Minister of Finance, who manages the State Budget as the Vice Chairman, the Chairman of the Capital Investment Coordinating Board, Minister of Environment and Forestry, Chief of National Police and the Vice Minister of the MEMR, so that SKK Migas can control, supervise, and evaluate the management of the upstream oil and gas business activities under its authority. The Supervisory Commission is required to submit a report to the President at least once every six months.

 

Foreign Direct Investment in the Oil and Gas Industry

 

Private investment in upstream interests in Indonesia can be made through either a “business entity” or a “permanent establishment”. The Oil and Gas Law defines “business entity” as a legal entity which is established under the law of and domiciled in the Republic of Indonesia, which operates in Indonesia, and which undertakes business permanently and continuously in Indonesia. Such business entities usually take the form of a limited liability company (Perseroan Terbatas). The Oil and Gas Law defines “permanent establishment” as a legal entity which is established outside of Indonesia which undertakes activities within the Indonesian territory and complies with the prevailing Indonesian laws. The permanent establishment allows foreign investors to conduct upstream activities through a branch of a foreign incorporated enterprise.

 

Law 6/2023 amended several provisions of the Oil and Gas Law. However, the changes were relatively limited pending the enactment of the proposed amendments to the Oil and Gas Law. The Government has since issued Government Regulation No. 5 of 2021 on Implementation of Risk-based Licensing, which serves as an implementing regulation to the Omnibus Law and which, among others, extends the requirement to obtain a Business Registration Number (Nomor Induk Berusaha or NIB) to oil and gas contractors which operate as “permanent establishments”.

 

Business entities and permanent establishments carry out upstream activities as contractors under a cooperation agreement with the representative of the Government. The Oil and Gas Law stipulates that a contractor may only be awarded one cooperation agreement for one working area as an implementation of the “ring-fencing” principle where revenues and costs in respect of one working area under one cooperation agreement cannot be consolidated with and used to relieve the tax obligations of another working area under a different cooperation agreement.

 

As our operating subsidiaries are each a Perseroan domiciled in Indonesia, we operate under the “business entity” regime of the Oil and Gas Law.

 

 

Upstream Regulations

 

Upstream activities are conducted in working areas whose boundaries are determined by the MEMR. Each contractor may only be granted one working area; as a result, upstream oil and gas companies operating in Indonesia, such as ours, incorporate separate legal entities for each asset in which they have an interest. Upstream activities are performed through cooperation contracts between either SKK Migas or Pertamina and contractors. Unlike any other industry in Indonesia, upstream oil and gas activities are open to participation by foreign business entities that are established and incorporated outside Indonesia.

 

MEMR Regulation No. 35 of 2021 on Procedures of Determining and Bidding Oil and Gas Working Areas (or MEMR Regulation 35/2021) regulates the awards of work areas, which may be granted on the basis of either a competitive tender process or a direct offer. The Director General of the DGOG may put a working area out to tender and invite bids for an interest in the area after considering the opinion and inputs of SKK Migas. Direct offers shall be performed based on a contractor’s written proposal for a working area that has not been reserved for the bidding process; if the Director General of the DGOG approves such proposal, the contractor must conduct a survey together with the DGOG to locate potential oil and gas fields (which we refer to as a Joint Study).

 

Joint Study Agreement

 

Pursuant to MEMR Regulation 35/2021, where an area has not already been reserved for the bidding process, a contractor may bid for such working area directly by providing the Director General of the DGOG with a written proposal. If the Director General approves the proposal, the contractor must conduct a Joint Study of the proposed area with the DGOG or any other party appointed by the DGOG. The Joint Study is conducted for the purposes of upgrading the data quality of geological and geophysical work such as field surveys, magnetic surveys, or the reprocessing of existing seismic lines, and is conducted over an eight-month period with a single possible extension of up to four months. Contractors are required to deliver a performance bond in the amount of US$500,000 from a well-known bank during the Joint Study, to be submitted 14 days from the date the Director General approves the direct offer; to bear all the costs, which generally range from US$500,000 to US$700,000, and risks in implementing the Joint Study; and to maintain the confidentiality of data used and produced in the Joint Study. Upon completion of the Joint Study, the Director General may choose to announce a bidding process for the working area, in which case the contractors who conducted the Joint Study will have the right to change their offer (right to match) in the bidding process if the other bidders give higher offers, but otherwise receive no preferential treatment.

 

In May 2018, we were awarded the rights to explore the Citarum Block by the MEMR through a direct tender process after a Joint Study in the Citarum area was completed.

 

Cooperation Contracts

 

“Cooperation contract” is a general term used under the Oil & Gas Law to describe the contract between the contractor and the representative of the Government which can be entered into by the parties in various forms, such as PSCs (Production Sharing Contracts), TACs (Technical Assistance Contracts), and KSOs (Joint Operation Partnership). Regardless of the form, the cooperation contracts essentially provide for production sharing arrangements. For example, title over resources in the ground remains with the Government (and title to the oil and gas lifted for the contractor’s share passes at the point of transfer, usually the point of export), ultimate management control is with SKK Migas, and capital requirements and risks are to be assumed by the contractors. These cooperation contracts are to be entered into with SKK Migas and thereafter notified in writing to the Indonesian Parliament. Only one working area will be given to any legal entity. Cooperation contracts can be made for a maximum term of 30 years and can be extended for a maximum of 20 years. Cooperation contracts are divided into exploration and exploitation stages. The exploration stage is for a term of six years, subject to only one extension for a maximum of four years.

 

The implementation regulations for the upstream sectors, such as GR35/2004, reiterate the obligation by a contractor to offer a certain minimum participating interest to domestic parties, such as regional government-owned enterprises, although the procedure for, and timing of, offering such an interest has been modified. The MEMR has a right to request that a contractor who wishes to sell its participating interest under a production sharing arrangement grants a right of first offer to national enterprises such as regional government-owned companies, central government-owned companies, cooperatives, small scale businesses and Indonesian companies wholly-owned by Indonesians. Under the existing upstream regulations, such an offer must be made on an “arms-length” basis. These modifications are applicable only to the cooperation contracts entered into after the issuance of the Oil and Gas Law in 2001.

 

 

The following principles provide the basis for all types of production sharing arrangements between the Government and private contractors:

 

	●	The contractors are responsible for all investments and production costs (exploration, development, and production), including provision of capital to implement the agreed work program;
	●	The operational risk in performing upstream activities under the contracts is borne by contractors;
	●	The profits are split between the Government and contractors based on production (the split depends on the fiscal terms adopted by the PSCs, namely the cost-recovery model or the gross-split model);
	●	The ownership of all tangible and intangible assets remains with the Government; and
	●	The overall management and control remain with SKK Migas (previously BP Migas) on behalf of the Government.

 

PSCs (Production Sharing Contracts)

 

The PSC is the most common type of production sharing arrangement. PSCs have been granted in respect of exploration properties and are awarded for the exploration for oil and gas reserves and the establishment of commercial production of those resources.

 

Under a PSC, the Government, through SKK Migas, allows one or more contractors to explore, develop, and produce oil and gas reserves and resources in a designated working area. Accordingly, PSCs are entered into with SKK Migas and approved by the co-signature of the MEMR on behalf of the Government. Each PSC is based on a standard form contract and typically contains provisions such as:

 

	●	The requirement for the contractor to pay to the Government certain signature bonuses, yearly administrative fees, royalty payments, production-level payments, and the payment of certain bonuses upon the achievement of certain production milestones for the working area;
	●	The term of the initial exploration and development period, with an option for the parties to agree to extend this period;
	●	The obligations of the contractor to bear the risk and costs of exploration and development activities and/or production operations;

 

	●	The scope and schedule for the contractor (and any other operators of the working area) to undertake exploration and production activities;
	●	Save for the gross-split PSCs (as discussed below), the ability of the contractor, if commercial production is successful, to recover its exploration, development and production costs out of the oil and gas produced after deduction of the First Tranche Petroleum or FTP). The percentage of FTP portion is 10 percent of the oil and gas produced if the FTP is allocated entirely to the Government or 20 percent if it is shared between the Government and the contractor in the same proportion as the percentage for profit sharing;
	●	The percentage allocation of total oil and gas production between BP Migas (now SKK Migas) and the contractor out of FTP and the following recovery by the contractor of their costs;
	●	The requirement for the contractor to supply the Indonesian domestic market at a discounted price with a certain percentage, usually 25 percent, of the contractor’s share of total oil and gas produced (this is referred to as the domestic market obligation, or DMO);

 

 

	●	The requirement that the title to petroleum at all times lies with the Government, except where the title to crude oil or gas has passed in accordance with the provisions of the PSC;
	●	The obligation of the contractor to pay the Indonesian corporate taxes on its share of profits, including FTP;
	●	The requirements for the contractor to provide financial and performance guarantees to BP Migas (now SKK Migas) to secure the contractor’s firm commitments;
	●	The requirements for the contractor to market the oil and gas produced; and
	●	The requirement (such as exists in our PSC for Citarum Block) for the contractor to relinquish specified percentages of the working area, which are not required for production and/or in which hydrocarbons have not been discovered by specified times.

 

Pursuant to GR 35/2004, once the approval of the field development plan for first production from a working area has been received, contractors are required to offer up to a 10 percent participating interest to a regional government-owned enterprise (Badan Usaha Milik Daerah). In the event the regional government-owned enterprise does not accept such offer within 60 days after the offer, the contractor must offer such participating interest to national enterprises such as regional government-owned companies, central government-owned companies, cooperatives, small scale businesses, and Indonesian companies wholly-owned by Indonesians. If no such enterprise accepts the offer within 60 days of the offer being made, then the offering is closed.

 

The MEMR issued MEMR Regulation No. 37 of 2016 on Terms of Bidding Participating Interest 10.0% in Oil and Gas Working Areas (known as the MEMR Regulation 37/2016) which operates as the implementation regulations for the offering by the contractors of the 10 percent participating interest in the oil and gas working areas to regional government-owned enterprises. MEMR Regulation 37/2016 restricts the right to bid to regional government-owned enterprises which meet the following requirements (i) the entities must be incorporated either as a regional company (commonly known as BUMD) with the shares wholly owned by the regional government, or as a limited liability company where at least 99% of its shares are owned by regional government; (ii) their status of the regional government-owned enterprise was established through the enactment of a local regulation; and (iii) their businesses are limited only to engage in participating interest management business. Each regional government-owned enterprise can only hold participating interest management in one working area.

 

Where a PSC involves more than one contractor, the contractors may enter into a joint operating agreement (or JOA) with the other holders of participating interests under the PSC. Pursuant to this JOA, each participant agrees to participate in proportion to its respective equity interest in all costs, expenses, and liabilities incurred in conjunction with petroleum operations in the working area and each participant will own, in the same proportion, the contractual and operating rights in the PSC. One participant is appointed operator and, subject to the terms of the operating agreement and supervision by the operating committee, which consists of one representative appointed by each party, the operator is vested with the discretion to manage all petroleum operations in the working area. In doing so, the operator is obliged to use its best efforts to conduct the petroleum operations in accordance with generally accepted practices in the petroleum industry and receives an indemnity from the other contractors for acting in the capacity of operator. An operating agreement generally continues in effect for the term of the PSC.

 

Extension of PSCs

 

Pursuant to the Oil and Gas Law and GR 35/2004, PSCs may be extended for a period of not more than 20 years for each extension. A contractor who intends to extend its PSC must submit a request to the MEMR through SKK Migas. Then, SKK Migas evaluates the request and submits it to the MEMR for consideration. A request for an extension of a PSC may be submitted no sooner than ten years and no later than two years before the expiry date of the PSC. However, if the contractor has entered into a natural gas sales/purchase contract, such contractor may request an extension of the PSC earlier than ten years prior to the expiry date of the PSC.

 

 

In granting approval, the MEMR shall consider, among other things, the potential reserves of oil and/or gas from the work area concerned, the potential or certainty of market/needs, and the technical/economic feasibility of the activities. Based on its consideration, the MEMR may reject or approve such request.

 

PSC Financial Terms

 

In January 2017, a new production sharing regime of PSC, called “gross-split”, was introduced, while the previously introduced “cost recovery” PSCs remain in place until the expiry of the relevant PSCs. Under the gross-split PSCs, the Government and the contractor are allocated a “base split” of oil or gas production, where the split percentage will be adjusted by certain components set out in the PSC. In contrast with the gross-split PSCs where production sharing is done at the beginning, without production being allocated towards recovery of the contractor’s operating costs first, the cost recovery PSCs provide for production to be shared between the Government and the contractor through a “cost recovery” mechanism. After the production is reduced by certain costs and deductibles, the remaining oil or gas will then be split between the Government and the contractor based on the agreed percentage set forth in the PSC.

 

We are a party to the gross-split PSC with respect to our operations in Citarum Block. Financial terms of our PSC are described above under “—Our Assets—Citarum Block.” Further details on the gross-split and cost recovery PSCs are set out below.

 

Gross-Split PSCs

 

In January 2017, a new fiscal regime was introduced by MEMR where gross production of oil and gas is to be divided between the contractor and the Government based on certain percentages in respect of (a) the crude oil production and (b) the natural gas production. This mechanism is known as “gross split”. Under the gross split sharing concept, the starting point for determining the relevant percentage of the contractor’s share is the “base split” percentage, which will then be adjusted upon the plan of development approval according to the “variable components” and “progressive components”. In short, the contractor’s share equals to the “base split” plus or minus the “variable components” plus or minus “progressive components”.

 

The base split, pursuant to the MEMR Regulation No. 08 of 2017 (MEMR 08/2017) as amended by the MEMR Regulation No. 52 of 2017, the MEMR Regulation No. 20 of 2019 (MEMR 20/2019) and lastly by MEMR Regulation No. 12 of 2020 (MEMR 12/2020), is currently set at, for gas, 52% for the Government and 48% for the contractor and for oil, 57% for the Government and 43% for the contractor. The percentage of variable components is determined based on, among others, the status of the work area, the field location, reservoir, supporting infrastructure, carbon dioxide and hydrogen sulfide content and compliance with local content requirements. The latest percentage of each variable component is detailed in the schedule to the MEMR 20/2019. For the progressive components, the adjustment is made by taking into account oil price, gas price and the cumulative oil and gas production. Current details on the split adjustment based on the progressive components are provided for in the MEMR 20/2019.

 

The concerns over the new Gross Split PSC introduced in 2017 may be relieved with issuance of MEMR Regulation No. 12/2020 in July 2020 which opens the door to oil and gas investors to elect to use the previous conventional cost recovery scheme, that is perceived to provide better investment returns. However, the oil and gas landscape both in Indonesia and globally has only worsened due to the COVID-19 pandemic which has significantly reduced energy demand and consequently hydrocarbon prices. With all those negative conditions, SKK Migas in June 2020 launched a comprehensive reforms initiative with a goal to achieve production of one million barrels of oil per day (BOPD) and 12 billion standard cubic feet per day (Bscfd) of gas production by 2030.

 

Depending upon the particular oil and gas field and related economic considerations, the MEMR may adjust the split in favor of either the contractor or the Government. The gross split is calculated based on gross production split, without regard to the cost recovery approach. Contractors who have entered into the PSCs prior to the issuance of MEMR 08/2017 may propose to amend the sharing mechanism under their existing PSCs to the gross split mechanism. The latest iteration of the gross-split PSCs fiscal terms are provided for in Government Regulation No. 53 of 2017, promulgated on 28 December 2017, regarding the Tax Treatment for the Upstream Oil and Gas Activities with Gross-Split Production Sharing Contracts (GR 53/2017).

 

 

Key points of GR 53/2017 include:

 

	●	“Taxable income” is to be the contractor’s “gross income” less “operating costs” but with a 10 year tax loss carry forward entitlement;
	●	The gross split taxing point begins at the “point of transfer” of the relevant hydrocarbon to the contractor;

 

	●	The value of oil is to be determined using the Indonesian Crude Price and that the value of gas is to be determined via the price agreed under the relevant gas sales contract;
	●	Income separately arising from “uplifts” is subject to tax at a final rate of 20% of the uplift amount;
	●	Certain tax facilities or incentives may be given to the contractors from the exploration and exploitation stages up to the commencement of commercial production. Such incentives are, amongst other things, the exemption of import duties on the import of goods used in petroleum activities and the deduction of land and building tax amounting to 100 percent of the land and building tax payable amount. Further provisions regarding the granting of facilities will be regulated by a ministerial regulation, which, to date, has not been issued.

 

 

On May 23, 2023, the MEMR made a press release announcing that the Government planned to revise the existing regulations to provide for a “new simplified gross split” arrangement. Aside for improving the investment climate in the oil and gas industry, the revisions are primarily intended to achieve the following objectives:

 

(i) Increasing the contractor’s production share (before tax) to become within the range of 80% - 90% of the gross production, depending on the risk profile of the working area;

 

(ii) Reducing the need for the contractor to rely on the Minister’s discretionary decision (to award additional split) to increase the economics of the working area;

 

(iii) Reducing the components and parameters for the split; and

 

(iv) Designing fiscal policies that are better suited for unconventional oil and gas development.

 

Such revisions will be effected through an amendment to MEMR 08 of 2017.

 

Cost Recovery PSCs.

 

Until 2017, all Indonesian PSCs adopted the “cost-recovery” concept and their fiscal terms reflects such a concept, the “cost recovery” approach requires the contractor to, among other things, prepare work program and budget which needs to be approved by SKK Migas and submit a request for approval for expenditure (or AFE) prior to performing a certain activity. Under this scheme, a waterfall mechanism is used in the sharing of the oil/gas production between the contractor and the Government – the oil/gas production will be deducted by, first, the FTP and then tax and subsequently, the (approved) cost recovery amount. The remaining oil/gas will then be split between the Government and the contractor based on the agreed percentage set forth in the PSC. The following flow chart of the cost-recovery PSC illustrates the sharing of oil and gas production between the Government and the contractor.

 

 

The latest iteration of the cost-recovery PSCs fiscal terms is found in Government Regulation No. 27 of 2017 on the Amendment of Government Regulation No. 79 of 2010 on the Operating Costs that May Be Recovered and Income Tax Treatment for Upstream Oil and Gas Activities (or GR 27/2017, which amended GR 79/2010). GR 27/2017, which came into effect on June 19, 2017, regulates the costs that cannot be recovered in the calculation of profit sharing and income tax. Such costs include costs incurred for the personal interests of the participating interest holders, penalties imposed due to violations of any laws by the contractor, depreciation costs, legal consultant (which is not directly related to the oil and gas operation activities) and tax consultant fees, and bonuses payable to the Government. GR 27/2017 also regulates the income tax applicable to the transfer of participating interests and any other activities conducted by PSCs, and requires the contractor to have its own tax identification number.

 

The provisions of GR 27/2017 only apply to contracts entered into and extensions of contracts after the issuance of GR 27/2017. Additionally, for contracts in existence up to the issuance of GR 79/2010 to remain in force until their expiration date, they must be adjusted to comply with GR 27/2017 in areas not previously or not sufficiently clearly regulated. Such provisions include provisions related to:

 

	●	The Government’s interest in the PSC;
	●	The terms for operating costs which can be recovered and the standard norms for operating costs;
	●	Non-recoverable operating costs;
	●	Third-party appointments to conduct financial and technical verification;
	●	The issuance of income tax assessments;
	●	Import duties and import tax exemptions on the importation of goods for exploration and exploitation activities;
	●	Contractors’ income taxes in the form of oil and/or gas volume from contractor entitlement; and
	●	Income from outside the contract in the form of uplift and/or participating interest transfer, must be adjusted to comply with GR 27/2017.

 

The implementing regulations for GR 79/2010 and GR 27/2017 cover various subjects, from the method for determining the Indonesian Crude Price issued by the MEMR, the terms and conditions for indirect head office cost recovery, procedures for withholding and remitting income tax arising from other income in the form of uplift or other similar compensation and contractor’s income from participating interest transfer, to subjects such as the maximum remuneration that can be cost recovered by the contractor issued by the Indonesian Minister of Finance (or MoF).

 

GR 79/2010, the provisions of which are maintained in GR 27/2017, also stipulates that income arising from a direct or indirect transfer of a participating interest is subject to a final income tax at 5.0 percent or 7.0 percent of the gross proceeds for the exploration stage or exploitation stage, respectively. Subject to satisfying certain requirements, a transfer of a risk-sharing participating interest during the exploration stage is not included as a taxable participating interest transfer.

 

MoF Regulation No. 257/PMK.011/2011 dated December 28, 2011 (or MoF 257/2011) further stipulates that taxable income, after deduction of final income tax on uplift and/or participating interest transfer, is subject to branch profit tax in accordance with the income tax law. GR 27/2017 has introduced tax facilities that exempt such taxable income, after deduction of final income tax on uplift and/or participating interest transfer, from branch profit tax. However, it remains unclear whether these tax facilities can be applied to the participating interest transfer in relation to PSCs entered into or extended prior to the enactment of GR 27/2017. In addition, although technically GR 27/2017 should override the contents of MoF 257/2011, it is uncertain whether another implementing regulation is needed to revoke MoF 257/2011.

 

 

With regards to land and building tax, under the Regulation of Director General of Tax No. PER-45/PJ/2013, effective as of January 1, 2014 (or DGT Regulation 45/2013), the land and/or buildings located within and outside (i.e., the supporting area for the oil and gas mining activity that physically forms an inseparable part of the onshore and offshore area) the working area utilized for oil and gas mining activities and geothermal was subject to land and building tax. DGT Regulation 45/2013 defines “land” as both the onshore and offshore areas, including depth measurements. The onshore area which was subject to land and building tax included the productive, not yet productive, not productive, and emplacement areas while the offshore area which was subject to land and building tax was defined as offshore waters within and outside (i.e., the supporting area for the oil and gas mining activity that physically forms an inseparable part of the onshore and offshore area) the working area utilized for upstream oil and gas business activities, whereby the taxpayer had rights and/or received benefits over such area. Not all onshore and offshore areas were subject to land and building tax as the regulation exempted land, inland waters, and offshore waters within the working area which, among other things, did not create a benefit for the taxpayer in respect of its oil and gas activities. DGT Regulation 45/2013 also provided the formula for calculating the amount of tax to be paid during the exploration and exploitation periods.

 

However, on November 27, 2020, the Directorate General of Tax issued Regulation of Directorate General of Tax No. PER-22/PJ/2020 of 2020 (or DGT Regulation 22/2020), which revokes 10 regulations, including DGT Regulation 45/2013, in an attempt to simplify the regulations. However, it is not entirely clear how the revocation of DGT Regulation 45 of 2013 would affect the obligations to pay land and building tax in the oil and gas sectors, including on how the tax is to be assessed.

 

On December 31, 2014, the MoF issued Regulation Number 267/PMK.011/2014 on Land and Building Tax Reduction for Oil and Gas Mining at the Exploration. This regulation, which became applicable in 2015, grants land and building tax incentives for the subsurface at the exploration stage. The tax reduction incentive can be granted on a yearly basis for a maximum of six years from the signing of the PSC and can be extended by up to four years and can be obtained if the PSC with the Government is signed after the enactment of GR 79/2010 (i.e., after December 20, 2010), the Tax Object Notification Form (Surat Pemberitahuan Objek Pajak, or SPOP) has been submitted to the relevant tax office, and there is a recommendation letter from the MEMR attached to the SPOP stating that the land and building tax object is still at the exploration stage.

 

GR 27/2017 also provides for complete exemptions of land and building tax during the exploitation and exploration period. Exemptions for the land and building tax during exploitation period for the subsurface part can be granted by the MoF upon consideration of economics of the project. The provisions of GR 27/2017 on tax facilities related to land and building tax are subject to further regulation by the MoF. GR 27/2017 extended the benefits of the facilities under the regulation to parties to PSCs signed or extended prior to the application of the regulation if they chose to adjust the existing contract to fully comply with the regulation within six months after the effective date (i.e., by December 19, 2017).

 

TACs (Technical Assistance Contracts)

 

TACs are another form of production sharing arrangement created under the regulatory framework that preceded the Oil and Gas Law of 2001. TACs were awarded for fields having prior or existing production and are valid for a specified term. The oil or gas production is divided into non-shareable and shareable portions. The non-shareable portion represents the production which is expected from the field (based on historic production) at the time the TAC is signed. Under a TAC, the non-shareable portion declines annually. The shareable portion corresponds to the additional production resulting from the operator’s investment in the field and is further split in the same way as a PSC. Pursuant to the Oil and Gas Law of 2001 and GR35/2004, existing TACs shall remain with Pertamina and are not renewable after the expiry of the initial term. In practice, the contractors may “renew” their TAC contracts with Pertamina by entering into the KSOs with Pertamina EP.

 

Our Kruh Block operatorship was under a TAC until May 2020, under which we were entitled to recover our share of past exploration and development costs and ongoing production costs of maximum 65% per annum and if those costs exceed the stated 65%, then the unrecovered surplus would be recovered in the succeeding years. Together with our share split, our monthly revenue was around 74% of the total production times Indonesian Crude Price during the TAC term. In May 2020, our Kruh Block operatorship was “renewed” under a KSO for an additional 10 years. Under KSO, part of the revenue. would be recognized based on the prevailing ICP through GWN from the 65% of monthly proceeds as monthly cost recovery entitlement, which was different from TAC and would exclude all previous right form TAC to recover previously unrecovered costs.

 

 

JOBs (Joint Operating Bodies)

 

JOBs are another form of production sharing arrangement created under the regulatory framework that preceded the Oil and Gas Law of 2001. In a JOB, operations are conducted by a JOB headed by Pertamina and assisted by one or more private sector energy companies through their respective secondees to the JOB. In a JOB, Pertamina is entitled to a specified percentage of the working interest in the project. The balance, after production is applied towards cost recovery and cost bearing as between Pertamina and the private sector participants, is the shareable portion which is generally split in the same way as for an ordinary PSC. Unlike TACs, GR35/2004 transferred the rights to operations under existing JOBs from Pertamina to SKK MIGAS by law. JOBs are not renewable after the expiry of their initial term.

 

We are not currently a party to any JOBs.

 

KSOs (Kerja Sama Operasi or Joint Operation Partnership)

 

KSOs are contractual arrangement between Pertamina EP and the contractor on the provision of technical assistance by the contractor to Pertamina EP for a certain work area. Unlike the cooperation contracts, the KSO does not create a contractual relationship between the contractor and the authority, i.e. BP Migas or SKK Migas. The contractors will have a contractual relationship with Pertamina EP instead. Pertamina EP’s authorization to award the KSOs to contractors is stated in the PSC which Pertamina EP entered into with BP Migas (now SKK Migas) in 2005. The terms of such PSC specify, among other things, that:

 

	●	The KSO must first be reviewed by SKK Migas;
	●	The KSO contractor will receive compensation from a portion of the oil and gas entitlement of Pertamina EP under its PSC with BP Migas (now SKK Migas);
	●	The compensation given to the KSO contractor shall not exceed the production sharing entitlement of other parties who enter into a cooperation contract with BP Migas (now SKK Migas) in the surrounding area; and
	●	The compensation given to the KSO contractor may be sourced from the proceeds of Pertamina EP’s entitlement which is calculated at the delivery point pursuant to the terms of the KSO.

 

Environmental Regulations

 

Indonesian law requires companies whose operations have a significant environmental or social impact to create and maintain one of two documents. Where a company’s operations meet or exceed a specified threshold, that company must obtain an AMDAL. The Minister of Environment and Forestry Regulation No. 4 of 2021 on List of Business Plan and/or Activities Requiring Environmental Impact Analysis, Environmental Management Efforts and Environmental Monitoring Efforts or Statements of Ability to Manage and Monitor the Environment requires companies whose operations involve the exploitation of oil and gas; and development of production facility, and whose operations meet the environmental or social impact threshold, to create and maintain an AMDAL. Where operations do not reach the threshold required for an AMDAL but still have an appreciable environmental or social impact, the company must prepare an Environmental Management Effort-Environmental Monitoring Effort (Upaya Pengelolaan Lingkungan Hidup dan Upaya Pemantauan Lingkungan Hidup, or UKL-UPL). Finally, in instances where operations do not reach the threshold required for a UKL-UPL, the company must prepare a Statement of Ability to Manage and Monitor the Environment.

 

 

There are a number of other key obligations that companies involved in upstream oil and gas may be required to fulfill in order to monitor their environmental impact and ensure adequate resources are allocated to cleanup activities. GR 22/2021 requires business actors to submit reports detailing their disposal of wastewater and compliance with applicable regulations to the Environmental Information System, a newly established system to support environmental protection operations and management. Government Regulation No. 74 of 2001 on Management of Hazardous or Toxic Materials (Bahan Berbahaya dan Beracun) requires companies using or producing specified hazardous materials such as flammable, poisonous, or infectious waste to obtain a revocable permit in relation to their activities and subjects mining operations to controls on the disposal of such materials. The Environmental Law requires the environmental license holder to create an environmental deposit fund for the restoration of the environment in a state-owned bank appointed by the MEF, Governor, Regent, or Mayor in accordance with their authority, who also has the authority to appoint a third party to conduct the restoration of the environment using the environmental deposit fund (this is to be detailed in an implementing regulation, which to date has not been issued). GR 35/2004 also requires contractors to allocate environmental deposit funds for the restoration of the environment after decommissioning, the amount of which is to be determined each year in conjunction with the budgets for operating costs and included in the work program and annual budget.

 

In addition to the environmental deposit funds allocated for environmental restoration, on February 23, 2018 the MEMR issued MEMR Regulation No. 15 of 2018 on the Post-Operation Activities in Upstream Oil and Gas Business Activities (or MEMR Regulation 15/2018), which requires all contractors who are parties to an unexpired PSC to set aside certain amounts in an abandonment and site restoration (ASR) fund deposited in a bank account held jointly with SKK Migas from the start of commercial operations until the expiry of the PSC. Moreover, on September 12, 2018, SKK Migas issued the Guidance of Abandonment and Restoration No.KEP-0087/SKKMA0000/2018/S0 of 2018 and Working Procedure Guidelines No. PTK-040/SKKMA0000/2018/S0 (or the Restoration Guidance) as guidance for the implementation of abandonment and site restoration (or ASR) activities for upstream oil and gas business activities. Under the Restoration Guidance, the contractor must prepare an ASR report in relation to existing assets, assets being constructed, and assets that will be constructed in accordance with the development plan that must contain estimates of ASR costs, and the total amount to be reserved as an ASR fund which is to be established with a reputable Indonesian bank as a joint account with SKK Migas. The contractor must also submit a report on the results of the implementation plan as well as the use of the ASR fund after completing its ASR activities to SKK Migas, which will evaluate the report submitted and issue a statement letter confirming completion of the ASR if the evaluation result is satisfactory.

 

We believe we are in compliance in all material respects with all applicable environmental laws, rules and regulations in Indonesia.

 

Labor Regulations Applicable to the Indonesian Oil and Gas Sectors

 

Save for certain limited exceptions, such as the working hours for the oil and gas sector discussed below, there are currently very few manpower regulations enacted specifically for the oil and gas industry. While certain operational guidelines, commonly known as “PTK”, issued by SKK Migas may establish additional requirements, such as age limitation for certain key positions, the oil and gas industry is subject to the labor regulations that are applicable generally in Indonesia.

 

Employment of Expatriates

 

Indonesian law generally requires contractors to give preference to local workers, but companies may use foreign manpower to bring in expertise not available in the local market. While several ministries are involved legally with manpower decisions, in practice SKK Migas often coordinates these issues, including controls on the number of expatriate positions. It reviews these positions, as well as contractor training programs for Indonesian workers, annually with a view to assessing the costs and benefits together with plans to localize expatriate positions. SKK Migas also requires contractors to submit organization charts for both nationals (known as RPTKs) and expatriates (known as RPTKAs) annually for review and approval.

 

Until recently, the employment of foreign manpower in the upstream and downstream sectors of the oil and gas industry was subject to additional requirements under MEMR Regulation No. 31 of 2013 on Expatriate Utilization and the Development of Indonesian Employees in the Oil and Gas Business (or MEMR31/2013). MEMR 31/2013 provided stringent regulations on the employment of expatriates, including a general obligation to prioritize the employment of Indonesian workers and specific prohibitions on hiring foreign manpower for certain roles such as human resources, legal, quality control, and exploration and exploitation functions below the level of superintendent. MEMR 31/2013 also permitted the use of foreign manpower in limited circumstances based on a stringent set of requirements such as age, relevant work experience, and willingness to transfer knowledge to the local workforce.

 

 

However, on February 8, 2018 the MEMR issued MEMR Regulation No. 6 of 2018 on the Revocation of the Regulations of the Minister of Energy and Mineral Resources, the Regulations of the Minister of Mining and Energy Regulations, and the Decisions of the Minister of Energy and Mineral Resources (or MEMR 6/2018). MEMR 6/2018 revokes 11 regulations which were deemed onerous in an attempt to, among other things, simplify the regulations in order to promote foreign investment in the energy and natural resources sectors. Among other things, MEMR 6/2018 revokes MEMR Regulation31/2013 and the Regulation of the Minister of Mining and Energy No. 02/P/M/Pertamb/1975 regarding the Work Safety on Distribution Pipes and other Facilities for the Transportation of Oil and Gas Outside of the Oil and Gas Working Area. As a result, expatriates are now subject to the Ministry of Manpower’s more relaxed requirements and certain positions that were previously restricted for expatriates have been opened for expatriates unless restricted under the general manpower regulations.

 

Contract Period

 

Law No. 13 of 2003 on Manpower, as amended by Law 6/2023 (or the Manpower Law), and Government Regulation No. 35 of 2021 on Temporary Employment Contract, Outsourcing, Working and Resting Time, and Termination of Employment Relationship (or GR 35/2021) stipulate that an employee can be hired under 2 schemes, either on a contract basis (temporary) or a permanent basis. For temporary employment contracts, the maximum period for the temporary employment contract is 5 years. Under the Manpower Law, temporary employment contracts are permitted only for works that are “temporary” in nature, such as seasonal works (e.g. crop harvesters) and project-based employments, such as construction works. Save for these types of works, workers are required to be employed on a permanent basis.

 

Statutory Benefits

 

Under Law No. 24 of 2011 on Social Security Administrative Bodies (or BPJS Law), a company is obligated to enroll its employees (including expatriates with an employment period of 6 months or more) for manpower social security programs with the Manpower Social Security Administrative Body (or BPJS Ketenagakerjaan) and Health Social Security Administrative Body (or BPJS Kesehatan). The coverage of BPJS Ketenagakerjaan includes, among other things, insurance for work-related accidents and pension/retirement. The premium payment arrangement for these programs vary from one program to the other. The insurance premiums for the work-related accidents, for example, is borne and paid by the employer while the premium payment for retirement insurance is shared between the employers and the employees.

 

Working Hours

 

The Manpower Law and the Minister of Manpower and Transmigration Regulation No. 4 of 2014 on Working and Resting Hours for the Oil and Gas Sector and GR 35/2021 regulate that the maximum working hours for 1 week is 40 hours, which can be divided for 5 or 6 days of work. If the working days in a week is 6, the maximum working hours per day is 7 and if the working days in a week is 5, the maximum working hours per day is 8.

 

Outsourcing

 

Pursuant to the Regulation of the Minister of Manpower and Transmigration No. 19 of 2012 on Requirements for Assignment of Parts of the Works to be Performed by Other Companies (or MoMT 19/2012), in general, a company may outsource a third party to perform certain work if such work is not the core activity of the company’s business. MoMT 19/2012 provides for two types of outsourcing schemes, namely “labor supply” scheme or “sub contract” scheme.

 

 

Under the “labor supply” scheme, works that may be outsourced are limited to menial activities or functions that are supportive in nature to the company’s operation and businesses or are indirectly related to the company’s production process. These activities are limited to (i) cleaning services, (ii) catering services, (iii) security services, (iv) supporting services in the mining and oil sectors, and (v) transportation service for employees (i.e. drivers for company’s cars only for picking up and delivering employees).

 

Under the “sub-contract” scheme or “cooperation” scheme, the outsourced functions must not be the “core” or the “main” business activities of the company. In addition, to be able to adopt the “cooperation scheme”, the company is required to prepare and register its business “flow-chart” with the relevant manpower office. Please note that to register such “flow-chart”, the company must apply and become a member at one of the business associations (whose members have identical business activities with the company) as the registration would need to be processed through such business association. Failure to meet any of these requirements will usually result in the issuance an order issued by the Ministry of Manpower to the violating company instructing such company to employ the “outsourced” personnel as a permanent employee with a retroactive effect.

 

Due to the enactment of the Omnibus Law, MOMT 19/2012 was revoked by Minister of Manpower Regulation No. 23 of 2021 and the restriction on the type of work that can be outsourced was abolished. Although GR 35/2021 includes certain provisions relating to outsourcing, it did not specifically limit the activities that can be outsourced to another company. The Omnibus Law however was later revoked by GR 2/2022 which re-introduced the restriction. GR 2/2022 stipulates that “certain work” that can be outsourced will be specified in an implementation regulation and as such, GR 35/2021 would likely need to be amended to reflect such changes. Until such amendments are enacted, the type of works that can be outsourced remain unclear.

 

Other Labor Compliance Obligations

 

Under Law No. 7 of 1981 on Mandatory Manpower Report, an employer is obligated to submit a mandatory manpower report consisting of among others the number of employees and the lowest to highest salary. In addition, the Manpower Law also requires a company that employs at least 10 employees to put in place a company regulation (or an employee handbook), which typically set forth general terms and conditions of employment such as number of leaves, procedure to take leave, working hours and disciplinary measure. Such company regulation must be registered with and ratified by the local manpower office. If there is a labor union in the company, the employer and the labor union may enter into a “collective labor agreement” which contents are often similar with the company regulation, and register the collective labor agreement with the local Manpower Office. If the employer and the labor union enter into a collective labor agreement, the preparation of company regulation by the company is not mandatory. We are not a party to any collective labor agreement.

 

History and Corporate Structure

 

We were incorporated on April 24, 2018 as a holding company for WJ Energy, which in turn owns our Indonesian holding and operating subsidiaries. We presently have one major shareholder, Maderic, which owns 51.34% of our issued and outstanding ordinary shares. Our Chairman and Chief Executive and certain of his family members own and control Maderic (see Item 7. Major Shareholders and Related Party Transactions).

 

WJ Energy was incorporated in Hong Kong on June 3, 2014. The initial shareholders of WJ Energy were Maderic and HFO Investment Group Ltd. (which is controlled by the adult sister of our Chief Investment Officer and director, James J. Huang) (or HFO), with each owning 50% of WJ Energy’s shares. On October 20, 2014, HFO received HKD 4,000 from Maderic as consideration for 4,000 shares in WJ Energy, which resulted in Maderic owning 90% of WJ Energy and HFO owning 10%.

 

On February 27, 2015, WJ Energy formed GWN as a vehicle to acquire and thereafter operate the Kruh Block. On March 20, 2017, PT Harvel Nusantara Energi, an Indonesian limited liability company (or HNE), was formed by WJ Energy as a required vehicle for oil and gas block acquisitions in compliance with Indonesian law. On June 26, 2017, Maderic sold 500 shares of WJ Energy to HFO in consideration of HKD 500. Concurrently, Maderic sold 1,500 shares of WJ Energy to Opera Cove International Limited, an unaffiliated third party (or Opera), in consideration of HKD 1,500. At the end of such transactions, the outstanding shares of WJ Energy were owned 70% by Maderic, 15% by HFO and 15% by Opera. On June 25, 2017, Maderic and Opera executed an entrustment agreement giving Maderic legal and beneficial ownership of the shares held by Opera. On December 7, 2017, PT Cogen Nusantara Energi, an Indonesian limited liability company, was formed under HNE as a required vehicle for the prospective acquisition of a new oil and gas block through a Joint Study program in consortium with GWN. On May 14, 2018, PT Hutama Wiranusa Energi, was formed under GWN as a requirement to sign the contract for the acquisition of Citarum Block as part of the consortium that conducted the Joint Study for the Citarum Block.

 

 

On June 30, 2018, we entered into two agreements with Maderic and HFO (the two then shareholders of WJ Energy): a Sale and Purchase of Shares and Receivables Agreement and a Debt Conversion Agreement (which we refer to collectively as the Restructuring Agreements). The intention of the Restructuring Agreements was to restructure our capitalization in anticipation of our initial public offering. As a result of the transactions contemplated by the Restructuring Agreements: (i) WJ Energy (including its assets and liabilities) became a wholly-owned subsidiary of our company, (ii) loans amounting to $21,150,000 and $3,150,000 that were owed by WJ Energy to Maderic and HFO, respectively, were converted for nominal value into ordinary shares of our company and (iii) we issued an aggregate of 15,999,000 ordinary shares to Maderic and HFO. The above-mentioned transaction is accounted for as a nominal share issuance (which we refer to as the Nominal Share Issuance). All number of shares and per share data presented in this report have been retroactively restated to reflect the Nominal Share Issuance.

 

This series of transactions resulted in the then ownership of our company prior to our initial public offering to be set at 87.04% owned by Maderic (13,925,926 ordinary shares), and 12.96% owned by HFO (2,074,074 ordinary shares), out of a total of 16,000,000 issued ordinary shares.

 

On November 8, 2019, we implemented a one-for-zero point three seven five (1 for 0.375) reverse stock split of our ordinary shares by way of share consolidation under Cayman Islands law (which we refer to herein as the Reverse Stock Split). As a result of the Reverse Stock Split, the total of 16,000,000 issued and outstanding ordinary shares prior to the Reverse Stock Split was reduced to a total of 6,000,000 issued and outstanding ordinary shares. The purpose of the Reverse Stock Split was for us to be able to achieve a share price for our ordinary shares consistent with the listing requirements of the NYSE American. Any fractional ordinary share that would have otherwise resulted from the Reverse Stock Split was rounded up to the nearest full share. The Reverse Stock Split maintained our founding shareholders’ then percentage ownership interests in our company at 87.04% owned by Maderic (5,222,222 ordinary shares) and 12.96% owned by HFO (777,778 ordinary shares), out of a total of 6,000,000 issued ordinary shares. The Reverse Stock Split also increased the par value of our ordinary shares from $0.001 to $0.00267 and decreased the number of authorized ordinary shares of our company from 100,000,000 to 37,500,000 and authorized preferred shares from 10,000,000 to 3,750,000.

 

As of April 23, 2024, Maderic owns 51.34% of our issued and outstanding shares, while HFO owns less than 5% of our issued and outstanding shares. As of April 23, 2024, we have 10,202,694 ordinary shares issued and outstanding.

 

 

The following diagram illustrates our corporate structure, including our consolidated holding and operating subsidiaries, as of the date of this report:

 

 

Not reflected in the above is that, for purposes of compliance with Indonesian law related to ownership of Indonesian companies: (i) WJ Energy owns 99.90% of the outstanding shares of GWN and HNE, and (ii) GWN and HNE each own 0.1% of the outstanding shares of the other; and (iii) GWN owns 99.50% of the outstanding shares of HWE, and the remaining 0.50% is owned by HNE; and (iv) HNE owns 99.90% of the outstanding shares of CNE, and the remaining 0.10% is owned by GWN.

 

Recent Developments

 

Drilling and Production at Kruh Block

We mobilized the drilling rigs to drill 2 back-to-back producing wells, namely the K-27 and K-28 well, at our Kruh Block in March 2022 and have commenced the drilling operations at the K-27 well in April 2022. The K-27 well reach a total depth of 3,359 feet on May 9, 2022. In December 2022, a hydraulic fracturing stimulation was conducted in the K-27 well. The well is currently producing 45 bopd. The fourth of the 18 wells program, K-28, was spudded on June 22, 2022 and reach the total depth of 3,359 feet on July 14, 2022. Due to the unexpected large amount of gas was encountered causing well bore instability, we side-tracked the well at 1,230 feet on September 4, 2022 and the K-28ST well reached a total depth of 3,475 feet on September 16, 2022. In addition to the proved oil-bearing Lamat B sand, several other potential oil and gas bearing reservoirs were encountered. We plan to complete the testing of K-28ST well in the first half of 2024.

 

During 2023, we were concentrated on the negotiation of the 5 year Kruh Block contract extension with the Government providing for a higher profit split. To maximize the benefit from the amended contract terms, major work programs such as seismic acquisition and drilling are rescheduled after the Amended KSO contract terms became effective. In the meantime, our operations team effectively managed the reservoir and production to minimize the decline. As a result, we produced an average of approximately 4,885 barrels per month of oil in 2023, compared with approximately 5,206 barrels per month in 2022, approximately a 6.1% annual decline.

 

L1 Capital Financing

 

On January 21, 2022 (the “Initial Closing Date”), we closed an initial $5.0 million tranche (the “First Tranche”) of a total anticipated $7.0 million private placement with L1 Capital pursuant to the terms of Securities Purchase Agreement, dated January 21, 2022, between our company and L1 Capital (the “Purchase Agreement”).

 

In connection with the closing of the First Tranche, we issued to L1 Capital (i) a 6% Original Issuance Discount Senior Convertible Note in a principal amount of up to $7,000,000 (as described further below, the “Note”) and (ii) a five year ordinary share purchase warrant (the “Initial Warrant”) to purchase up to 383,620 of our ordinary shares at an exercise price of $6.00 per share, subject to adjustment.

 

On March 4, 2022, we entered into a First Amendment with L1 Capital to the Purchase Agreement (the “SPA Amendment”) and an Amended and Restated Senior Convertible Promissory Note, which amends and restates the Original Note in its entirety (the “Replacement Note”).

 

 

On May 16, 2022, we executed and delivered to L1 Capital a Second Amended and Restated Senior Convertible Promissory Note which amends and restates the SPA Amendment in its entirety (the “Second SPA Amendment”).

 

During the year ended December 31, 2022, $9,900,000 of the total $10,000,000 principal amount of the convertible notes were converted into ordinary shares at $6.00 per share at L1 Capital’s election and 325,000 of the total 767,240 warrants were exercised. During the year ended December 31, 2023, the remaining $100,000 principal amount of the convertible notes were fully repaid and no warrants were exercised. As of the date of this report, there are still certain warrants not exercised under the L1 Capital financing.

 

Amendments to Executive Employment Agreements

 

On January 16, 2024, we entered into a First Amendment to the Said Agreement (as defined below) with Mirza F. Said (the “Said First Amendment”), our prior Chief Business Development Officer (who is also a member of the board), effective on January 16, 2024. The Said First Amendment amended and restated the Said Agreement between us and Mr. Said.

 

Pursuant to the Said First Amendment: (i) Mr. Said serve as our Chief Operating Officer (“COO”), effective from January 16, 2024; (ii) the pre-tax annual base salary for Mr. Said remains at US$204,000; and (iii) Mr. Said shall perform the duties and responsibilities (a) typically associated with the office of COO of a similarly sized U.S. listed public company in the oil and gas exploration and production sector and (b) outlined in the Said First Amendment. As a result of the Said First Amendment, Mr. Said, is our COO, and is no longer our Chief Business Development Officer, and no other individual was appointed to this position.

 

On January 16, 2024, we entered into a First Amendment to the Wu Agreement (as defined below) with Chia Hsin “Charlie” Wu (the “Wu First Amendment”), our prior COO, effective on January 16, 2024. The Wu First Amendment amended and restated the Wu Agreement between us and Dr. Wu.

 

Pursuant to the Wu First Amendment: (i) Dr. Wu serves as the our Chief Technology Officer (“CTO”), effective from January 16, 2024; (ii) the pre-tax annual base salary for Dr. Wu remains at US$204,000; (iii) Dr. Wu shall perform the duties and responsibilities (a) typically associated with the office of CTO of a similarly sized U.S. listed public company in the oil and gas exploration and production sector and (b) outlined in the Wu First Amendment. As a result of the Wu First Amendment, Dr. Wu is our CTO, and is no longer our COO.

 

Except for the foregoing, no further changes were made to either the Said First Amendment or the Wu First Amendment.

 

On December 28, 2023, we entered into a Third Amendment to the Ingriselli Agreement (as defined below) with Frank C. Ingriselli (the “Ingriselli Third Amendment”), our President, effective on January 1, 2024. The Ingriselli Third Amendment amended and restated the Ingriselli Agreement between us and Mr. Ingriselli, as amended by certain First Amendment to the Ingriselli Agreement, effective as of February 1, 2020 (the “Ingriselli First Agreement”), and certain Second Amendment to the Ingriselli Agreement, effective as of January 1, 2022 (the “Ingriselli Second Agreement”).

 

Pursuant to the Ingriselli Third Amendment: (i) the term of the Ingriselli Agreement was extended to December 31, 2025, unless terminated earlier pursuant to the terms of the Ingriselli Agreement; (ii) the pre-tax annual base salary for Mr. Ingriselli remains at US$150,000; and (iii) Mr. Ingriselli was granted an award of 60,000 ordinary shares, with 30,000 ordinary shares vesting on July 1, 2024 and 30,000 ordinary shares vesting on January 1, 2025, under a lock-up period of 180 days from each vesting date.

 

On January 1, 2024, we entered into a Third Amendment to the Overholtzer Agreement (as defined below) with Gregory L. Overholtzer (the “Overholtzer Third Amendment”), our Chief Financial Officer, effective on January 1, 2024. The Overholtzer Third Amendment amended and restated the Overholtzer Agreement between us and Mr. Overholtzer, as amended by certain First Amendment to the Overholtzer Agreement, effective as of February 1, 2020 (the “Overholtzer First Agreement”), and certain Second Amendment to the Overholtzer Agreement, effective as of January 1, 2022 (the “Overholtzer Second Agreement”).

 

Pursuant to the Overholtzer Third Amendment: (i) the term of the Overholtzer Agreement was extended to December 31, 2025, unless terminated earlier pursuant to the terms of the Overholtzer Agreement; and (ii) the pre-tax annual base salary for Mr. Overholtzer remains at US$80,000.

 

Except for the foregoing, no further changes were made to either the Ingriselli Agreement or the Overholtzer Agreement.

 

 

Departure of Director and Appointment of Director

 

On January 15, 2024, Tamba P. Hutapea, our independent director, resigned from the board, the chairman and a member of the Nominating and Corporate Governance Committee and a member of the Compensation Committee of the Company, effective on January 15, 2024. Mr. Hutapea’s resignation was not due to any disputes or disagreements with us or our Board.

 

On January 16, 2024, our board appointed Ahmad Fathurachman as an independent director, the chairman and a member of the Nominating and Corporate Governance Committee and a member of the Compensation Committee of the Company, effective on January 16, 2024. Mr. Fathurachman currently serves as our independent director for a term expiring at our next annual meeting or until his successor is duly elected.

 

First Amendment to the ATM Agreement

 

On July 22, 2022, we entered into an At The Market Offering Agreement (the “ATM Agreement”) with the Sales Agent, pursuant to which we may offer and sell, from time to time, to or through the Sales Agent, ordinary shares (the “ATM Shares”) having an aggregate gross offering price of up to $20,000,000. Under the ATM Agreement, the ATM Shares, if offered and sold by us, will be offered and sold pursuant to a prospectus dated February 16, 2021 and a prospectus supplement, dated July 22, 2022, that form a part of our shelf registration statement on Form F-3 (File No. 333-252520), which registration statement was declared effective by the SEC on February 16, 2021 (“Prior Registration Statement”). On August 25, 2022, we sold 177,763 ATM Shares at $10.7407 per share for net proceeds (after Sales Agent commissions) of $1,801,193. On August 25, 2022, we sold an additional 280,612 ATM Shares at $10.1090 per share for net proceeds (after Sales Agent commissions) of $2,750,449. As of December 31, 2023, there are no ATM Shares sold under the ATM Agreement.

 

On March 22, 2024, we filed a New F-3 Registration Statement, which includes a Prospectus Supplement and a base prospectus supplemented by the Prospectus Supplement, covering (i) the offering, issuance and sale by us of up to a maximum aggregate offering price of $50,000,000 of our ordinary shares, preferred shares, warrants, debt securities, rights, depositary shares, and/or units from time to time in one or more offerings, and (ii) up to a maximum aggregate offering price of $4,267,622 of our ordinary shares that may be issued and sold from time to time under the ATM Agreement, as amended by the ATM Amendment No.1 on March 22, 2024, with the Sales Agent. We are not permitted to sell any ATM Shares prior to the effectiveness of the New F-3 Registration Statement. As of the date of this report, the New F-3 Registration Statement has not been declared effective.

 

Corporate Information

 

Our principal executive offices are located at GIESMART PLAZA 7th Floor, Jl. Raya Pasar Minggu No. 17A, Pancoran – Jakarta 12780 Indonesia. Our telephone number at this address is +62 21 2696 2888. Our registered office in the Cayman Islands is located at Ogier Global (Cayman) Limited, 89 Nexus Way, Camana Bay, Grand Cayman, Cayman Islands. Our web site is located at www.indo-energy.com. The information contained on our website is not incorporated by reference into this report, and the reference to our website in this report is an inactive textual reference only.

 

 

ITEM 4A. UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

 

The following discussion of the results of our operations and our financial condition should be read in conjunction with the consolidated financial statements and the related notes to those statements included in this annual report. This discussion contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those set forth in “Item 3. Key Information–D. Risk Factors”.

 

As described elsewhere in this annual report, all share amounts and per share amounts set forth below have been presented on a retroactive basis to reflect a reverse stock split by way of share consolidation of our outstanding ordinary shares at a ratio of one-for-zero point three seven five (1 for 0.375) shares which was implemented on November 8, 2019.

 

Business Overview

 

We are an oil and gas exploration and production company focused on the Indonesian market. Alongside operational excellence, we believe we have set the highest standards for ethics, safety and corporate social responsibility practices to ensure that we add value to society. Led by a professional management team with extensive oil and gas experience, we seek to bring forth at all times the best of our expertise to ensure the sustainable development of a profitable and integrated energy exploration and production business model.

 

We currently have rights through contracts with the Government to one oil and gas producing block (Kruh Block) and one oil and gas exploration block (Citarum Block). We may seek to acquire or otherwise obtain rights to additional oil and gas producing assets.

 

We produce oil through GWN, our indirect wholly-owned subsidiary which operates the Kruh Block under an agreement with Pertamina, the Indonesian state-owned oil and gas company (“Pertamina”). Our operatorship Kruh Block previously ran until May 2030 under a ten-year Operations Cooperation Agreement, known as Joint Operation Partnership (the “KSO”), between GWN and Pertamina. Kruh Block covers an area of 258 km2 (63,753 acres) and is located onshore 16 miles northwest of Pendopo, Pali, South Sumatra. In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed the Amended KSO that moved the expiration date of our operatorship of Kruh Block to September 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%.

 

Our reserves estimate of 3 fields (Kruh, North Kruh and West Kruh) within the Kruh KSO block was based on two major sources: (i) an integrated study of geology, geophysics and reservoir including reserve evaluation of Kruh, North Kruh and West Kruh fields by LEMIGAS (a Government oil and gas research and development center responsible for exploration and production technology development and assessment of oil and gas fields) in 2005, and (ii) additional reservoir and production data since 2005, particularly from the addition of 8 new wells since 2013.

 

The content and reserves in the LEMIGAS report (2005) was approved by Pertamina. The methods used in updating the proved, probable and possible reserves of LEMIGAS report with additional reservoir and production data was based on guidelines from the SPE-PRMS (Society of Petroleum Engineers-Petroleum Resources Management System) and SEC guidelines.

 

Our proved oil reserves have not been estimated or reviewed by independent petroleum engineers. The estimate of the proved reserves for the Kruh Block was prepared by representatives of our company, a team consisting of engineering, geological and geophysical staff based on the definitions and disclosure guidelines of the SEC contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.

 

 

Our estimates of the proven reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers, and Pertamina, and revised as warranted by additional data. Revisions are due to changes in, among other things, development plans, reservoir performance, TAC effective period and governmental restrictions.

 

Kruh Block’s general manager, Mr. Denny Radjawane, and our Chief Technology Officer, Mr. Charlie Wu, have reviewed the reserves estimate to ensure compliance to SEC guidelines for (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities. The estimate of reserves was also reviewed by our Chief Business Development Officer and our Chief Executive Officer.

 

The table below shows the individual qualifications of our internal team that prepares the reserves estimation:

 

						Total
Reserve		University				professional				Field of professional experience (years)
Estimation Team*		degree major		Degree level		experience (years)				Drilling & Production				Petroleum Engineering				Production Geology				Reserve Estimation
Charlie Wu		Geosciences		Ph.D.			46				12								34				23
Frans Watimena		Petroleum Engineering		M.S.			35				20				15								6
Denny Radjawane		Geophysics		M.S.			33				12								21				15
Fransiska Sitinjak		Petroleum Engineering		M.S.			20				6				14								9
Yudhi Setiawan		Geology		B.S.			21				15				2				4				2
Oni Syahrial		Geology		B.S.			17				2								15				9
Juan Chandra		Geology		B.S.			18				2								16				10

 

The individuals from the reserves estimation team are members of at least one of the following professional associations: American Association of Petroleum Geologists (AAPG), Indonesian Association of Geophysicist (HAGI), Indonesian Association of Geologists (IAGI), Society of Petroleum Engineers (SPE), Society of Indonesian Petroleum Engineers (IATMI) and Indonesian Petroleum Association (IPA).

 

Citarum Block is an exploration block covering an area of 3,924.67 km2 (969,807 acres). This block is located onshore in West Java and only 16 miles south of the capital city of Indonesia, Jakarta.

 

Our Citarum PSC contract, valid until July 2048, is based on the “gross split” regime, in which the production of oil and gas is to be divided between the contractor and the Indonesian Government based on certain percentages in respect of (a) the crude oil production and (b) the natural gas production. Our share will be the Base Split share plus a Variable and Progressive component. Our Crude Oil Base Split share is 43% and our Natural Gas Base Split share is 48%. Our share percentage is determined based on both variable (such as carbon dioxide and hydrogen sulfide content) and progressive (such as crude oil and refined gas prices) components.

 

Thus, pursuant to our Citarum PSC contract, once Citarum commences production, we are entitled to at least 65% of the natural gas produced, calculated as 48% from the Base Split plus a Variable Component of 5% from the first Plan of Development (POD I) in Citarum, a Variable Component of 2% from the use of Local Content, as the oil and gas onshore services are mostly closed or restricted for foreign companies (as described in “Legal Framework for the Oil and Gas Industry in Indonesia” elsewhere in this annual report), and a 10% increase for the first 180 BSCF produced or 30 million barrels of oil equivalent which according to our economic model, the cumulative production of 180 BSCF will only be achieved in 2025, if our exploration efforts succeed.

 

In mid-2018, we identified an onshore open area in the province of West Java, adjacent to our Citarum Block. We believe that this area, also known as the Rangkas Area, holds large amounts of crude oil due to its proven petroleum system. To confirm the potential of Rangkas Area, in July 2018, we formally expressed our interest to the DGOG of MEMR to conduct a Joint Study in the Rangkas Area and we attained the approval to initiate our Joint Study program in this area on November 5, 2018. The Rangkas Joint Study covered an area of 3,970 km2 (or 981,008 acres) and was completed in November 2019. The DGOG accepted the completion of the joint study and inquired IEC’s interest for further process to tender the block. The study result suggested an effective petroleum system for oil and gas accumulations. Furthermore with the opportunity to integrate the operation of Citarum and Rangkas together efficiently, we decided to issue a Statement of Interest Letter in December 2019 to the Ministry of Energy (DGOG) as we intend to enter into a PSC contract for the Rangkas through a direct tender process. We will have the right to change our offer in order to match the best offer following the results of the bidding process which has not taken place as of the date of this report. The timeline for the tender is contingent upon the DGOG’s plans and schedule.

 

 

We currently generate revenue from Kruh Block and profit sharing from the sale of the crude oil under our new 10-year Joint Operation Partnership (or KSO) that commenced in May 2020 by Pertamina. Prior to May 2020, Kruh Block was operated under a TAC agreement. Under our KSO, we have the operatorship to, but not the ownership of, the extraction and production of oil from the designated oil deposit location in Indonesia until May 2030. In December 2022, we started our negotiations with Pertamina for a five-year extension of our contract for Kruh Block. Effective on August 9, 2023, GWN and Pertamina executed the Amended KSO that moved the expiration date of our operatorship of Kruh Block to September 2035. This extension effectively gives us 13 years to fully develop the existing 3 oil fields, and 5 other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%.

 

During the operations, our company pays all expenditures and obligations incurred including but not limited to exploration, development, extraction, production, transportation, abandonment and site restoration. Under the TAC, revenue was recognized based on the prevailing ICP through GWN from the 65% of monthly proceeds as monthly cost recovery entitlement plus 26.7857% of the remaining proceeds from the sale of the crude oil after monthly cost recovery entitlement as part of the profit sharing. For the original KSO, with an 80% cap on the proceeds of such sale as part of the cost recovery scheme, on a monthly basis, calculated by multiplying the quantity of crude oil produced by our company and the prevailing ICP published by the Government of Indonesia plus 80% of the operating cost per bbl multiplying Non-Shareable Oil (“NSO”). In addition, we were also entitled to an additional 23.5294% of the remaining 20% of such sales proceeds as part of the profit sharing. The main differences between the two contracts (KSO and TAC) are that: (1) in the TAC, all oil produced is shareable between Pertamina and its contractor, while in the KSO, a NSO production is determined and agreed between Pertamina and its partners so that the baseline production, with an established decline rate, belongs entirely to Pertamina, so that the partners’ revenue and production sharing portion shall be determined only from the production above the NSO baseline; (2) in the TAC, the cost recovery was capped at 65% of the proceeds from the sale of the oil produced in the block, while in the KSO, the cost recovery is capped at 80% of the proceeds from the sale of the oil produced within Kruh Block for the cost incurred during the term under the KSO plus 80% of the operating cost per bbl multiplying NSO. Any remaining cost recovery balance from the KSO period of contract is carried over to the next period, although the cost recovery balance from the TAC contract will not be carried over to the KSO, meaning that the cost recovery balance was reset to nil with the commencement of the operatorship under the KSO in May 2020.

 

In the Amended KSO contract, Pertamina receives 5% gross production as the first tranche production (ftp). GWN is entitled to use 100% of the rest for cost recovery. For the DMO responsibility, GWN receives 100% of ICP in the amended KSO compared to 25% of ICP in the original KSO contract. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%.

 

Our revenue and potential for profit depend mostly on the level of oil production in Kruh Block and the ICP that is correlated to international crude oil prices. Therefore, the biggest factor affecting our financial results in 2023 and 2022 was the volatility in the price of crude oil. For the year ended December 31, 2023, ICP decreased to an average of $77.61 per Bbl., 19.94% lower when compared to the ICP average of $96.94 per Bbl. for the year ended December 31, 2022, which eroded the financial performance of our company in 2023.

 

Since the commencement of operations in 2014 (then via our now subsidiary WJ Energy), the natural resources industry has gone through a dramatic change. The downturn in the price of crude oil during this period has impacted our results of operations, cash flows, capital and exploratory investment program and production outlook. A sustained lower price environment could result in the impairment or write-down of specific assets in future periods. During 2016, oil price crisis hit its bottom with an ICP of only $25.83 per Bbl. in the month of January. As a result of this low price, our operations went through a cost analysis procedure in order to determine the economic limit of each of our producing wells at Kruh by identifying their respective direct production cost. Accordingly, we closed a total of 6 wells that were producing less than 10 BOPD each that year. We commenced new drilling operations in Kruh Block in March 2021. Our originally anticipated drilling commencement date was delayed due to COVID-19 and the government permitting process. The first new well was spudded in April 2021 and the drilling of the second well was commenced in August 2021. The reserve estimate was updated at the end of 2021. We mobilized the drilling rigs to drill 2 back-to-back producing wells, namely the K-27 and K-28 well, at our Kruh Block in March 2022 and have commenced the drilling operations at the K-27 well in April 2022 and reached a total depth of 3,359 feet on May 9, 2022. In December 2022, a hydraulic fracturing stimulation was performed in K-27 well. The well is currently producing 38 bopd. The fourth of the 18 wells program, K-28, was spudded on June 22, 2022 and reached a total depth of 3,359 feet on July 14, 2022. Due to the unexpected large amount of gas was encountered causing well bore instability, we side-tracked the well at 1,230 feet on September 4 and the K-28ST well reached a total depth of 3,475 feet on September 16, 2022. In addition to the proved oil-bearing Lamat B sand, several other potential oil and gas bearing reservoirs were encountered. We plan to complete the testing of K-28ST well in the first half of 2024.

 

 

Key Components of Results of Operations

 

For the years ended December 31, 2023 and 2022

 

Financial and operating results for the year ended December 31, 2023 compared to the year ended December 31, 2022 are as follows:

 

	●	Total oil production decreased approximately 6.16%, from 62,467 Bbl. for the year ended December 31, 2022 to 58,616 Bbl. for the same period in 2023. The decline of production in 2023 was due to the natural reservoir energy decline and no new production from drilling contributed to the production decrease in 2023. The lower oil price in 2023 resulted in lower revenue and cost recovery entitlements for the year ended December 31, 2023 than for the same period in 2022. However, effective production and reservoir management minimized the decline rate in 2023. The Proved, Developed and Producing reserves (PDP) decreased from 371,076 bbls in 2022 to 335,191 bbls in 2023 due to production.
	●	ICP decreased 19.94% from an average price of $96.94 per Bbl. for the year ended December 31, 2022 to $77.61 per Bbl. for the same period in 2023. The ICP, which correlates to the international crude oil price, is determined by MEMR. Throughout 2023, increases in U.S. petroleum production put downward pressure on crude oil prices. In addition, the production increases likely limited the effect on prices from the attack on key energy installations in Saudi Arabia on September 16, 2019, production cut announcements from the Organization of the Petroleum Exporting Countries (OPEC), and U.S. sanctions on Iran and Venezuela that limited crude oil exports from those countries. This production increase accompanied by weaker demand growth, have led to a large build up in stocks caused the decrease of crude oil price. In the first half of 2022, geopolitical tension with Russia, culminating with Russia’s full-scale invasion of Ukraine in February 2022, to some extent, contributed to crude oil price increases. In second half of 2022, crude oil prices generally decreased as concerns about a possible economic recession to some extent reduced demand. Since the decline of oil price at over $100 in July 2022, Brent oil price remains relatively stable around $80 except a spike of $93.72 in September 2023 when Saudi Arabia and Russia decided to extend the output cut of 1.3 mb/d. The average ICP in 2022 was $96.94 while the average ICP in 2023 was $77.61. Although the regional conflicts of the ongoing Russia-Ukraine war and Israel-Hamas war could lead to oil price shock above $100, we expect the oil price would most likely stay around $80 per barrel in 2024 and 2025 because of the relatively balanced supply and demand.
	●	Revenue decreased by $571,949, or 13.96%, from $4,097,403 for the year ended December 31, 2022 to $3,525,454 for the same period in 2023 due to a combination of a significantly lower average ICP and slightly lower production.

 

●

General and administrative expenses decreased by $1,234,627, or 26.82%, for the year ended December 31, 2023 as compared to the same period in 2022, mainly due to a decrease in share-based compensation which was fully amortized in 2022, and a decrease in professional service fees resulted from lower volume of financing activities.

 

	●	The amount of lease operating expenses slightly decreased by $2,385, or 0.08%, for the year ended December 31, 2023 as compared to the same period in 2022 mainly because of stable productivity activities as no new well developed in 2023.
	●	We incurred a net loss of $2,642,684 for the year ended December 31, 2023 as compared to a net loss of $3,063,349 for the same period in 2022, with the reduction in net loss being due to a combination of the factors described above.
	●	The average production cost per barrel of oil for the year ended December 31, 2023 was $50.34 compared to $47.2 for the year ended December 31, 2022, computed using production costs disclosed pursuant to FASB ASC Topic 932 and only to exclude ad valorem and severance taxes, an increase of 6.20% due to a combination of the factors discussed above.

 

 

For the years ended December 31, 2022 and 2021

 

Financial and operating results for the year ended December 31, 2022 compared to the year ended December 31, 2021 are as follows:

 

	●	Total oil production increased approximately 3.02%, from 60,637 Bbl. for the year ended December 31, 2021 to 62,467 Bbl. for the same period in 2022. Despite the natural decline of production due to reservoir energy decline, the production from new wells contributed to the production increase in 2022. The higher oil price in 2022, however, resulted in higher revenue and cost recovery entitlements for the year ended December 31, 2022 than for the same period in 2021. The production increase from the three new wells K-25, K-26 and K-27 was offset by the natural decline of the four existing wells. The Proved, Developed and Producing reserves (PDP) had increased from 311,211 bbls in 2021 to 371,076 bbls in 2022.
	●	ICP increased 44.64% from an average price of $67.02 per Bbl. for the year ended December 31, 2021 to $96.94 per Bbl. for the same period in 2022. The ICP, which correlates to the international crude oil price, is determined by MEMR. Throughout 2020, increases in U.S. petroleum production put downward pressure on crude oil prices. In addition, the production increases likely limited the effect on prices from the attack on key energy installations in Saudi Arabia on September 16, 2019, production cut announcements from the Organization of the Petroleum Exporting Countries (OPEC), and U.S. sanctions on Iran and Venezuela that limited crude oil exports from those countries. This production increase accompanied by weaker demand growth, have led to a large build up in stocks caused the decrease of crude oil price. In the first half of 2022, geopolitical tension with Russia, culminating with Russia’s full-scale invasion of Ukraine in February 2022, to some extent, contributed to crude oil price increases. In the second half of 2022, crude oil prices generally decreased as concerns about a possible economic recession to some extent reduced demand.
	●	Revenue increased by $1,644,863, or 67.07%, from $2,452,540 for the year ended December 31, 2021 to $4,097,403 for the same period in 2022 due to a combination of a significantly higher average ICP and slightly higher production.

 

●

General and administrative expenses decreased by $647,962, or 12.34%, for the year ended December 31, 2022 as compared to the same period in 2021, mainly due to a decrease of share-based compensation and travel expenses, which was offset by increases in professional service fees.

 

	●	The amount of lease operating expenses increased by $460,778, or 18.49%, for the year ended December 31, 2022 as compared to the same period in 2021 mainly because of additional equipment rental added, well stimulation and fracturing activity for existing wells and a lease for a water treatment/environmental system as well as pumping units and gensets (power generators) for three wells (namely, K-25, K-26 and K-27).
	●	We incurred a net loss of $3,122,592 for the year ended December 31, 2022 as compared to a net loss of $6,083,379 for the same period in 2021, with the reduction in net loss being due to a combination of the factors described above.
	●	The average production cost per barrel of oil for the year ended December 31, 2022 was $47.28 compared to $41.10 for the year ended December 31, 2021, computed using production costs disclosed pursuant to FASB ASC Topic 932 and only to exclude ad valorem and severance taxes, an increase of 15.02% due to a combination of the factors discussed above.

 

Trends Affecting Future Operations

 

The factors that will most significantly affect results of operations will be (i) the selling prices of crude oil and natural gas, and (ii) the amount of production from oil or gas wells in which we have an interest. Our revenues will also be significantly impacted by its ability to maintain or increase oil or gas production through exploration and development activities.

 

 

It is expected that the principal source of cash flow will be from the production and sale of crude oil and natural gas capitalized property which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance operations to a greater extent with internally generated funds and may allow us to obtain equity financing more easily or on better terms, and lessen the difficulty of obtaining financing. However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.

 

Since the decline of oil price at over $100 in July 2022, Brent oil price remains relatively stable around $80 except a spike of $93.72 in September 2023 when Saudi Arabia and Russia decided to extend the output cut of 1.3 mb/d. The average ICP in 2022 was $96.94 while the average ICP in 2023 was $77.61. Although the regional conflicts of the ongoing Russia-Ukraine war and Israel-Hamas war could lead to oil price shock above $100, we expect the oil price would most likely stay around $80 per barrel in 2024 and 2025 because of the relatively balanced supply and demand. ICP of the first three months in 2024 is $77.02, $80.16 and $82.78, respectively.

 

We commenced new drilling operations in Kruh Block in March 2021. Our originally anticipated drilling commencement date was delayed due to COVID-19 and the government permitting process. The first new well was spudded in April 2021 and the second well commenced in August 2021. The reserve estimate was updated at the end of 2021. The third and fourth well K-27 and K-28 were drilled in 2022. The K-27 was producing a maximum of 59 barrels of oil per day in June 2023 while the K-28 well is still waiting for testing and completion in the first half of 2024. To further understand the oil and gas potential in the Kruh Block, we will complete a seismic data acquisition, processing and interpretation program in 2024. After the Kruh Block seismic acquisition, processing and interpretation program is completed in 2024, we expect to resume drilling in 2024 with the goal of finishing 14 additional wells and significantly increasing our production. The result of the high quality 3D seismic data will also provide strong support of additional PUD locations which will result in additional proved reserves.

 

The Russian-Ukraine conflict which began in February 2022 and the most recent Israel-Hamas conflict have caused an oil supply concern, which has led to a sharp increase in global oil prices. This trend has led to a higher Indonesian Crude Price (ICP), from $94.92 per Bbl in February and $114.02 per Bbl in March 2022 from the average ICP price of $67.02 per Bbl for the year 2021, and an average ICP price of $96.94. A sustained increase in ICP creates the potential for higher revenue for our company without a resulting increase in expenses. In 2023, the range of ICP prices was between US$68.06 and US$89.69 per barrel with an average of US$77.61 per barrel. It is our expectation that for 2024, the oil price will be around US$80 per barrel. This will help us establish a stable cash flows for our company, enhance our liquidity and may provide us with enhanced access to capital resources.

 

Other than the foregoing, the management is unaware of any other trends, events or uncertainties that will have, or are reasonably expected to have, a material impact on sales, revenues or expenses.

 

Results of Operations

 

The table below sets forth certain line items from our Consolidated Statement of Operations for the years ended December 31, 2023, 2022 and 2021:

 

		For The Years Ended
		December 31,				December 31,				December 31,
		2023				2022				2021
Revenue		$	3,525,454			$	4,097,403			$	2,452,540
Lease operating expenses			2,950,869				2,953,254				2,492,476
Depreciation, depletion and amortization			702,217				1,139,723				810,855
General and administrative expenses			3,368,029				4,602,656				5,250,618
Total other income, net			852,977				1,475,638				(10,459	)
Loss before income tax			(2,642,684	)			(3,122,592	)			(6,083,379	)
Income tax provision			-				-				-
Net loss		$	(2,642,684	)		$	(3,122,592	)		$	(6,083,379	)
Actuarial gain for post-employment benefits			8,543				59,243				30,704
Total comprehensive loss		$	(2,634,141	)		$	(3,063,349	)		$	(6,052,675	)

 

 

Year ended December 31, 2023 compared with year ended December 31, 2022 

 

Revenue

 

Total revenue for the year ended December 31, 2023, were $3,525,454 compared to $4,097,403 for the year ended December 31, 2022, an decreased of $571,949 or 13.96% due to a combination of a significantly lower average ICP and slightly lower production.

 

Lease operating expenses

 

Lease operating expenses decreased by $2,385, or 0.08%, for the year ended December 31, 2023, compared to the same period in 2022 mainly because of stable productivity activities as no new well developed in 2023.

 

Depreciation, depletion and amortization (DD&A)

 

The amount of DD&A decreased by $437,506, or 38.39% for the year ended December 31, 2023 compared to the same period in 2022 mainly due to decrease in depletion per unit as there was an increase in total estimated proved reserves and slight decrease in production.

 

General and Administrative Expenses

 

General and administrative expenses decreased by $1,234,627 or 26.82%, for the year ended December 31, 2023 as compared to the same period in 2022 due to a decrease in share-based compensation which was fully amortized in 2022, and a decrease in professional service fees resulted from lower volume of financing activities.

 

Total other income, net

 

There was other income, net of $852,977 for the year ended December 31, 2023 as compared to other income, net of $1,475,638 in the same period in 2022. The decreased was mainly due to a $1,971,235 decrease in fair value change of warrant liability as a result of a decline of year-end share price compared to 2022, the decrease of amortization of debt discount for convertible note and an exchange gain as a result of the fluctuation in exchange rate.

 

Net Loss

 

We had net loss for the year ended December 31, 2023, in the amount of $2,642,684 as compared to $3,122,592 for the same period in 2022, with the reduction in loss being due to the combination of the factors discussed above.

 

Year ended December 31, 2022 compared with year ended December 31, 2021

 

Revenue

 

Total revenue for the year ended December 31, 2022, were $4,097,403 compared to $2,452,540 for the year ended December 31, 2021, an increase of $1,644,863 or 67.07% due to a combination of a significantly higher average ICP and slightly higher production.

 

Lease operating expenses

 

Lease operating expenses increased by $460,778, or 18.49%, for the year ended December 31, 2022, compared to the same period in 2021 mainly because of additional equipment rental added, well stimulation and fracturing activity for existing wells and a lease for a water treatment/environmental system as well as pumping units and gensets (power generators) for three wells (namely, K-25, K-26 and K-27).

 

 

Depreciation, depletion and amortization (DD&A)

 

The amount of DD&A increased by $328,868, or 40.56% for the year ended December 31, 2022 compared to the same period in 2021 due to retirement of certain drilling and production tools for the TAC Period and an increase in depletion number, which was the result of $4,912,336 addition of the depletion base due to the development of the two new drilled wells (K-27 and K-28) and an increase in depletion per unit due to a decrease in total estimated proved reserves.

 

General and Administrative Expenses

 

General and administrative expenses decreased by $647,962 or 12.34%, for the year ended December 31, 2022 as compared to the same period in 2021 due to a decrease of share-based compensation and travel expenses, which was offset by increases in professional service fees.

 

Total other income, net

 

There was other income, net of $1,475,638 for the year ended December 31, 2022 as compared to other income, net of $18,030 in the same period in 2021. The increase was mainly due to a $2,878,660 decrease of fair value of warrant liability as a result of a decline of year-end share price compared to May 2022, which was offset by an issuance cost allocated to warrants issued in a financing, an increase in other expense and an exchange loss as a result of the fluctuation in exchange rate.

 

Net Loss

 

We had net loss for the year ended December 31, 2022, in the amount of $3,122,592 as compared to $6,083,379 for the same period in 2021, with the reduction in loss being due to the combination of the factors discussed above.

 

Critical Accounting Policies and Estimates

 

Our accounting policies affecting our financial condition and results of operations are more fully described in our consolidated financial statements for the years ended December 31, 2023, 2022 and 2021, included elsewhere in this annual report. The preparation of these consolidated financial statements requires us to make judgments in selecting appropriate assumptions for calculating accounting estimates, which inherently contain some degree of uncertainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis of making judgments about the carrying values of assets and liabilities and the reported amounts of revenues and expenses that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. Out of our significant accounting policies, which are described in Note 2 — Summary of Significant Accounting Policies of our consolidated financial statements included elsewhere in this annual report, certain accounting policies and practices are deemed as “critical accounting policy,” as they require management’s highest degree of judgment, estimates and assumptions, including (i) impairment of long-lived assets; (ii) oil and gas property, net, full cost method, and (iii) warrant liabilities. We believe that the following estimates involve the most significant judgments used in the preparation of our financial statements are deemed as “critical accounting estimate”:

 

Impairment of long-lived assets

 

We review our long-lived assets or asset group for impairment whenever events or changes in circumstances, such as a significant adverse change to market conditions that will impact the future use of the assets, indicate that the carrying value of an asset may no longer be recoverable. When these events occur, we assess the recoverability of the long-lived assets or asset group by comparing the carrying value of the long-lived assets or asset group to the estimated undiscounted future cash flows expected to result from the use of the assets and their eventual disposition when the estimated undiscounted future cash flows is lower than the carrying value, an impairment loss is recognized in the consolidated statements of operations and comprehensive loss for the difference between the fair value, using the expected future discounted cash flows, and the carrying value of the assets. We primarily consider whether the following factors exist when evaluating impairment:

 

	●	significant underperformance relative to projected operating results;
	●	significant changes in the overall business strategy;
	●	significant adverse changes in legal or business environment: and
	●	significant competition, unfavorable industry trends, or economic outlook.

 

There was no impairment for long-lived assets for the years ended December 31, 2023, 2022 and 2021, respectively.

 

 

Oil and gas property, net, Full cost method

 

We follow the full-cost method of accounting for the oil and gas property. Under the full-cost method, all productive and non-productive costs incurred in the acquisition, exploration and development associated with properties with proven reserves under KSO Kruh Block, are capitalized. As of December 31, 2023 and 2022, all capitalized costs associated with Kruh’s reserves were subject to amortization. Capitalized costs are subject to a quarterly ceiling test that limits such costs to the aggregate of the present value of estimated future net cash flows of proved reserves, computed using the unweighted arithmetic average of the first-day-of the-month oil and gas prices for each month within the 12-month period prior to the end of reporting period, updated drilling schedule and estimated production and development costs, discounted at 10%, and the lower of cost or fair value of proved properties. If unamortized costs capitalized exceed the ceiling, the excess is charged to expense in the period the excess occurs. There were no cost ceiling write-downs for the years ended December 31, 2023, 2022 and 2021, respectively.

 

Depletion for each of the reported periods is computed on the units-of-production method. Depletion base is the total capitalized oil and gas property in the previous period, plus the period capitalization and future development costs. Furthermore, the depletion rate is calculated as the depletion base divided by the total estimated proved reserves that expected to be extracted during the operatorship. Then, depletion is calculated as the production of the period times the depletion rate.

 

For the years ended December 31, 2023, 2022 and 2021, the estimated proved reserves were considered based on the operatorship of the Kruh Block under the TAC through May 2020 and then the KSO and Amended KSO from June 2020 and expiring in September 2035.

 

The costs associated with properties with unproved reserves or under development, such as PSC Citarum Block, are not initially included in the full-cost depletion base. The costs include but are not limited to unproved property acquisition costs, seismic data and geological and geophysical studies associated with the property. These costs are transferred to the depletion base once the reserve has been determined as proven.

 

We primarily consider whether the following factors exist when evaluating future net cash flows and future development costs:

 

	●	significant underperformance relative to projected operating results;
	●	significant changes in the overall business strategy;
	●	significant changes in legal, business or environmental factors; and
	●	significant competition, industry trends, or economic outlook.

 

Fair Value of Warrant Liabilities

 

The Company accounts for the warrants issued in connection with its 2022 convertible note financing in accordance with the guidance contained in Accounting Standards Codification (“ASC”) 815-40 Derivatives and Hedging - Contracts in Entity’s Own Equity (“ASC 815”) under which the warrants do not meet the criteria for equity treatment and must be recorded as liabilities. Accordingly, the Company classifies such warrants as liabilities at their fair value and adjusts the warrants to fair value at each reporting period. This liability is subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the condensed consolidated statements of operations. Such warrants are valued using the Black-Scholes option-pricing model as no observable traded price was available for such warrants. Determining the appropriate valuation model and estimating the fair values of warrant liabilities requires the input of subjective assumptions, including risk-free interest rate, expected stock price volatility, dividend yields and expected term. The assumptions used in calculating the fair values of warrant liabilities represent management’s best estimates, but these estimates involve inherent uncertainties and the application of judgment. As a result, if factors change and different assumptions are used, warrant liabilities could be significantly different from what we recorded in the current period.

 

Going Concern Forecast

 

The Company assessed its ability to continue as a going concern, evaluating whether there are conditions and events, considered in the aggregate, that raise substantial doubt about its ability to continue as a going concern using all information available about the future, focusing on the twelve-month period following the issuance date of the consolidated financial statements. For the cashflow projection, we assume production from existing wells with natural decline, average ICP of last 12 months in the most recent fiscal year as expected ICP, stable operational cost and limited capital expenditure as new drilling will not begin until 2026.

 

The Company’s going concern status is subject to various risks and uncertainties mainly includes limited unrestricted cash balance as of the date of this report, volatility on profit forecast affected by fluctuations in oil price, planned level of operational and capital expenditures and ability to obtain the necessary additional capital on a timely basis, on acceptable terms, or at all, from any source.

 

 

Recent Accounting Pronouncements

 

A list of recently adopted accounting pronouncements that are relevant to us is included in Note 2 - Summary of Significant Accounting Policies of our consolidated financial statements included elsewhere in this annual report.

 

Liquidity and Capital Resources

 

We generated a net loss of $2,634,141 and net cash used in operating activities of $2,978,919 for the year end December 31, 2023. As of December 31, 2023, we had an accumulated deficit of $39,583,437 and working capital of $5,016,233. Our operating results for future periods are subject to numerous risks and uncertainties and it is uncertain if we will be able to reduce or eliminate our net losses and achieve cash flow positive operations in the near term or eventually achieve profitability. If we are not able to increase revenues or manage operating expenses in line with revenue forecasts, or if the price of oil should drop significantly, we may not be able to achieve profitability.

 

We have financed the operations primarily through cash flow from operations, loans from banks, and proceeds from equity instrument financing, where necessary. As of December 31, 2023, the Company had total cash of $3,997,187. On March 22, 2024, we filed a New F-3 Registration Statement, which includes a Prospectus Supplement and a base prospectus supplemented by the Prospectus Supplement, covering (i) the offering, issuance and sale by us of up to a maximum aggregate offering price of $50,000,000 of our ordinary shares, preferred shares, warrants, debt securities, rights, depositary shares, and/or units from time to time in one or more offerings, and (ii) up to a maximum aggregate offering price of $4,267,622 of our ordinary shares that may be issued and sold from time to time under the ATM Agreement, as amended by the ATM Amendment No.1 on March 22, 2024, with H.C. Wainwright & Co., LLC as Sales Agent. We are not permitted to sell any ATM Shares prior to the effectiveness of the New F-3 Registration Statement. As of the date of this report, the New F-3 Registration Statement has not been declared effective yet.

 

As of April 23, 2024, we had approximately $0.75 million of cash, which is placed with financial institutions and is unrestricted as to withdrawal or use. We intend to meet the cash requirements for the next 12 months from the issuance date of the Company’s audited consolidated financial statements through a combination of improving operational efficiency, equity or debt financing and financial support from principal shareholder. We will collect the account receivables and other receivables more closely and review the payment schedule in a planned manner, especially for general and administrative expenses, seismic and G&G study. We will not plan any new drilling activity for the next 12 months, unless further proceeds from above ATM offering or exercise of outstanding warrants are received. We expect that we will be able to obtain new bank loans based on past experience and the Company’s good credit history. In addition, Mr. Wirawan Jusuf, the Chief Executive Officer and Chairman of the Board of the Company, has agreed to provide $4 million of financial support in the form of debt to the Company to enable the Company to meet its obligations and commitments as they become due for at least next 12 months. We believe that our cash on hand and internally generated cash flows will be sufficient to fund its operations over at least the next 12 months from the date of this filing.

 

Based on our current liquidity and anticipated funding requirements, if we determine that our cash requirements exceed the amount of cash we have on hand at the time, we may seek to issue equity or debt securities or obtain credit facilities. The issuance and sale of additional equity would result in further dilution to our shareholders. The incurrence of indebtedness would result in increased fixed obligations and could result in operating covenants that might restrict our operations. We cannot assure you that financing will be available from any source in amounts or on terms acceptable to us, if at all or, therefore, that we will be able to alleviate our anticipated funding requirements.

 

Cash flows

 

The following table sets forth certain historical information with respect to our statements of cash flows for the years ended December 31, 2023, 2022 and 2021:

 

		For The Years Ended
		December 31,				December 31,				December 31,
		2023				2022				2021
Net cash used in operating activities		$	(2,978,919	)		$	(3,208,138	)		$	(3,548,656	)
Net cash used in investing activities			(419,459	)			(5,416,501	)			(2,759,829	)
Net cash provided by (used in) financing activities			-				12,925,190				-
Effect of exchange rate changes on cash and restricted cash			-				-				-
Net change in cash, and restricted cash		$	(3,398,378	)		$	4,300,551			$	(6,308,485	)
Cash and restricted cash at beginning of year			7,395,565				3,095,014				9,403,499
Cash and restricted cash at end of year		$	3,997,187			$	7,395,565			$	3,095,014

 

 

Year ended December 31, 2023 compared with year ended December 31, 2022 

 

Operating activities

 

Operating activities used $2.99 million in cash for the year ended December 31, 2023, as compared to $3.21 million for 2022. The decrease of approximately $0.22 million in the amount of net cash used in operating activities is primarily due to decrease in operating expenses.

 

Investing activities

 

Net cash used in investing activities for the year ended December 31, 2023 was approximately $0.42 million, as compared to approximately $5.42 million for the year ended December 31, 2022. The decreased is mainly due to decrease in cash paid for fracturing job stimulation expenditure and drilling expenditures as no new well developed in 2023.

 

Financing activities

 

Net cash received from financing activities for the year ended December 31, 2023 was $nil, as compared to $12.93 million for the year ended December 31, 2022. There was no cash received in financing activities for the year ended December 31, 2023.

 

Year ended December 31, 2022 compared with year ended December 31, 2021

 

Operating activities

 

Operating activities used $3.21 million in cash for the year ended December 31, 2022, as compared to $3.55 million for 2021. The decrease of approximately $0.34 million in the amount of net cash used in operating activities is primarily due to $1.04 million increase in cash received from our customer (Pertamina) which was offset by approximately $0.55 million increase of cash paid for prepaid tax that will be reimbursed by Pertamina.

 

Investing activities

 

Net cash used in investing activities for the year ended December 31, 2022 was approximately $5.42 million, as compared to approximately $2.76 million for the year ended December 31, 2021. The increase of approximately $2.60 million in the amount of net cash used in investing activities was primarily a result of an increase of cash paid for one fracturing job/stimulation expenditure and drilling expenditures for two wells in 2022.

 

Financing activities

 

Net cash received from financing activities for the year ended December 31, 2022 was approximately $12.93 million, as compared to $nil for the year ended December 31, 2021. Cash received in financing activities for the year ended December 31, 2022 amounted to $15.09 million, which primarily consisted of the proceeds from issuance of convertible note & warrants amounted to $8.59 million, exercise of warrants amounted to $1.95 million and issuance of ordinary shares by ATM offering amounted to $4.55 million. Cash used in financing activities for the year ended December 31, 2022 amounted to $1.98 million and primarily consisted of repayment of bank loan amounted to $0.98 million and repayment of long term loan to a third party amounted to $1 million.

 

 

Capital Expenditures

 

We made capital expenditures of $419,459 and $5,416,501 for the years ended December 31, 2023 and 2022, respectively, which were primarily related to the development and exploration of the oil and gas property and purchases of property and equipment.

 

Transfers of Funds Through Our Corporate Organization

 

With respect to how cash funds are transferred from our company to WJ Energy and subsequently to our operating subsidiaries in Indonesia, such transfers are undertaken in the form of shareholder loans to fund capital, operational and general and administrative expenditures of our operating subsidiaries. For the years ended December 31, 2022 and 2021: (i) the total amount of cash transferred from us to WJ Energy was $8,675,000 and $2,922,205, respectively and (ii) the total amount of cash transferred from WJ Energy to our operating subsidiaries was $7,785,506 and $2,899,444, respectively. All the above-mentioned transactions have been made through bank accounts owned by each respective company in Indonesia. Our parent company, WJ Energy and our operating subsidiaries each hold bank accounts in Indonesia to minimize international or cross-border cash transfers.

 

No dividends or distributions have been made to date from our operating subsidiaries to WJ Energy, nor from WJ Energy to our company. While as of the date of this annual report, the likelihood of our paying dividends to our shareholders (including our public shareholders) is remote, we are not aware of any Hong Kong or other restriction on foreign exchange nor any restriction that impairs (i) our ability to distribute earnings to our shareholders, (ii) WJ Energy’s ability to make distributions to our parent company or (iii) our operating subsidiaries ability to make distributions to WJ Energy.

 

Research and development

 

Development costs that are expected to generate probable future economic benefits can be capitalized as intangible assets. All other research and development expenditure is recognized in income as incurred. For the years ended December 31, 2023 and 2022, the Company conducts no Research and Development activities, nor is it dependent upon any patents or licenses.

 

Trend Information

 

Other than as disclosed elsewhere in this annual report, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 2023 that are reasonably likely to have a material and adverse effect on our total revenues, income, profitability, liquidity or capital resources, or that would cause the disclosed financial information to be not necessarily indicative of future results of operations or financial conditions.

 

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

 

Directors and Executive Officers

 

The following table sets forth information regarding our executive officers and directors as of the date of this annual report.

 

Name		Age		Position/Title
Dr. Wirawan Jusuf		38		Director, Chairman of the Board and Chief Executive Officer
Frank C. Ingriselli		69		President
Chia Hsin “Charlie” Wu		71		Chief Technology Officer, prior Chief Operating Officer
Mirza F. Said		58		Chief Operating Officer and Director, prior Chief Business Development Officer
James J. Huang		37		Chief Investment Officer and Director
Gregory L. Overholtzer		66		Chief Financial Officer
Mochtar Hussein		66		Independent Director
Benny Dharmawan		41		Independent Director
Ahmad Fathurachman		32		Independent Director
Michael L. Peterson		62		Independent Director

 

Dr. Wirawan Jusuf is a co-founder, Chief Executive Officer and Chairman of the board of directors of our company, and has served as the Chief Executive Officer of WJ Energy since 2014. Since 2015, Dr. Jusuf has also served as a co-founder and Commissioner of Pt. Asiabeef Biofarm Indonesia, a fully integrated and sustainable cattle business company in Indonesia. Dr. Jusuf also serves as the Director of Maderic Holding Limited, a private investment firm and our majority shareholder, which he founded in 2014. Dr. Jusuf began his professional career when he co-founded and served as the Director of Pt. Wican Indonesia Energi, an oil and gas services company, from 2012 to 2014. Dr. Jusuf earned his Master’s in Public Health at the Gajah Mada University-Jogjakarta in Central Java, Indonesia, and his medical degree at the University of Tarumanegara in Jakarta, Indonesia beforehand. We believe Dr. Jusuf is qualified to serve in his positions with our company due to his strong qualifications in business development, government relations and strategic planning.

 

 

Frank C. Ingriselli has served as our President since February 2019. With over 45 years of experience in the energy industry, Mr. Ingriselli is a seasoned leader and entrepreneur with wide-ranging exploration and production experience in diverse geographies, business climates and political environments. From 2005 to 2018, Mr. Ingriselli was the founder, President, CEO and Chairman of PEDEVCO Corp. and Pacific Asia Petroleum, Inc., both energy companies which are or were listed on NYSE American. Prior to founding these two companies, from 1979 to 2001, Mr. Ingriselli worked at Texaco in diverse senior executive positions involving exploration and production, power and gas operations, merger and acquisition activities, pipeline operations and corporate development. The positions Mr. Ingriselli held at Texaco included President of Texaco Technology Ventures, President and CEO of the Timan Pechora Company (owned by affiliates of Texaco, Exxon, Amoco, Norsk Hydro and Lukoil), and President of Texaco International Operations, where he directed Texaco’s global initiatives in exploration and development. While at Texaco, Mr. Ingriselli, among other activities, led Texaco’s initiatives in exploration and development in China, Russia, Australia, India, Venezuela and many other countries. Mr. Ingriselli served as an independent member of the Board of Directors of NXT Energy Solutions Inc. (TSX:SFD; OTC QB:NSFDF) from 2019 to 2022 and is also on the Board of Trustees of the Eurasia Foundation, and is the founder and Chairman of Brightening Lives Foundation, Inc., a charitable public foundation. From 2016 through 2018, Mr. Ingriselli founded and was the President and CEO of Blackhawk Energy Ventures Inc. which endeavored to acquire oil and gas assets in the United States for development purposes. Mr. Ingriselli also served as the chief executive officer of Trio Petroleum Corp. (NYSE American: TPET) (“Trio Petroleum”), a company developing assets in California, from February 2022 to October 2023, and has been serving as vice chairman and director of Trio Petroleum since February 2022, and serves on the Board of Directors of Lafayette Energy (a private company developing assets in Louisiana). Mr. Ingriselli graduated from Boston University in 1975 with a B.S. in business administration. He also earned an M.B.A. from New York University in both finance and international finance in 1977 and a J.D. from Fordham University School of Law in 1979.

 

Dr. Chia Hsin (Charlie) Wu has served as our Chief Technology Officer since January 2024 and previously served as our Chief Operating Officer since 2018. Dr. Wu is a highly qualified and recognized oil and gas industry veteran with over 40 years of experience. Dr. Wu has been responsible for building and leading the upstream exploration and production teams for 3 independent oil and gas companies in Indonesia over the last 15 years. Prior to joining our company, since 2017 Dr. Wu has been acting as the Chief Technology Officer for Pt. Pandawa Prima Lestari, an oil and gas company operating a PSC block in Kalimantan, as well as an independent oil and gas consultant. Dr. Wu previously served as the Director of Operations and Chief Operating Officer of Pt. Sugih Energy TBK, an oil and gas exploration and production company with 4 PSC blocks in Central and South Sumatera from 2013 to 2016. From 2010 to 2013, Dr. Wu was the President Director of Pacific Oil & Gas Indonesia, an oil and gas company operating 2 PSC blocks in North Sumatra and one KSO block in Aceh. Prior to 2010, Dr. Wu had transitioned into the senior role of Vice-President and General Manager with Petroselat Ltd., operator of an exploration and production PSC block in Central Sumatra between 2000 and 2010, and simultaneously served as Chief Operating Officer at International Mineral Resources Inc from 2003 to 2010. From 1999 to 2000, Dr. Wu served as an Exploration Consultant with EMP Kondur Petroleum, an oil company which operated a production PSC in Central Sumatra. From 1981 to 1999, Dr. Wu worked in a variety of roles internationally with Atlantic Richfield Company (ARCO, now recognized as BP Plc). Dr. Wu worked in the position of Geological Specialist from 1996 to 1999 in Jakarta, Indonesia. From 1990 to 1995, Dr. Wu worked as a New Venture Geologist with the ARCO organization in Plano, Texas, and from 1985 to 1990, Dr. Wu worked as an Exploration Coordinator of the for ARCO in Jakarta, Indonesia. Dr. Wu began his work with ARCO from 1983 to 1985 as an explorationist in Plano, Texas, during which time he earned ARCO’s “Exploration Excellence Award” on the Vice-President Level for providing training to worldwide staff in geohistory and basin modelling with subsequent exploration successes. From 1979 to 1981, Dr. Wu worked as a Petrophysical Supervisor with Core Laboratories Inc. Dr. Wu began his career as a Research Specialist with the US Department of Energy at the University of Oklahoma in 1979. Dr. Wu completed his Postgraduate Diploma in Business Administration at DeMontfort University in 2000 and earned his Ph.D. in Geosciences in 1991 at the University of Texas. He also completed his Masters of Science in Geology at the University of Toledo in 1979. Prior to his graduate studies, Dr. Wu earned his Bachelors of Science degree in Geology at National Taiwan University in 1975. Dr. Wu was once an Adjunct Associate Professor at the University of Texas at Dallas between 1995 and 2000 and has served as a lecturer at the University of Indonesia since 2006. Dr. Wu has also been a member of American Association of Petroleum Geologists (AAPG) since 1979.

 

 

Mirza F. Said has served as Chief Operating Officer since January 2024 and a Director of our company since 2018, Chief Executive Officer of our subsidiary Pt. Green World Nusantara since 2014, PT Harvel Nusantara Energi since 2015, and PT Hutama Wiranusa Energi since 2018. Mr. Said was also our Chief Business Development Officer between February 2019 and January 2024. From 2012 to 2014, Mr. Said had served as President Director of Pt. Humpuss Patragas, and Commissioner of Pt. Humpuss Trading and Pt. Humpuss Wajo Energi simultaneously. All of these companies are the subsidiaries of PT. Humpuss, an Indonesian holding company focusing on energy business, including in upstream, transportation and refining activities. From 2010 to 2012, Mr. Said acted as the Senior Business Development & External Relations Manager for Pacific Oil & Gas. From 2007 to 2010, Mr. Said Co-Founded Pt. Corpora Hydrocarbon Asian, a private oil and gas investment company, and served as that organization’s Operational Specialist. Prior to serving as Chief Operating Officer of Pt. Indelberg Indonesia from 2006 to 2007, Mr. Said served as the Corporate Operations Controller for Akar Golindo Group from 2004 to 2006. From 2001 to 2004, Mr. Said was the Project Cost Controller & Analyst for the Kangean Asset for BP Indonesia, during which time, as a result of his achievements he was awarded the “Spot Recognition Award of Significant Contribution in Managing & Placing”. From 1997 to 1999, he served as Operations Manager for JOB Pertamina Western Madura Pty Ltd., a joint operation company between Citiview Corporation Ltd (an Australian based oil and gas company) and Pertamina (the Indonesian state owned oil and gas company) that operated a block in Madura, East Java. Mr. Said began his professional career as Senior Drilling Engineer with Pt. Humpuss Patragas, an Indonesian private oil and gas company a subsidiary of PT. Humpuss, which operated Cepu Block, East Java from 1991 to 1997 (he would later return to that organization in 2012 and serve in two senior executive positions concurrently). Mr. Said earned his Master of Engineering Management at the Curtin University of Technology in Perth, Australia, and had completed his Bachelor’s degree in Chemical Engineering at the Institute Technology of Indonesia. Mr. Said holds professional memberships with the Indonesian Petroleum Association (IPA) and Society of Indonesian Petroleum Engineers (IATMI) and is fluent in English and Indonesian. We believe Mr. Said is qualified to serve in his positions with our company as a result of his education and professional experiences, including achievements and expertise within the energy and infrastructure sector.

 

James J. Huang is co-founder and has served as Chief Investment Officer and Director of our company since inception, and has served as the Chief Investment Officer of WJ Energy since 2014. Mr. Huang co-founded and has served as Director of Asiabeef Group Limited, a fully integrated and sustainable cattle business company and holding company of Pt. Asiabeef Biofarm Indonesia, since 2015. Mr. Huang founded and is a Director at Pt. HFI International Consulting, an Indonesian based business consulting company, since 2014. Mr. Huang was previously the Director of Pt. Biofarm Plantation, a cattle trading company, from 2013 until 2015. From 2010 to 2013, Mr. Huang founded and served as a Director at HFI Ind. Imp. e Exp. Ltd., an information technology company providing integrated security and surveillance solutions in Brazil. Mr. Huang began his professional career in 2008 as an intern practicing corporate law and tax consulting with Barbosa, Müssnich & Aragão in São Paulo, Brazil. Mr. Huang holds the Chartered Financial Analyst^® (CFA) designation and maintains an Attorney at Law professional license from the Brazilian Bar Association (OAB/SP). Mr. Huang earned his Bachelor’s degree in law at the Escola de Direito de São Paulo in Brazil at Fundação Getúlio Vargas and previously participated at a Double Degree Business Management Program at the Escola de Administração de Empresas de São Paulo also at Fundação Getúlio Vargas. We believe Mr. Huang is qualified to serve in his positions with our company due to his expertise in finance, legal matters, business management and strategic planning.

 

Gregory L. Overholtzer has served as our Chief Financial Officer since February 2019. Mr. Overholtzer is a seasoned financial officer for public companies, including in the energy space. Mr. Overholtzer has worked as a part-time Chief Financial Officer for Trio Corporation since February 2022. In addition, since November 2019, Mr. Overholtzer has served as a Consulting Director of Ravix Consulting Group. From December 2018 until November 2019, Mr. Overholtzer served as a Field Consultant at Resources Global Professionals. Mr. Overholtzer had served as the Chief Financial Officer of PEDEVCO Corp. from January 2012 to December 2018. From 2011 to 2012, Mr. Overholtzer served as Senior Director and Field Consultant for Accretive Solutions, where he had consulted for various companies at the chief financial officer and controller levels. Mr. Overholtzer acted as the Chief Financial Officer of Omni-ID USA Inc. from 2008 to 2011. Mr. Overholtzer was the Corporate Controller of Genitope Corporation from 2006 to 2008, and Stratex Inc. from 2005 to 2006. Mr. Overholtzer served as the Chief Financial Officer and Vice President of Finance for Polymer Technology Group from 1998 to 2005. From 1997 to 1998, he was the Chief Financial Officer and Vice President of Finance at TeleSensory Corporation. Mr. Overholtzer held roles of Chief Financial Officer, Vice President of Finance and Corporate Secretary with Giga-tronics Inc. from 1994 to 1997. Mr. Overholtzer also held several positions with Airco Coating Tech., a division of BOC Group London from 1982 to 1994, which included Senior Financial Analyst, General Accounting Manager, Vice President of Finance and Administration. In the early years of his career, Mr. Overholtzer also was as an MBA course Instructor in Managerial Accounting at Golden Gate University from 1984 to 1987 and 1989 to 1991. Mr. Overholtzer had received his MBA at the University of California, Berkeley, concentrating in Finance and Accounting and graduating with Beta Sigma Honors. Prior to his graduate studies, Mr. Overholtzer earned his B.A. in Zoology at the University of California, Berkeley, graduating with University Honors.

 

 

Mochtar Hussein has served as a Director of our company since October 2018. From 2013 to 2018, Mr. Hussein acted as Inspector General of Inspectorate General of the MEMR. From 2014 to 2018, Mr. Hussein also served as Commissioner of Pt. Timah (Persero) Tbk, an Indonesian state-owned enterprise engaged in tin mining and listed on Indonesia Stock Exchange. In 2012, Mr. Hussein served as Director of Indonesian Government Institution Supervision of Public Welfare and Defence & Security, and from 2009 to 2012, he served as the Head of the Representative Office of the Indonesian State Finance & Development Surveillance Committee (known as BPKP) in Central Java Province. From 2005 to 2009, he served as Director of Fiscal and Investment Supervision in the BPKP, and during 2004, he served as the Head of the Representative Office of BPKP in Lampung Province. From 2000 to 2004, Mr. Hussein served as Head of Indonesian State & Regionally Owned Enterprises Supervision in Jakarta. From 1997 to 2000, Mr. Hussein concurrently served as Head of Indonesian State & Regionally Owned Enterprises Supervision in East Nusa Tenggara Province and the Section Head of Fuel & Non-Fuel Distribution Supervision. Mr. Hussein began his professional career in 1993 as Section Head of Services, Trading & Financial Institution Supervision in Bengkulu Province and served in a range of senior positions with the BPKP until 2012. Mr. Hussein holds a Forensic Auditor Certification. He earned his Bachelor’s degree in Economics at the Brawijaya University, Malang in East Java. We believe Mr. Hussein is qualified to serve as a Director of our company due to his expertise in investigative auditing, compliance and corporate governance.

 

Benny Dharmawan has served as a Director of our company since October 2018. Since 2006, following his previous international experiences throughout Australia, United Kingdom and the United States, Mr. Dharmawan has served as the Chief Compliance Officer for GIGA Carbon Neutrality Inc., a Canadian incorporated private company headquartered in London and offices in New York and Beijing, primarily engaged in the manufacturing and sales of zero emission commercial vehicle and equipment which integrates hydrogen fuel cells with electric battery. Mr. Dharmawan has also served as Director of Pt. Panasia Indo Resources Tbk., a holding company that primarily engages in yarn manufacturing and synthetic fibers through its subsidiaries, and in the mining sector. Since 2015, Mr. Dharmawan has served as a Controller at Pt. Sinar Tambang Arthalestari, a fully integrated cement producer in Central Java, Indonesia. From 2007 to 2015, Mr. Dharmawan served in several executive positions, first as equity capital markets, regional operations, and compliance, and later being promoted to Associate Vice President, at the Macquarie Group, a global provider of banking, advisory, trading, asset management and retail financial services, in New York, London and Sydney. Mr. Dharmawan earned his Bachelor’s degree in Commerce at the Macquarie University in Australia and received his Master’s degree in Applied Finance and Investments in Kaplan, Australia. We believe Mr. Dharmawan is qualified to serve as a Director of our company due to his previous international professional accomplishments, particularly his expertise in risk management, compliance, financial markets, business management and strategic and tactical planning.

 

Ahmad Fathurachman has served as a Director of our company since January 2024. Mr. Fathurachman is an oil and gas professional with a multifaceted skillset in electrical & instrumentation (“E&I”) engineering. Since August 2022, Mr. Fathurachman has served as a consultant in Indonesia to Weatherford International (“Weatherford”), a global oil field services company. Prior to this role, he held several positions at Weatherford, first as a project manager for production business unit between March 2018 and June 2020, and later as a senior project manager for project development & product sales between June 2020 and August 2022. Between October 2022 and June 2023, he served as a Business Development Specialist at Deleum Oilfield Services, an oilfield services company engaged in oil & gas chemical business in Southeast Asia. Between October 2016 and February 2018, he served as an E&I system engineer at PT. Wifgasindo Dinamika Instrument Engineering, an Indonesia engineering, procurement, construction, and installation company, and between January 2016 and September 2016, he worked as an E&I system engineer at PT. Mangunkerta Nusantara, an E&I system integrator company in Indonesia. From January 2014 to December 2015, he served as an E&I services engineer at Matrik Engineering (j.v PT. Kota Minyak Internusa), an E&I manufacturing company in Indonesia. Mr. Fathurachman received his bachelor’s degree in electrical engineering from Universitas Jenderal Achmad Yani in Indonesia in 2013. We believe Mr. Fathurachman is qualified to serve as a Director of our company due to his expertise in implementation and optimization of heavy oil production, especially deep understanding of oilfield digital solution and project executions in Indonesia.

 

 

Michael L. Peterson has served as a Director of our Company since January 2021. In April 2022, Mr. Peterson founded and currently serves as a Director and the Chief Executive Officer of Lafayette Energy Corp., a private company developing assets in Louisiana. Since October 2023, Mr. Peterson has served as the chief executive officer of Trio Petroleum, and since June 2021, he has served as a Director of Aesther Healthcare Acquisition Corp., a Nasdaq listed special purpose acquisition company (“SPAC”), which merged with Ocean Biomedical Inc. (NASDAQ: OCEA) in February 2023, and Mr. Peterson currently serves as a Director of Ocean Biomedical Inc. Since March 2023, Mr. Peterson has served as a Director of OceanTech Acquisitions I Corp (NASDAQ: OTEC), a Nasdaq listed SPAC. Since December 2020, Mr. Peterson has served as the Chief Executive Officer of Nevo Motors, Inc. (Formerly Nevo Energy, Inc.), a company that is commercializing low carbon emission trucks. Between June 2018 and June 2021, Mr. Peterson served as the President of the Taipei Taiwan Mission of The Church of Jesus Christ of Latter-day Saints, in Taipei, Taiwan. From August 2016 to May 2021, Mr. Peterson served as an Independent Director of Trxade Health, Inc. (NASDAQ: MEDS), a Nasdaq listed company primarily engaged in pharmaceutical B2B technology. From 2011 to 2018, Mr. Peterson served in several executive officer positions and a Director at PEDEVCO Corp. (NYSE American: PED), a public company primarily engaged in the acquisition, exploration, development and production of oil and natural gas shale plays in the United States. These executive officer positions included Chief Executive Officer, President, Chief Financial Officer and Executive Vice President. Mr. Peterson previously served as Interim President and Chief Executive Officer (from June 2009 to December 2011), and as a Director (from May 2008 to December 2011), of Blast Energy (Pacific Energy Development’s predecessor), a company primarily engaged in oil and gas development, as a Director (from May 2006 to July 2012) of Aemetis, Inc. (formerly AE Biofuels Inc.), a Cupertino, California-based global advanced biofuels and renewable commodity chemicals company (AMTX.OB), and as Chairman and Chief Executive Officer of Nevo Energy, Inc. (“NEVE”, formerly Solargen Energy, Inc.), a Cupertino, California-based developer of utility-scale solar farms from December 2008 to July 2012. From 2005 to 2006, Mr. Peterson served as a Managing Partner of American Institutional Partners, a venture investment fund based in Salt Lake City. From 2000 to 2004, he served as a First Vice President at Merrill Lynch, where he helped establish a new private client services division to work exclusively with high-net-worth investors. From September 1989 to January 2000, Mr. Peterson was employed by Goldman Sachs & Co. in a variety of positions and roles, including as a Vice President with the responsibility for a team of professionals that advised and managed over $7 billion in assets. Mr. Peterson received his Master’s degree of Business Administration at the Marriott School of Management and a Bachelor’s degree in statistics/computer science from Brigham Young University. Mr. Peterson is qualified to be a Director of our company due to his experience in managing, operating and growing both public and private companies, especially those active in the energy industry.

 

Family Relationships and Conflicts of Interests

 

There are no family relationships between any of our officers and directors. We are not aware of any conflicts of interests related to our officers and directors arising from the management and operations of our business.

 

Board of Directors and Committees

 

General

 

Our board of directors consists of seven (7) directors. A majority of our board of directors (namely, Mochtar Hussein, Benny Dharmawan, Ahmad Fathurachman and Michael L. Peterson) are independent, as such term is defined by the NYSE American. The members of our board of directors are elected annually at our annual general meeting of shareholders.

 

We do not have a lead independent director, and we do not anticipate having a lead independent director. Our board of directors as a whole play a key role in our risk oversight. Our board of directors makes all decisions relevant to our company. We believe it is appropriate to have the involvement and input of all of our directors in risk oversight matters.

 

 

Board Committees

 

Our board of directors have three standing committees: the audit committee, the compensation committee and the nominating and corporate governance committee. Each committee has three members, and each member is independent, as such term is defined by the NYSE American.

 

The audit committee is responsible for overseeing the accounting and financial reporting processes of our company and audits of the financial statements of our company, including the appointment, compensation and oversight of the work of our independent auditors.

 

The compensation committee reviews and makes recommendations to the board regarding our compensation policies for our officers and all forms of compensation, and also administers and has authority to make grants under our incentive compensation plans and equity-based plans.

 

The nominating and corporate governance committee is responsible for the assessment of the performance of our board of directors, considering and making recommendations to our board of directors with respect to the nominations or elections of directors and other governance issues. The nominating and corporate governance committee will consider diversity of opinion and experience when nominating directors.

 

The members of the audit committee, the compensation committee and the nominating and corporate governance committee are set forth below. All such members will qualify as independent under the rules of NYSE American.

 

Director		Audit Committee				Compensation Committee				Nominating and Corporate Governance Committee
Michael L. Peterson (3)			(2	)			—				—
Ahmad Fathurachman			—				(1	)			(2	)
Benny Dharmawan			(1	)			(2	)			(1	)
Mochtar Hussein			(1	)			(1	)			—

 

(1)	Committee member
(2)	Committee chair
(3)	Audit committee financial expert

 

Duties of Directors

 

As a matter of Cayman Islands law, a director owes three types of duties to the company: (a) statutory duties, (b) fiduciary duties, and (iii) common law duties. The Companies Act imposes a number of statutory duties on a director. A Cayman Islands director’s fiduciary duties are not codified, however the courts of the Cayman Islands have held that a director owes the following fiduciary duties (a) a duty to act in what the director bona fide considers to be in the best interests of the company, (b) a duty to exercise their powers for the purposes they were conferred, (c) a duty to avoid fettering his or her discretion in the future and (d) a duty to avoid conflicts of interest and of duty. The common law duties owed by a director are those to act with skill, care and diligence that may reasonably be expected of a person carrying out the same functions as are carried out by that director in relation to the company and, also, to act with the skill, care and diligence in keeping with a standard of care commensurate with any particular skill they have which enables them to meet a higher standard than a director without those skills. In fulfilling their duty of care to us, our directors must ensure compliance with our amended articles of association, as amended and restated from time to time (our “Articles of Association”). We have the right to seek damages if a duty owed by any of our directors is breached. Our board of directors.

 

Interested Transactions

 

A director may vote, attend a board meeting or, presuming that the director is an officer and that it has been approved, sign a document on our behalf with respect to any contract or transaction in which he or she is interested. We require directors to promptly disclose the interest to all other directors after becoming aware of the fact that he or she is interested in a transaction we have entered into or are to enter into. A general notice or disclosure to the board or otherwise contained in the minutes of a meeting or a written resolution of the board or any committee of the board that a director is a shareholder, director, officer or trustee of any specified firm or company and is to be regarded as interested in any transaction with such firm or company will be sufficient disclosure, and, after such general notice, it will not be necessary to give special notice relating to any particular transaction.

 

 

Remuneration and Borrowing

 

Our directors may receive such remuneration as our board of directors may determine or change from time to time. The compensation committee will assist the directors in reviewing and approving the compensation structure for the directors.

 

Our board of directors may exercise all the powers of the company to borrow money and to mortgage or charge our undertakings and property and assets both present and future and uncalled capital or any part thereof, to issue debentures and other securities whether outright or as collateral security for any debt, liability or obligation of our company or its parent undertaking (if any) or any subsidiary undertaking of our company or of any third party.

 

Qualification

 

A majority of our board of directors is required to be independent. There are no membership qualifications for directors. The shareholding qualification for directors may be fixed by our shareholders by ordinary resolution and unless and until so fixed no share qualification shall be required.

 

Limitation of Director and Officer Liability

 

Under Cayman Islands law, each of our directors and officers, in performing his or her functions, is required to act honestly and in good faith with a view to our best interests and exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Cayman Islands law does not limit the extent to which a company’s Articles of Association may provide for indemnification of officers and directors and secretaries, except to the extent any such provision may be held by the Cayman Islands courts to be contrary to public policy, such as to provide indemnification against civil fraud or the consequences of committing a crime.

 

The Articles of Association provide, to the extent permitted by law, for the indemnification of each existing or former director (including alternate director), secretary and any of our other officers (including an investment adviser or an administrator or liquidator) and their personal representatives against:

 

	(a)	all actions, proceedings, costs, charges, expenses, losses, damages or liabilities incurred or sustained by the existing or former director (including alternate director), secretary or officer in or about the conduct of our business or affairs or in the execution or discharge of the existing or former director’s (including alternate director’s), secretary’s or officer’s duties, powers, authorities or discretions; and
	(b)	without limitation to paragraph (a) above, all costs, expenses, losses or liabilities incurred by the existing or former director (including alternate director), secretary or officer in defending (whether successfully or otherwise) any civil, criminal, administrative or investigative proceedings (whether threatened, pending or completed) concerning us or our affairs in any court or tribunal, whether in the Cayman Islands or elsewhere. To be entitled to indemnification, these persons must have acted honestly and in good faith with a view to the best interest of the company and, in the case of criminal proceedings, they must have had no reasonable cause to believe their conduct was unlawful. Such limitation of liability does not affect the availability of equitable remedies such as injunctive relief or rescission. These provisions will not limit the liability of directors under United States federal securities laws.

 

The decision of our board of directors as to whether the director acted honestly and in good faith with a view to our best interests and as to whether the director had no reasonable cause to believe that his or her conduct was unlawful, is in the absence of fraud sufficient for the purposes of indemnification, unless a question of law is involved. The termination of any proceedings by any judgment, order, settlement, conviction or the entry of no plea does not, by itself, create a presumption that a director did not act honestly and in good faith and with a view to our best interests or that the director had reasonable cause to believe that his or her conduct was unlawful. If a director to be indemnified has been successful in defense of any proceedings referred to above, the director is entitled to be indemnified against all expenses, including legal fees, and against all judgments, fines and amounts paid in settlement and reasonably incurred by the director or officer in connection with the proceedings.

 

 

We have purchased and currently maintain insurance in relation to any of our directors or officers against any liability asserted against the directors or officers and incurred by the directors or officers in that capacity, whether or not we have or would have had the power to indemnify the directors or officers against the liability as provided in our Articles of Association. Insofar as indemnification for liabilities arising under the Securities Act may be permitted for our directors, officers or persons controlling our company under the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

 

Involvement in Certain Legal Proceedings

 

To our knowledge, none of our directors or officers has been convicted in a criminal proceeding, excluding traffic violations or similar misdemeanors, nor has been a party to any judicial or administrative proceeding during the past five years that resulted in a judgment, decree or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws, except for matters that were dismissed without sanction or settlement. Except as set forth in our discussion below in “Related Party Transactions,” our directors and officers have not been involved in any transactions with us or any of our affiliates or associates which are required to be disclosed pursuant to the rules and regulations of the SEC.

 

Code of Business Conduct and Ethics

 

The board adopted a code of ethics and business conduct applicable to our directors, officers and employees on June 21, 2019.

 

Executive Compensation

 

Summary Compensation Table

 

Our compensation committee, consisting of independent board members determined the compensation to be paid to our executive officers based on our financial and operating performance and prospects, and contributions made by the officers’ to our success. Our compensation committee measures each of our officers by a series of performance criteria by our board of directors, or the compensation committee on a yearly basis. Such criteria is based on certain objective parameters such as job characteristics, required professionalism, management skills, interpersonal skills, related experience, personal performance and overall corporate performance.

 

Our board of directors has not adopted or established a formal policy or procedure for determining the amount of compensation paid to our executive officers. Our board of directors will make an independent evaluation of appropriate compensation to key employees, with input from management. Our board of directors has oversight of executive compensation plans, policies and programs.

 

 

Summary Compensation Table

 

The following table presents summary information regarding the total compensation awarded to, earned by, or paid to each of the named executive officers for services rendered to us for the years ended December 31, 2023 and 2022.

 

Name and principal position		Fiscal Year				Salary ($)				Bonus ($)				Stock awards ($)				Option awards ($)(1)				Non-equity incentive plan compensation ($)				Nonqualified deferred compensation earnings ($)				All other compensation ($)(2)				Total ($)
Dr. Wirawan Jusuf			2023				297,000				-				-				-				-				-				-				297,000
Chief Executive Officer			2022				297,000				-				-				-				-				-				-				297,000
Frank C. Ingriselli			2023				150,000				-				-				-				-				-				-				150,000
President			2022				150,000				-				-				-				-				-				-				150,000
Gregory L. Overholtzer			2023				80,000				-				-				-				-				-				-				80,000
Chief Financial Officer			2022				80,000				-				-				-				-				-				-				80,000
Mirza F. Said			2023				204,000				-				-				-				-				-				-				204,000
Chief Operating Officer			2022				204,000								-				-				-				-				-				204,000
Chia Hsin “Charlie” Wu			2023				204,000				-				-				-				-				-				-				204,000
Chief Technology Officer			2022				204,000				-				-				-				-				-				-				204,000
James J. Huang			2023				240,000				-				-				-				-				-				-				240,000
Chief Investment Officer			2022				240,000				-				-				-				-				-				-				240,000

 

(1) The options and bonus were granted pursuant to agreements between the executives and our company. The values of the option awards represent grant-date fair values without regard to forfeitures.

 

(2) All other compensation refers to income tax withholding under Indonesian law. Salaries in Indonesia are negotiated on a “take home pay” basis. Therefore, we pay the income withholding tax on behalf of the employee, which is legally considered part of the employee’s compensation.

 

 

Outstanding Equity Awards at 2023 Year-End 

 

The following table provides information regarding each unexercised stock option held by the named executive officers as of December 31, 2023.

 

Name		Grant date				Vesting Start date				Number of securities underlying unexercised options vested (#)				Number of securities underlying unexercised options unvested (#)				Options exercise price ($)				Option Expiration date
Dr. Wirawan Jusuf Chief Executive Officer			December 19, 2019				December 23, 2022				50,000				-			$	11.00				December 19, 2024
Frank C. Ingriselli President			-				-				-				-				-				-
Gregory L. Overholtzer Chief Financial Officer			-				-				-				-				-				-
Chia Hsin “Charlie” Wu Chief Technology Officer			December 19, 2019				December 23, 2022				50,000				-			$	11.00				December 19, 2029
James J. Huang Chief Investment Officer			December 19, 2019				December 23, 2022				50,000				-			$	11.00				December 19, 2029
Mirza F. Said Chief Operating Officer			December 19, 2019				December 23, 2022				50,000				-			$	11.00				December 19, 2029

 

2018 Omnibus Equity Incentive Plan

 

On October 31, 2018, our board of directors and shareholders adopted a 2018 Omnibus Equity Incentive Plan for our company (which we refer to as the 2018 Plan).

 

Purpose

 

The purpose of our 2018 Plan is to attract and retain directors, officers, consultants, advisors and employees whose services are considered valuable, to encourage a sense of proprietorship and to stimulate an active interest of such persons in our development and financial achievements.

 

Administration

 

The compensation committee of our board of directors (or the Compensation Committee) will have primary responsibility for administering the 2018 Plan. The Compensation Committee will have the authority to, among other things, the (a) determine terms and conditions of any option or stock purchase right granted, including the exercise price and the vesting schedule, (b) determine the persons who are to receive options and stock purchase rights and (c) determine the number of shares to be subject to each option and stock purchase right, (d) prescribe any limitations, restrictions and conditions upon any awards, including the vesting conditions of awards, (e) determine if a grant will be an “incentive” options (qualified under section 422 of the Internal Revenue Code of 1986, as amended, which is referred to herein as the Code) to employees of our company or a non-qualified options to directors and consultants of our company, and (f) make any other determination and take any other action that the Compensation Committee deems necessary or desirable for the administration of the 2018 Plan. The Compensation Committee will have full discretion to administer and interpret the 2018 Plan and to adopt such rules, regulations and procedures as it deems necessary or advisable and to determine, among other things, the time or times at which the awards may be exercised and whether and under what circumstances an award may be exercised.

 

Eligibility

 

Our employees, directors, officers and consultants (and those of any affiliated companies of ours) are eligible to participate in the 2018 Plan. The Compensation Committee has the authority to determine who will be granted an award under the 2018 Plan, however, it may delegate such authority to one or more of our officers under the circumstances set forth in the 2018 Plan; provided, however, that all awards made to non-employee Directors shall be determined by our board of directors in its sole discretion.

 

 

Number of Shares Authorized

 

Approximately 1,104,546 ordinary shares are reserved for issuance under our 2018 Plan.

 

If an award is forfeited, canceled, or if any option terminates, expires or lapses without being exercised, the ordinary shares subject to such award will again be made available for future grant. However, shares that are used to pay the exercise price of an option or that are withheld to satisfy the Participant’s tax withholding obligation will not be available for re-grant under the 2018 Plan.

 

Awards Available for Grant

 

The Compensation Committee may grant awards of non-qualified share options, incentive share options, share appreciation rights, restricted share awards, restricted share units, share bonus awards, performance compensation awards (including cash bonus awards) or any combination of the foregoing, as each type of award is described in the 2018 Plan. Unless accelerated in accordance with the 2018 Plan, unvested awards shall, if so determined by the Compensation Committee, terminate immediately upon the grantee resigning from or our terminating the grantee’s employment or contractual relationship with us or any related company without cause, including death or disability.

 

Options

 

The Compensation Committee is authorized to grant options to purchase ordinary shares that are either “qualified,” meaning they are intended to satisfy the requirements of Code Section 422 for incentive stock options, or “non-qualified,” meaning they are not intended to satisfy the requirements of Section 422 of the Code. Options granted under the 2018 Plan will be subject to the terms and conditions established by the Compensation Committee. Under the terms of the 2018 Plan, unless the Compensation Committee determines otherwise in the case of an option substituted for another option in connection with a corporate transaction, the exercise price of the options will not be less than the fair market value (as determined under the 2018 Plan) of the ordinary shares on the date of grant. Options granted under the 2018 Plan are subject to such terms, including the exercise price and the conditions and timing of exercise, as may be determined by the Compensation Committee and specified in the applicable award agreement. The maximum term of an option granted under the 2018 Plan is 10 years from the date of grant (or five years in the case of an incentive share option granted to a 10% shareholder). Payment in respect of the exercise of an option may be made in cash or by check, by surrender of unrestricted ordinary shares (at their fair market value on the date of exercise) that have been held by the participant for any period deemed necessary by our accountants to avoid an additional compensation charge or have been purchased on the open market, or the Compensation Committee may, in its discretion and to the extent permitted by law, allow such payment to be made through a broker-assisted cashless exercise mechanism, a net exercise method, or by such other method as the Compensation Committee may determine to be appropriate.

 

Share Appreciation Rights

 

The Compensation Committee is authorized to award share appreciation rights (or SARs) under the 2018 Plan. SARs are subject to such terms and conditions as established by the Compensation Committee. A SAR is a contractual right that allows a participant to receive, either in the form of cash, shares or any combination of cash and shares, the appreciation, if any, in the value of a share over a certain period of time. A SAR granted under the 2018 Plan may be granted in tandem with an option and SARs may also be awarded to a participant independent of the grant of an option. SARs granted in connection with an option shall be subject to terms similar to the option which corresponds to such SARs. SARs shall be subject to terms established by the Compensation Committee and reflected in the award agreement.

 

 

Restricted shares

 

The Compensation Committee is authorized to award restricted shares under the 2018 Plan. The Compensation Committee will determine the terms of such restricted shares awards. Restricted shares are ordinary shares that generally are non-transferable and subject to other restrictions determined by the Compensation Committee for a specified period. Unless the Compensation Committee determines otherwise or specifies otherwise in an award agreement, if the participant terminates employment or services during the restricted period, then any unvested restricted shares will be forfeited.

 

Restricted share unit Awards

 

The Compensation Committee is authorized to award restricted share unit awards. The Compensation Committee will determine the terms of such restricted share units. Unless the Compensation Committee determines otherwise or specifies otherwise in an award agreement, if the participant terminates employment or services during the period of time over which all or a portion of the units are to be earned, then any unvested units will be forfeited.

 

Bonus Share Awards

 

The Compensation Committee is authorized to grant awards of unrestricted ordinary shares or other awards denominated in ordinary shares, either alone or in tandem with other awards, under such terms and conditions as the Compensation Committee may determine.

 

Performance Compensation Awards

 

The Compensation Committee is authorized to grant any award under the 2018 Plan in the form of a Performance Compensation Award exempt from the requirements of Section 162(m) of the Code by conditioning the vesting of the Award on the attainment of specific performance criteria of our company and/or one or more of our affiliates, divisions or operational units, or any combination thereof, as determined by the Compensation Committee. The Compensation Committee will select the performance criteria based on one or more of the following factors: (i) revenue; (ii) sales; (iii) profit (net profit, gross profit, operating profit, economic profit, profit margins or other corporate profit measures); (iv) earnings (EBIT, EBITDA, earnings per share, or other corporate profit measures); (v) net income (before or after taxes, operating income or other income measures); (vi) cash (cash flow, cash generation or other cash measures); (vii) share price or performance; (viii) total shareholder return (share price appreciation plus reinvested dividends divided by beginning share price); (ix) economic value added; (x) return measures (including, but not limited to, return on assets, capital, equity, investments or sales, and cash flow return on assets, capital, equity, or sales); (xi) market share; (xii) improvements in capital structure; (xiii) expenses (expense management, expense ratio, expense efficiency ratios or other expense measures); (xiv) business expansion or consolidation (acquisitions and divestitures); (xv) internal rate of return or increase in net present value; (xvi) working capital targets relating to inventory and/or accounts receivable; (xvii) inventory management; (xviii) service or product delivery or quality; (xix) customer satisfaction; (xx) employee retention; (xxi) safety standards; (xxii) productivity measures; (xxiii) cost reduction measures; and/or (xxiv) strategic plan development and implementation.

 

Transferability

 

Each award may be exercised during the participant’s lifetime only by the participant or, if permissible under applicable law, by the participant’s guardian or legal representative and may not be otherwise transferred or encumbered by a participant other than by will or by the laws of descent and distribution. The Compensation Committee, however, may permit options (other than incentive share options) to be transferred to family members, a trust for the benefit of such family members, a partnership or limited liability company whose partners or shareholders are the participant and his or her family members or anyone else approved by it.

 

Amendment

 

In addition, our board of directors may amend, in whole or in part, our 2018 Plan at any time. However, without shareholder approval, except that (a) any amendment or alteration shall be subject to the approval of the our shareholders if such shareholder approval is required by any federal or state law or regulation or the rules of any stock exchange or automated quotation system on which the Shares may then be listed or quoted, and (b) our board of directors may otherwise, in its discretion, determine to submit other such amendments or alterations to shareholders for approval. Awards previously granted under the 2018 Plan may not be impaired or affected by any amendment of our 2018 Plan, without the consent of the affected grantees.

 

 

Change in Control

 

The 2018 Plan provides that in the event of a change of control, the Compensation Committee shall, unless an outstanding award is assumed by the surviving company or replaced with an equivalent award granted by the surviving company in substitution for such outstanding award cancel any outstanding awards that are not vested and non-forfeitable as of the consummation of such corporate transaction (unless the Compensation Committee, in its discretion, accelerates the vesting of any such awards). In respect to any vested and non-forfeitable awards, the Compensation Committee may, in its discretion, (i) allow all grantees to exercise such awards within a reasonable period prior to the consummation of the corporate transaction and cancel any outstanding awards that remain unexercised, or (ii) cancel any or all of such outstanding awards in exchange for a payment (in cash, or in securities or other property, up to the sole discretion of the Compensation Committee) in an amount equal to the amount that the grantee would have received if such vested awards were settled or distributed or exercised immediately prior to the consummation of the corporate transaction.

 

Director Compensation

 

Each independent director receives annual cash compensation equal to $30,000 per year for such directors’ services to our board of directors. The Chairman of the Board receives an additional $15,000 per year. In addition to the annual cash compensation for serving on our board of directors, each independent director that also serves on a committee of our board of directors receives compensation as follows: each member of the audit committee and compensation committee (not including the chairperson) receives annual cash compensation of $3,000 per year and each member of the Nominating and Corporate Governance Committee (not including the chairperson) receives annual cash compensation of $3,000 per year. The chairperson of our Audit Committee receives annual compensation of $27,000 and the chairperson of our Compensation Committee receives annual compensation of $6,000 and the chairperson of our Nominating and Corporate Governance Committee receives annual compensation of $3,000.

 

Employment Agreements and Other Arrangements with Named Executive Officers

 

Except as set forth below, we currently have no written employment agreements with any of our officers, directors, or key employees. While certain of our officers hold positions with other entities, pursuant to their employment agreements with us, each officer is required to spend substantially all of his working time, attention and skills to the performance of his duties to our company. Unless otherwise stated below, all employment agreements listed below with auto-renewal provisions were not terminated by either us or the employee, and were therefore automatically renewed.

 

In connection with the Reverse Stock Split, the number of stock options granted as described below decreased accordingly.

 

Wirawan Jusuf

 

On February 27, 2019, our board of directors approved an employment agreement with Wirawan Jusuf and we entered into such agreement (which we refer to as the Jusuf Agreement) with Mr. Jusuf effective February 1, 2019, under which he serves as our Chief Executive Officer. We also entered into a share option agreement with Mr. Jusuf effective as of February 1, 2019.

 

The Jusuf Agreement has an initial term beginning on February 1, 2019, and expiring one (1) year from such date. The Jusuf Agreement is subject to automatic renewal on a year-to-year renewal basis unless either we or Mr. Jusuf provides written notice not to renew the Jusuf Agreement no later than 30 days prior to the end of the then current or renewal term.

 

Pursuant to the terms and provisions of the Jusuf Agreement, Mr. Jusuf is entitled to an annual base salary of $282,000 (Mr. Jusuf’s annual base salary prior to the completion of our initial public offering was $189,000), cash bonuses as determined by our board of directors or its designated committee in its sole discretion, participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors.

 

 

We may terminate the Jusuf Agreement without cause upon 30 days’ prior written notice and Mr. Jusuf may resign without cause upon 30 days’ prior written notice. We may also immediately terminate the Jusuf Agreement for cause (as set forth in the Jusuf Agreement). Upon the termination of the Jusuf Agreement for any reason, Mr. Jusuf will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Mr. Jusuf is terminated during the term of the employment agreement other than for cause, Mr. Jusuf is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination and such severance payments as may be mandated by Indonesian law (presently one month of base salary for every year worked with us) (the “Jusuf Severance Payment”). In the event that such termination is upon a Change of Control (as defined in the Jusuf Agreement), Mr. Jusuf shall be entitled to the Jusuf Severance Payment. In addition, the Jusuf Agreement will terminate prior to its scheduled expiration date in the event of Mr. Jusuf’s death or disability.

 

The Jusuf Agreement also includes confidentiality and non-disclosure covenants as well as a twelve (12) month non-competition and non-solicitation covenant. The Jusuf Agreement is governed by Cayman Islands law.

 

Under Mr. Jusuf’s share option agreement, Mr. Jusuf was granted an option to purchase 150,000 ordinary shares under our 2018 Omnibus Equity Incentive Plan at an exercise price equal to $11.00 per share. Mr. Jusuf’s option shall vest as follows (assuming, in each case, that Mr. Jusuf remains employed with us): (a) 50,000 ordinary shares shall vest on the first anniversary of the closing of our initial public offering, (b) 50,000 ordinary shares shall vest on the second anniversary of the closing of our initial public offering; and (c) 50,000 ordinary shares shall vest on the third anniversary of the closing of our initial public offering. The share option agreement is governed by Cayman Islands law.

 

Frank C. Ingriselli

 

On February 27, 2019, our board of directors approved an employment agreement with Frank C. Ingriselli and we entered into such agreement (which we refer to as the Ingriselli Agreement) with Mr. Ingriselli effective February 1, 2019, under which he serves as our President. We also entered into a share option agreement with Mr. Ingriselli effective as of February 1, 2019. On January 23, 2020, we entered into an amendment to the Ingriselli Agreement (the “Ingriselli Amendment”). On January 21, 2022, we entered into a Second Amendment to Ingriselli Agreement (the “Ingriselli Second Amendment”). On December 28, 2023, we entered into the Ingriselli Third Amendment with Mr. Ingriselli, effective on January 1, 2024.

 

The Ingriselli Agreement had an initial term beginning on February 1, 2019, and expired one (1) year from such date. The Ingriselli Amendment extends the term of Mr. Ingriselli’s employment as our President for a two-year term commencing on February 1, 2020 and terminating on January 31, 2022, the Ingriselli Second Amendment extends the term of the Ingriselli Agreement to December 31, 2023, and the Ingriselli Third Amendment further extends the term of the Ingriselli Agreement to December 31, 2025 unless terminated earlier pursuant to the terms of the Ingriselli Agreement. The Ingriselli Agreement is not subject to automatic renewal.

 

Pursuant to the terms and provisions of the Ingriselli Agreement, as amended by the Ingriselli Amendment, Mr. Ingriselli is entitled to an annual base salary of $150,000 and a $75,000 cash bonus for services rendered during the year ended December 31, 2019. Cash bonuses as determined by our board of directors or its designated committee in its sole discretion. Pursuant to the Ingriselli Amendment, Mr. Ingriselli was also granted 35,000 ordinary shares as an equity incentive award for his continued service as our President. The vesting schedule of these shares is as follows: 18,750 vested on December 19, 2019, 9,375 will vest on June 16, 2020, and 9,375 will vest on December 19, 2020. The award also includes a 180-day lock-up period from the date of vesting. Participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors. Pursuant to the Ingriselli Second Amendment, Mr. Ingriselli was granted an award of 60,000 ordinary shares, with 30,000 shares vesting on July 1, 2022 and 30,000 vesting on January 1, 2023, with a lock-up period of 180 days from each vesting date. Pursuant to the Ingriselli Third Amendment, the pre-tax annual base salary for Mr. Ingriselli will remain at US$150,000; Mr. Ingriselli was granted an award of 60,000 ordinary shares, with 30,000 ordinary shares vesting on July 1, 2024 and 30,000 ordinary shares vesting on January 1, 2025, under a lock-up period of 180 days from each vesting date.

 

 

We may terminate the Ingriselli Agreement, as amended without cause upon 30 days’ prior written notice and Mr. Ingriselli may resign with or without cause upon 30 days’ prior written notice. We may also immediately terminate Ingriselli Agreement, as amended for cause (as set forth in the Ingriselli Agreement). Upon the termination of the Ingriselli Agreement for any reason, Mr. Ingriselli will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Mr. Ingriselli is terminated during the term of the employment agreement other than for cause, Mr. Ingriselli is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination. In addition, the Ingriselli Agreement, as amended will terminate prior to its scheduled expiration date in the event of Mr. Ingriselli’s death or disability.

 

The Ingriselli Agreement, as amended, also includes confidentiality and non-disclosure covenants as well as a twelve (12) month non-competition and non-solicitation covenant. The Ingriselli Agreement, as amended is governed by Cayman Islands law.

 

Under Mr. Ingriselli’s share option agreement, Mr. Ingriselli was granted an option to purchase 37,500 ordinary shares under our 2018 Omnibus Equity Incentive Plan at an exercise price equal to $11.00 per share. Mr. Ingriselli’s option shall vest as follows (assuming, in each case, that Mr. Ingriselli remains employed with us): (a) 18,750 ordinary shares shall vested on the date of effectiveness of our initial public offering registration statement, (b) 9,375 ordinary shares shall vest on the 180^th day following the closing of our initial public offering; and (c) 9,375 ordinary shares shall vest on the first anniversary of the closing of our initial public offering. The share option agreement is governed by Cayman Islands law.

 

James Jerry Huang

 

On February 27, 2019, our board of directors approved an employment agreement and share option agreement with James Jerry Huang and we entered into such agreements (which we refer to as the Huang Agreement) with Mr. Huang effective February 1, 2019, under which he serves as our Chief Investment Officer. We also entered into a share option agreement with Mr. Huang effective as of February 1, 2019.

 

The Huang Agreement has an initial term beginning on February 1, 2019, and expiring one (1) year from such date. The Huang Agreement is subject to automatic renewal on a year-to-year renewal basis unless either we or Mr. Huang provides written notice not to renew the Huang Agreement no later than 30 days prior to the end of the then current or renewal term.

 

Pursuant to the terms and provisions of the Huang Agreement, Mr. Huang is entitled to an annual base salary of $240,000 (Mr. Huang’s annual base salary prior to the completion of our initial public offering was $150,000), cash bonuses as determined by our board of directors or its designated committee in its sole discretion, participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors.

 

We may terminate the Huang Agreement without cause upon 30 days’ prior written notice and Mr. Huang may resign without cause upon 30 days’ prior written notice. We may also immediately terminate Huang Agreement for cause (as set forth in the Huang Agreement). Upon the termination of the Huang Agreement for any reason, Mr. Huang will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Mr. Huang is terminated during the term of the employment agreement other than for cause, Mr. Huang is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination and such severance payments as may be mandated by Indonesian law (presently one month of base salary for every year worked with us) (the “Huang Severance Payment”). In the event that such termination is upon a Change of Control (as defined in the Huang Agreement), Mr. Huang shall be entitled to the Huang Severance Payment. In addition, the Huang Agreement will terminate prior to its scheduled expiration date in the event of Mr. Huang’s death or disability.

 

The Huang Agreement also includes confidentiality and non-disclosure covenants as well as a twelve (a) month non-competition and non-solicitation covenant. The Huang Agreement is governed by Cayman Islands law.

 

 

Under Mr. Huang’s share option agreement, Mr. Huang was granted an option to purchase 150,000 ordinary shares under our 2018 Omnibus Equity Incentive Plan at an exercise price equal to $11.00 per share. Mr. Huang’s option shall vest as follows (assuming, in each case, that Mr. Huang remains employed with us): (a) 50,000 ordinary shares shall vest on the first anniversary of the closing of our initial public offering, (b) 50,000 ordinary shares shall vest on the second anniversary of the closing of our initial public offering; and (c) 50,000 ordinary shares shall vest on the third anniversary of the closing of our initial public offering. The share option agreement is governed by Cayman Islands law.

 

Gregory L. Overholtzer

 

On February 27, 2019, our board of directors approved an employment agreement with Gregory L. Overholtzer and we entered into such agreement (which we refer to as the Overholtzer Agreement) with Mr. Overholtzer effective February 1, 2019, under which he serves as our Chief Financial Officer. On January 29, 2020, we and Mr. Overholtzer entered into an amendment to the Overholtzer Agreement (the “Overholtzer Amendment”). On January 21, 2022, we entered into a Second Amendment to Overholtzer Agreement (the “Overholtzer Second Amendment”), effective January 1, 2022. On January 1, 2024, we entered into the Overholtzer Third Amendment with Mr. Overholtzer, effective on January 1, 2024.

 

The Overholtzer Agreement had an initial term beginning on February 1, 2019, which expired one (1) year from such date. Pursuant to the Overholtzer Amendment, Mr. Overholtzer’s employment term was extended for a two-year term commencing on February 1, 2020 and terminating on January 31, 2022, the Overholtzer Second Amendment extends the term of the Overholtzer Agreement to December 31, 2023, and the Overholtzer Third Amendment further extends the term of the Overholtzer Agreement to December 31, 2025 unless terminated earlier pursuant to the Overholtzer Agreement, as amended. The Overholtzer Agreement, as amended, is not subject to automatic renewal.

 

Pursuant to the terms and provisions of the Overholtzer Agreement, as amended by the Overholtzer Amendment, Mr. Overholtzer was entitled to an annual base salary of $40,000 until the effectiveness of our registration statement in connection with our IPO on December 19, 2019, when his annual base salary increased to $80,000. Cash bonuses as determined by our board of directors or its designated committee in its sole discretion, participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors. Pursuant to the Overholtzer Third Amendment, the pre-tax annual base salary for Mr. Overholtzer will remain at US$80,000.

 

We may terminate the Overholtzer Agreement without cause upon 30 days’ prior written notice and Mr. Overholtzer may resign with or without cause upon 30 days’ prior written notice. We may also immediately terminate Overholtzer Agreement for Cause (as set forth in the Overholtzer Agreement). Upon the termination of the Overholtzer Agreement for any reason, Mr. Overholtzer will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Mr. Overholtzer is terminated during the term of the employment agreement other than for cause, Mr. Overholtzer is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination. In addition, the Overholtzer Agreement, as amended will terminate prior to its scheduled expiration date in the event of Mr. Overholtzer’s death or disability.

 

The Overholtzer Agreement, as amended, also includes confidentiality and non-disclosure covenants as well as a twelve (12) month non-competition and non-solicitation covenant. The Overholtzer Agreement, as amended, is governed by Cayman Islands law.

 

Chia Hsin “Charlie” Wu

 

On February 27, 2019, our board of directors approved an employment agreement with Chia Hsin “Charlie” Wu and we entered into such agreements (which we refer to as the Wu Agreement) with Dr. Wu effective February 1, 2019, under which he serves as our Chief Operating Officer. We also entered into a share option agreement with Dr. Wu effective as of February 1, 2019.

 

The Wu Agreement has an initial term beginning on February 1, 2019, and expiring one (1) year from such date. The Wu Agreement is subject to automatic renewal on a year-to-year renewal basis unless either we or Dr. Wu provides written notice not to renew the Wu Agreement no later than 30 days prior to the end of the then current or renewal term.

 

 

Pursuant to the terms and provisions of the Wu Agreement, Dr. Wu is entitled to an annual base salary of $204,000 following our initial public offering (Dr. Wu’s annual base salary prior to the completion of our initial public offering was $75,000), cash bonuses as determined by our board of directors or its designated committee in its sole discretion, participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors.

 

On January 16, 2024, we entered into the Wu First Amendment with Dr. Wu, effective January 16, 2024. The Wu First Amendment amended and restated the Wu Agreement between us and Dr. Wu. Pursuant to the Wu First Amendment: (i) Dr. Wu serves as our Chief Technology Officer (“CTO”), effective from January 16, 2024; (ii) the pre-tax annual base salary for Dr. Wu remains at US$204,000; (iii) Dr. Wu shall perform the duties and responsibilities (a) typically associated with the office of CTO of a similarly sized U.S. listed public company in the oil and gas exploration and production sector and (b) outlined in the Wu First Amendment. As a result of the Wu First Amendment, Dr. Wu is our CTO, and is no longer our COO. Except for the foregoing, no further changes were made to the Wu First Amendment.

 

We may terminate the Wu Agreement without cause upon 30 days’ prior written notice and Dr. Wu may resign without cause upon 30 days’ prior written notice. We may also immediately terminate Wu Agreement for cause (as set forth in the Wu Agreement). Upon the termination of the Wu Agreement for any reason, Dr. Wu will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Dr. Wu is terminated during the term of the employment agreement other than for cause, Dr. Wu is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination and such severance payments as may be mandated by Indonesian law (presently one month of base salary for every year worked with us) (the “Wu Severance Payment”). In the event that such termination is upon a Change of Control (as defined in the Wu Agreement), Dr. Wu shall be entitled to the Wu Severance Payment. In addition, the Wu Agreement will terminate prior to its scheduled expiration date in the event of Dr. Wu’s death or disability.

 

The Wu Agreement also includes confidentiality and non-disclosure covenants as well as a twelve (12) month non-competition and non-solicitation covenant. The Wu Agreement is governed by Cayman Islands law.

 

Under Dr. Wu’s share option agreement, Dr. Wu was granted an option to purchase 150,000 ordinary shares under our 2018 Omnibus Equity Incentive Plan at an exercise price equal to $11.00 per share. Dr. Wu’s option shall vest as follows (assuming, in each case, that Dr. Wu remains employed with us): (a) 50,000 ordinary shares shall vest on the first anniversary of the closing of our initial public offering, (b) 50,000 ordinary shares shall vest on the second anniversary of the closing of our initial public offering; and (c) 50,000 ordinary shares shall vest on the third anniversary of the closing of our initial public offering. The share option agreement is governed by Cayman Islands law.

 

Mirza F. Said

 

On February 27, 2019, our board of directors approved an employment agreement with Mirza F. Said and we entered into such agreements (which we refer to as the Said Agreement) with Mr. Said effective February 1, 2019, under which he served as Chief Business Development Officer. We also entered into a share option agreement with Mr. Said effective as of February 1, 2019.

 

The Said Agreement has an initial term beginning on February 1, 2019, and expiring one (1) year from such date. The Said Agreement is subject to automatic renewal on a year-to-year renewal basis unless either we or Mr. Said provides written notice not to renew the Said Agreement no later than 30 days prior to the end of the then current or renewal term.

 

Pursuant to the terms and provisions of the Said Agreement, Mr. Said is entitled to an annual base salary of $204,000 following our initial public offering (Mr. Said’s annual base salary prior to the completion of our initial public offering was $135,000), cash bonuses as determined by our board of directors or its designated committee in its sole discretion, participation in our 2018 Omnibus Equity Incentive Plan or similar equity incentive plans, and other employee benefits as approved by our board of directors.

 

On January 16, 2024, we entered into the Said First Amendment with Mr. Said, effective January 16, 2024. The Said First Amendment amended and restated the Said Agreement between us and Mr. Said.

 

Pursuant to the Said First Amendment: (i) Mr. Said serves as our Chief Operating Officer (“COO”), effective from January 16, 2024; (ii) the pre-tax annual base salary for Mr. Said remains at US$204,000; and (iii) Mr. Said shall perform the duties and responsibilities (a) typically associated with the office of COO of a similarly sized U.S. listed public company in the oil and gas exploration and production sector and (b) outlined in the Said First Amendment. As a result of the Said First Amendment, Mr. Said, is our COO, and is no longer our Chief Business Development Officer, and no other individual was appointed to this position. Except for the foregoing, no further changes were made to the Said First Amendment.

 

We may terminate the Said Agreement without cause upon 30 days’ prior written notice and Mr. Said may resign without cause upon 30 days’ prior written notice. We may also immediately terminate Said Agreement for cause (as set forth in the Said Agreement). Upon the termination of the Said Agreement for any reason, Mr. Said will be entitled to receive payment of any base salary earned but unpaid through the date of termination and any other payment or benefit to which he is entitled under the applicable terms of any applicable company arrangements. If Mr. Said is terminated during the term of the employment agreement other than for cause, Mr. Said is entitled to, upon delivering to us a general release of our company and its affiliates in a form satisfactory to us, the amount of base salary earned and not paid prior to termination and such severance payments as may be mandated by Indonesian law (presently one month of base salary for every year worked with us) (the “Said Severance Payment”). In the event that such termination is upon a Change of Control (as defined in the Said Agreement), Mr. Said shall be entitled to the Said Severance Payment. In addition, the Said Agreement will terminate prior to its scheduled expiration date in the event of Mr. Said’s death or disability.

 

 

The Said Agreement also includes confidentiality and non-disclosure covenants as well as a twelve (12) month non-competition and non-solicitation covenant. The Said Agreement is governed by Cayman Islands law.

 

Under Mr. Said’s share option agreement, Mr. Said was granted an option to purchase 150,000 ordinary shares under our 2018 Omnibus Equity Incentive Plan at an exercise price equal to $11.00 per share. Mr. Said’s option shall vest as follows (assuming, in each case, that Mr. Said remains employed with us): (a) 50,000 ordinary shares shall vest on the first anniversary of the closing of our initial public offering, (b) 50,000 ordinary shares shall vest on the second anniversary of the closing of our initial public offering; and (c) 50,000 ordinary shares shall vest on the third anniversary of the closing of our initial public offering. The share option agreement is governed by Cayman Islands law.

 

Non-Employee Director Compensation

 

For the year ended December 31, 2023, each independent director receives annual cash compensation equal to $30,000 per year for such directors’ services to our board of directors. In addition to the annual cash compensation for serving on our board of directors, each independent director that also serves on a committee of our board of directors receives compensation as follows: each member of the audit committee and compensation committee (not including the chairperson) receives annual cash compensation of $3,000 per year and each member of the Nominating and Corporate Governance Committee (not including the chairperson) receives annual cash compensation of $3,000 per year. The chairperson of our Audit Committee receives annual compensation of $27,000 and the chairperson of our Compensation Committee receives annual compensation of $6,000 and the chairperson of our Nominating and Corporate Governance Committee receives annual compensation of $3,000.

 

Equity Awards for Non-Employee Directors

 

As of December 31, 2023, none of our non-employee directors were granted any options.

 

Employees

 

As of December 31, 2023, 2022 and 2021, we had 33, 30 and 28 permanent employees, respectively, and 42, 35, and 34 contract employees, respectively. Our employees are not represented by a labor organization or covered by a collective bargaining agreement. We have not experienced any work stoppages, and we believe we maintain good relationships with our employees.

 

The table below sets forth the breakdown of our employees by function as of December 31, 2023:

 

Function		Number of Employees				% of Total
Senior Management			6				8.00	%
Subsurface			3				4.00	%
Engineering			3				4.00	%
Operation and Production			3				4.00	%
Finance and Accounting			6				8.00	%
Administration, Procurement and Human Resources			9				12.00	%
Health, Safety, Security and Environment (or HSSE)			2				2.67	%
Local Relations			1				1.33	%
Operation Contract Employees (production, construction and HSSE)			42				56.00	%
Total (including 33 permanent employees and 42 contract employees)			75				100	%

 

 

We believe that all of our contract employees for non-specialized job functions are replaceable in the marketplace, thus not representing a material risk to our business. We believe we are in material compliance with Indonesian labor regulations.

 

Share Ownership

 

Please see Item 7 Major Shareholders and Related Party Transactions of this annual report for information relating to ownership of our securities by our directors, officers and certain major shareholders.

 

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

 

Major Shareholders

 

The following table sets forth information regarding the beneficial ownership of our ordinary shares as of the date of this report by our officers, directors, and 5% or greater beneficial owners of ordinary shares. There is no other person or group of affiliated persons known by us to beneficially own more than 5% of our ordinary shares.

 

We have determined beneficial ownership in accordance with the rules of the SEC. These rules generally attribute beneficial ownership of securities to persons who possess sole or shared voting power or investment power with respect to those securities. The person is also deemed to be a beneficial owner of any security of which that person has a right to acquire beneficial ownership within 60 days. Unless otherwise indicated, the person identified in this table has sole voting and investment power with respect to all shares shown as beneficially owned by him, subject to applicable community property laws. Percentage ownership of our ordinary shares in the following table is based on 10,172,694 ordinary shares outstanding as of April 23, 2024. Unless otherwise noted, the business address for each of our directors and executive officers is GIESMART PLAZA 7th Floor, Jl. Raya Pasar Minggu No. 17A, Pancoran – Jakarta 12780 Indonesia.

 

		Ordinary Shares Beneficially Owned
Name of Beneficial Owners		Number				%
Directors and Executive Officers:
Dr. Wirawan Jusuf (1)			5,267,767				51.78	%
Frank C. Ingriselli			30,000				*
Mirza F. Said (2)			45,545				*
James J. Huang (3)			45,545				*
Chia Hsin “Charlie” Wu (4)			45,545				*
Gregory L. Overholtzer			—				—
Mochtar Hussein			—				—
Benny Dharmawan			—				—
Ahmad FathurachmanFathurachman			—				—
Michael L. Peterson			—				—
All directors and officers as a group			5,434,402				53.42	%
5% shareholders:
MADERIC Holding Limited (1)			5,222,222				51.34	%

 

(1)

Dr. Wirawan Jusuf, our Chairman and Chief Executive Officer, holds voting and dispositive control over, and thus beneficial ownership of, the shares held by MADERIC Holding Limited. Beneficial ownership excludes options to purchase 50,000 ordinary shares at $11.00 per share which vested on December 23, 2022 (the third anniversary of the closing of our initial public offering).

 

(2)	Beneficial ownership excludes options to purchase 50,000 ordinary shares at $11.00 per share which vested on December 23, 2022 (the third anniversary of the closing of our initial public offering).

 

 

(3)	Beneficial ownership excludes options to purchase 50,000 ordinary shares at $11.00 per share which vested on December 23, 2022 (the third anniversary of the closing of our initial public offering).

 

(4)	Beneficial ownership excludes options to purchase 50,000 ordinary shares at $11.00 per share which vested on December 23, 2022 (the third anniversary of the closing of our initial public offering).

 

*	Less than one percent

 

Related Party Transactions

 

Other than the executive and director compensation and other arrangements discussed in the “Item 6. Directors, Senior Management and Employees” of this report, we have not entered into any transactions to which we or our subsidiaries have been or are a party of the type which is required to be disclosed under Item 7.B of the Form 20-F for fiscal years ended December 31, 2023, 2022 and 2021.

 

Our audit committee is required to review and approve any related party transaction we propose to enter into. Our audit committee charter details the policies and procedures relating to transactions that may present actual, potential or perceived conflicts of interest and may raise questions as to whether such transactions are consistent with the best interest of our company and our stockholders.

 

Interests of Experts and Counsel

 

Not applicable.

 

ITEM 8. FINANCIAL INFORMATION

 

The financial statements required by this item can be found at the end of this report beginning on page F-1.

 

Legal Proceedings

 

From time to time, we may be subject to legal proceedings arising in the ordinary course of business. As of the date of this report, we are not a party to any litigation or similar proceedings.

 

Dividend Policy

 

Subject to the provisions of the Companies Act and any rights for the time being attaching to any class or classes of shares: (i) our directors may declare dividends or distributions out of our funds which are lawfully available for that purpose and (ii) our shareholders may, by ordinary resolution, declare dividends but no such dividend shall exceed the amount recommended by the directors.

 

Subject to the requirements of the Companies Act regarding the application of a company’s share premium account and with the sanction of an ordinary resolution, dividends may also be declared and paid out of any share premium account. The directors when paying dividends to shareholders may make such payment either in cash or in specie.

 

Unless provided by the rights attached to a share, no dividend shall bear interest.

 

We do not know when or if we will pay dividends to our shareholders (including our public shareholders), and the likelihood that we will be paying dividends on our ordinary is remote at this time. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities.

 

Significant Changes

 

There have been no significant changes since the date of the consolidated financial statements included in this annual report.

 

 

ITEM 9. THE OFFER AND LISTING

 

Our ordinary shares are listed on the NYSE American under the symbol “INDO.”

 

ITEM 10. ADDITIONAL INFORMATION

 

A.	Share Capital

 

Not applicable.

 

B.	Amended and Restated Memorandum and Articles of Association of the Company

 

Our amended and restated memorandum and articles of association have been filed with the SEC as an exhibit to our registration statement on Form F-1 filed with the SEC on November 12, 2019. Those amended and restated memorandum and articles of association contained in such filing are incorporated by reference.

 

C.	Material contracts

 

Attached as exhibits to this annual report or incorporated by reference herein are the contracts we consider to be both material and outside the ordinary course of business during the two-year period immediately preceding the date of this annual report. We refer you to “Item 4. Information on the Company” and “Related Party Transactions” under “Item 7. Major Shareholders and related party transactions” of this annual report for a discussion of these contracts. Other than as discussed in this annual report, we have no material contracts, other than contracts entered into in the ordinary course of business, to which we are a party.

 

D.	Exchange controls

 

There are no exchange control regulations or currency restrictions in the Cayman Islands.

 

E.

Taxation

 

The following discussion of material Cayman Islands, Indonesia and United States federal income tax consequences of an investment in our ordinary shares is based upon laws and relevant interpretations thereof in effect as of the date of this annual report, all of which are subject to change. This discussion does not deal with all possible tax consequences relating to an investment in our ordinary shares, such as the tax consequences under state, local and other tax laws. To the extent that the discussion relates to matters of Cayman Islands tax law, it represents the opinion of Ogier, our Cayman Islands counsel.

 

Cayman Islands Taxation

 

The Cayman Islands currently levies no taxes on individuals or corporations based upon profits, income, gains or appreciation and there is no taxation in the nature of inheritance tax or estate duty. There are no other taxes likely to be material to us levied by the Government of the Cayman Islands except for stamp duties which may be applicable on instruments executed in, or after execution brought within, the jurisdiction of the Cayman Islands. No stamp duty is payable in the Cayman Islands on the issue of shares by, or any transfers of shares of, Cayman Islands companies (except those which hold interests in land in the Cayman Islands). The Cayman Islands is not party to any double tax treaties which are applicable to any payments made to or by our company. There are no exchange control regulations or currency restrictions in the Cayman Islands.

 

 

Payments of dividends and capital in respect of our shares will not be subject to taxation in the Cayman Islands and no withholding will be required on the payment of dividends or capital to any holder of our shares, nor will gains derived from the disposal of our shares be subject to Cayman Islands income or corporation tax.

 

Pursuant to Section 6 of the Tax Concessions Act (Revised) of the Cayman Islands, we have obtained an undertaking from the Financial Secretary of the Cayman Islands:

 

(1)

that no law which is enacted in the Cayman Islands imposing any tax to be levied on profits or income or gains or appreciation shall apply to us or our operations; and

 

(2)

in addition, that no tax to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable:

 

(i)

on or in respect of the shares, debentures or other obligations of our company; or

 

(ii)

by way of the withholding in whole or in part of any “relevant payment” as defined in section 6(3) of the Tax Concessions Act (Revised).

 

The undertaking is for a period of twenty years from November 2, 2018.

 

Material U.S. Federal Income Tax Considerations 

 

Subject to the qualifications and limitations described below, the following are the material U.S. federal income tax consequences of the purchase, ownership and disposition of ordinary shares to a “U.S. Holder.” Non-U.S. Holders are urged to consult their own tax advisors regarding the U.S. federal income tax consequences of the purchase, ownership and disposition of ordinary shares to them.

 

For purposes of this discussion, a “U.S. Holder” means a beneficial owner of ordinary shares that is, for U.S. federal income tax purposes:

 

	●	An individual who is a citizen or resident of the United States;
	●	A corporation (or other entity taxed as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States or any of its political subdivisions;
	●	An estate, whose income is includible in gross income for U.S. federal income tax purposes regardless of its source; or
	●	A trust if (i) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or (ii) it has a valid election to be treated as a U.S. person.

 

A “non-U.S. Holder” is any individual, corporation, trust or estate that is a beneficial owner of ordinary shares and is not a U.S. Holder.

 

This discussion is based on current provisions of the Internal Revenue Code of 1986, as amended, or the Code, applicable U.S. Treasury Regulations promulgated thereunder, and administrative and judicial decisions as at the date hereof, all of which are subject to change, possibly on a retroactive basis, and any change could affect the continuing accuracy of this discussion.

 

This summary does not purport to be a comprehensive description of all of the tax considerations that may be relevant to each person’s decision to purchase ordinary shares. This discussion does not address all aspects of U.S. federal income taxation that may be relevant to any particular U.S. Holder based on such holder’s particular circumstances, including Medicare tax imposed on certain investment income. In particular, this discussion considers only U.S. Holders that will own ordinary shares as capital assets within the meaning of section 1221 of the Code and does not address the potential application of U.S. federal alternative minimum tax or the U.S. federal income tax consequences to U.S. Holders that are subject to special treatment, including:

 

	●	Broker dealers or insurance companies;
	●	U.S. Holders who have elected mark-to-market accounting;

 

 

	●	Tax-exempt organizations or pension funds;
	●	Regulated investment companies, real estate investment trusts, insurance companies, financial institutions or “financial services entities”;
	●	U.S. Holders who hold ordinary shares as part of a “straddle,” “hedge,” “constructive sale” or “conversion transaction” or other integrated investment;
	●	U.S. Holders who own or owned, directly, indirectly or by attribution, at least 10% of the voting power of our ordinary shares;
	●	U.S. Holders whose functional currency is not the U.S. Dollar;
	●	U.S. Holders who received ordinary shares as compensation;
	●	U.S. Holders who are otherwise subject to UK taxation;
	●	Persons holding ordinary shares in connection with a trade or business outside of the United States; and
	●	Certain expatriates or former long-term residents of the United States.

 

This discussion does not consider the tax treatment of holders that are entities treated as partnerships for U.S. federal income tax purposes or other pass-through entities or persons who hold ordinary shares through a partnership or other pass-through entity. In addition, this discussion does not address any aspect of state, local or non-U.S. tax laws, or the possible application of U.S. federal gift or estate tax.

 

BECAUSE OF THE COMPLEXITY OF THE TAX LAWS AND BECAUSE THE TAX CONSEQUENCES TO ANY PARTICULAR HOLDER OF ORDINARY SHARES MAY BE AFFECTED BY MATTERS NOT DISCUSSED HEREIN, EACH HOLDER OF ORDINARY SHARES IS URGED TO CONSULT WITH ITS TAX ADVISOR WITH RESPECT TO THE SPECIFIC TAX CONSEQUENCES OF THE ACQUISITION AND THE OWNERSHIP AND DISPOSITION OF ORDINARY SHARES, INCLUDING THE APPLICABILITY AND EFFECT OF STATE, LOCAL AND NON-U.S. TAX LAWS, AS WELL AS U.S. FEDERAL TAX LAWS AND APPLICABLE TAX TREATIES.

 

Taxation of Dividends Paid on Ordinary Shares

 

Subject to the passive foreign investment company rules discussed below, the gross amount of distributions made by us with respect to our ordinary shares generally will be includable in the gross income of U.S. Holders as foreign source passive income. Because we do not determine our earnings and profits for U.S. federal income tax purposes, a U.S. Holder will be required to treat any distribution paid on ordinary shares, including the amount of non-U.S. taxes, if any, withheld from the amount paid, as a dividend on the date the distribution is received. Such distribution generally will not be eligible for the dividends-received deduction generally allowed to U.S. corporations in respect of dividends received from other U.S. corporations.

 

Cash distributions paid in a non-U.S. currency will be included in the income of U.S. Holders at a U.S. Dollar amount equal to the spot rate of exchange in effect on the date the dividends are includible in the income of the U.S. Holders, regardless of whether the payment is in fact converted to U.S. Dollars, and U.S. Holders will have a tax basis in such non-U.S. currency for U.S. federal income tax purposes equal to such U.S. Dollar value. If a U.S. Holder converts a distribution paid in non-U.S. currency into U.S. Dollars on the day the dividend is includible in the income of the U.S. Holder, the U.S. Holder generally should not be required to recognize gain or loss arising from exchange rate fluctuations. If a U.S. Holder subsequently converts the non-U.S. currency, any subsequent gain or loss in respect of such non-U.S. currency arising from exchange rate fluctuations will be U.S.-source ordinary income or loss.

 

 

Dividends we pay with respect to our ordinary shares to non-corporate U.S. Holders may be “qualified dividend income,” which is currently taxable at a reduced rate; provided that (i) our ordinary shares are readily tradable on an established securities market in the United States, (ii) we are not a passive foreign investment company (as discussed below) with respect to the U.S. Holder for either our taxable year in which the dividend was paid or the preceding taxable year, (iii) the U.S. Holder has held our ordinary shares for at least 61 days of the 121-day period beginning on the date which is 60 days before the ex-dividend date, and (v) the U.S. Holder is not under an obligation to make related payments on substantially similar or related property. We believe our ordinary shares, which are expected to be listed on the NYSE American, will be considered to be readily tradable on an established securities market in the United States, although there can be no assurance that this will continue to be the case in the future. Any days during which a U.S. Holder has diminished its risk of loss on our ordinary shares are not counted towards meeting the 61-day holding period. U.S. Holders should consult their own tax advisors on their eligibility for reduced rates of taxation with respect to any dividends paid by us.

 

Distributions paid on ordinary shares generally will be foreign-source passive category income for U.S. foreign tax credit purposes and will not qualify for the dividends received deduction generally available to corporations. Subject to certain conditions and limitations, non-U.S. taxes, if any, withheld from a distribution may be eligible for credit against a U.S. Holder’s U.S. federal income tax liability. In addition, if 50 percent or more of the voting power or value of our shares is owned, or is treated as owned, by U.S. persons (whether or not we are a “controlled foreign corporation” for U.S. federal income tax purposes), the portion of our dividends attributable to income which we derive from sources within the United States (whether or not in connection with a trade or business) would generally be U.S.-source income. U.S. Holders would not be able directly to utilize foreign tax credits arising from non U.S. taxes considered to be imposed upon U.S.-source income.

 

Taxation of the Sale or Other Disposition of Ordinary Shares

 

Subject to the passive foreign investment company rules discussed below, a U.S. Holder generally will recognize a capital gain or loss on the taxable sale or other disposition of our ordinary shares in an amount equal to the difference between the U.S. Dollar amount realized on such sale or other disposition (determined in the case of consideration in currencies other than the U.S. Dollar by reference to the spot exchange rate in effect on the date of the sale or other disposition or, if the ordinary shares are treated as traded on an established securities market and the U.S. Holder is a cash basis taxpayer or an electing accrual basis taxpayer, the spot exchange rate in effect on the settlement date) and the U.S. Holder’s adjusted tax basis in such ordinary shares determined in U.S. Dollars. The initial tax basis of ordinary shares to a U.S. Holder will be the U.S. Holder’s U.S. Dollar cost for ordinary shares (determined by reference to the spot exchange rate in effect on the date of the purchase or, if the ordinary shares are treated as traded on an established securities market and the U.S. Holder is a cash basis taxpayer or an electing accrual basis taxpayer, the spot exchange rate in effect on the settlement date).

 

Capital gain from the sale, exchange or other disposition of ordinary shares held more than one year generally will be treated as long-term capital gain and is eligible for a reduced rate of taxation for non-corporate holders. Gain or loss recognized by a U.S. Holder on a sale or other disposition of ordinary shares generally will be treated as U.S.-source income or loss for U.S. foreign tax credit purposes. The deductibility of a capital loss recognized on the sale or exchange of ordinary shares is subject to limitations. A U.S. Holder that receives currencies other than U.S. Dollars upon disposition of the ordinary shares and converts such currencies into U.S. Dollars subsequent to receipt will have foreign exchange gain or loss based on any appreciation or depreciation in the value of such currencies against the U.S. Dollar, which generally will be U.S.-source ordinary income or loss.

 

Passive Foreign Investment Company

 

Based on our current composition of assets and market capitalization (which will fluctuate from time to time), we believe that we are not and will not become a passive foreign investment company, or a PFIC, for U.S. federal income tax purposes. However, the determination of whether we are a PFIC is made annually, after the close of the relevant taxable year. Therefore, it is possible that we could be classified as a PFIC for the current taxable year or in future years due to changes in the composition of our assets or income, as well as changes to our market capitalization. The market value of our assets may be determined in large part by reference to the market price of our ordinary shares, which may fluctuate.

 

 

In general, a non-U.S. corporation will be classified as a PFIC for any taxable year if at least (i) 75% of its gross income is classified as “passive income” or (ii) 50% of its assets (determined on the basis of a quarterly average) produce or are held for the production of passive income. For these purposes, cash is considered a passive asset. In making this determination, the non-U.S. corporation is treated as earning its proportionate share of any income and owning its proportionate share of any assets of any corporation in which it holds 25% or more (by value) of the stock.

 

Under the PFIC rules, if we were considered a PFIC at any time that a U.S. Holder holds our shares, we would continue to be treated as a PFIC with respect to such holder’s investment unless (i) we cease to be a PFIC and (ii) the U.S. Holder has made a “deemed sale” election under the PFIC rules.

 

If we are considered a PFIC at any time that a U.S. Holder holds our shares, any gain recognized by the U.S. Holder on a sale or other disposition of the shares, as well as the amount of an “excess distribution” (defined below) received by such holder, would be allocated ratably over the U.S. Holder’s holding period for the shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for that taxable year, and an interest charge would be imposed. For purposes of these rules, an excess distribution is the amount by which any distribution received by a U.S. Holder on its shares exceeds 125% of the average of the annual distributions on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the shares.

 

If we are treated as a PFIC with respect to a U.S. Holder for any taxable year, the U.S. Holder will be deemed to own shares in any of our subsidiaries that are also PFICs. However, an election for mark-to-market treatment would likely not be available with respect to any such subsidiaries. If we are considered a PFIC, a U.S. Holder will also be subject to information reporting requirements on an annual basis. U.S. Holders should consult their own tax advisors about the potential application of the PFIC rules to an investment in our shares.

 

If we were classified as a PFIC, a U.S. Holder may be able to make a mark-to-market election with respect to our ordinary shares (but not with respect to the shares of any lower-tier PFICs) if the ordinary shares are “regularly traded” on a “qualified exchange”. In general, our ordinary shares issued will be treated as “regularly traded” in any calendar year in which more than a de minimis quantity of ordinary shares are traded on a qualified exchange on at least 15 days during each calendar quarter. We believe the NYSE American is a qualified exchange. However, we can make no assurance that the ordinary shares will be listed on a “qualified exchange” or that there will be sufficient trading activity for the ordinary shares to be treated as “regularly traded”. Accordingly, U.S. Holders should consult their own tax advisers as to whether their ordinary shares would qualify for the mark-to-market election.

 

If a U.S. Holder makes the mark-to-market election, for each year in which our company is a PFIC, the holder will generally include as ordinary income the excess, if any, of the fair market value of the ordinary shares at the end of the taxable year over their adjusted tax basis, and will be permitted an ordinary loss in respect of the excess, if any, of the adjusted tax basis of the ordinary shares over their fair market value at the end of the taxable year (but only to the extent of the net amount of previously included income as a result of the mark-to-market election). If a U.S. Holder makes the election, the holder’s tax basis in our ordinary shares will be adjusted to reflect any such income or loss amounts. Any gain recognized on the sale or other disposition of our ordinary shares will be treated as ordinary income, and any loss will be treated as an ordinary loss to the extent of any prior mark-to-market gains.

 

If a U.S. Holder makes the mark-to-market election, it will be effective for the taxable year for which the election is made and all subsequent taxable years unless the ordinary shares are no longer regularly traded on a qualified exchange or the IRS consents to the revocation of the election.

 

If we were classified as a PFIC, U.S. Holders would not be eligible to make an election to treat us as a “qualified electing fund,” or a QEF election, because we do not anticipate providing U.S. Holders with the information required to permit a QEF election to be made.

 

 

U.S. Information Reporting and Backup Withholding

 

A U.S. Holder is generally subject to information reporting requirements with respect to dividends paid in the United States on ordinary shares and proceeds paid from the sale, exchange, redemption or other disposition of ordinary shares. A U.S. Holder is subject to backup withholding (currently at 24%) on dividends paid in the United States on ordinary shares and proceeds paid from the sale, exchange, redemption or other disposition of our ordinary shares unless the U.S. Holder is a corporation, provides an IRS Form W-9 or otherwise establishes a basis for exemption.

 

Backup withholding is not an additional tax. Amounts withheld under the backup withholding rules may be credited against a U.S. Holder’s U.S. federal income tax liability, and a U.S. Holder may obtain a refund from the IRS of any excess amount withheld under the backup withholding rules, provided that certain information is timely furnished to the IRS. Holders are urged to consult their own tax advisors regarding the application of backup withholding and the availability of and procedures for obtaining an exemption from backup withholding in their particular circumstances.

 

F.	Dividends and paying agents

 

Not applicable.

 

G.	Statement by experts

 

Not applicable

 

H.	Documents on display

 

We file annual reports and other information with the SEC. You may inspect and copy any report or document we file, including this annual report and the accompanying exhibits, at the website maintained by the SEC at http://www.sec.gov, as well as on our website at www.indo-energy.com. Information on our website does not constitute a part of this annual report and is not incorporated by reference.

 

We will also provide without charge to each person, including any beneficial owner of our ordinary shares, upon written or oral request of that person, a copy of any and all of the information that has been incorporated by reference in this annual report. Please direct such requests to James J. Huang, Chief Investment Officer, Indonesia Energy Corporation Limited, GIESMART PLAZA 7^th Floor, Jl. Raya Pasar Minggu No. 17A, Pancoran – Jakarta 12780 Indonesia.

 

I.	Subsidiary information

 

Not applicable.

 

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Credit Risk

 

As of December 31, 2023 and 2022, all of our accounts receivable result from the entitlement of Oil & Gas Property subject to amortization and profit sharing from the sale of the crude oil under the KSO by Pertamina. This concentration of receivables from one party may impact our overall credit risk, either positively or negatively, in that Pertamina may be similarly affected by changes in economic or other conditions.

 

For the years ended December 31, 2023, 2022 and 2021, 100% of our revenues were generated through the operatorship of Kruh Block. We do not believe that there will be any material adverse change in the operatorship of Kruh Block or the KSO.

 

Liquidity Risk

 

See above “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources”.

 

 

Interest Rate Risk

 

We do not enter into investments for trading or speculative purposes and have not used any derivative financial instruments to manage our interest rate risk exposure.

 

Foreign Currency Exchange Rate Risk

 

Our reporting currency is the United States dollar (“USD”, “dollar”). The currency of the primary economic environment in which our operations are conducted is dollar. Therefore, the dollar has been determined to be our functional currency.

 

Non-dollar transactions and balances have been translated into dollars for financial reporting purposes. Transactions in foreign currency (primarily in Indonesian Rupiahs – “IDR”) are recorded at the exchange rate as of the transaction date. Monetary assets and liabilities denominated in foreign currency are translated on the basis of the representative rates of exchange at the balance sheet dates. All exchange gains and losses from re-measurement of monetary balance sheet items denominated in non-dollar currencies are reflected in the statement of operations as they arise.

 

See “Risk Factors – Risks Related to Doing Business in Indonesia – Fluctuations in the value of the Indonesian Rupiah may materially and adversely affect us.”

 

Inflation Risk

 

We do not consider inflation to be a significant risk to direct expenses in the current and foreseeable future. However, in the event that inflation becomes a significant factor in the global economy, inflationary pressures would result in increased operating and financing costs.

 

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

 

Not applicable.

 

PART II

 

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

 

None.

 

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OR PROCEEDS

 

Rights of Security Holders

 

See Item 10. Additional Information—B. “Amended and Restated Memorandum and Articles of Association of the Company” for a reference to a description of the rights of securities holders, which remain unchanged.

 

ITEM 15. CONTROLS AND PROCEDURES

 

A. Disclosure Controls and Procedures

 

An evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, regarding the effectiveness of our design and operation of our disclosure controls and procedures as of December 31, 2023. Based on that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures as of December 31, 2023 were ineffective due to the lack of sufficient financial reporting and accounting personnel with appropriate knowledge of U.S. GAAP and SEC reporting requirements to properly address complex U.S. GAAP accounting issues and to prepare and review our consolidated financial statements and related disclosures to fulfil U.S. GAAP and SEC financial reporting requirements. Our goal is to remediate deficiencies in our disclosure controls via the actions described under “Management’s Annual Report on Internal Control over Financial Reporting” below.

 

 

Disclosure controls and procedures are designed to enable us to record, process, summarize and report information required to be included in the reports that we file or submit under the Exchange Act within the time period required and also effective to ensure that information required to be disclosed in the reports that it files or submits under the Exchange Act is accumulated and communicated to our management, including its principal executive and principal financial officer, to allow timely decisions regarding required disclosure.

 

It should be noted that while our disclosure controls and procedures as of December 31, 2023 were designed at the reasonable assurance level, our management does not expect that our disclosure controls and procedures or internal financial controls will prevent all errors or fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

 

B. Management’s Annual Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Principal Executive Officer (Wirawan Jusuf) and Principal Financial Officer (Gregory L. Overholtzer), and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP, including those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and the disposition of our assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of our management and board of directors, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the consolidated financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

 

Management conducted an evaluation of the effectiveness of our control over financial reporting based on the 2013 framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2023.

 

In connection with the audit of our consolidated financial statements for the year ended December 31, 2023, we identified a material weakness in our internal control over financial reporting as of December 31, 2023. As defined in the standards established by the U.S. Public Company Accounting Oversight Board (the “PCAOB”), a “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

 

A material weakness identified with regards to our company related to the lack of sufficient financial reporting and accounting personnel with appropriate knowledge of U.S. GAAP and SEC reporting requirements to properly address complex U.S. GAAP accounting issues and to prepare and review our consolidated financial statements and related disclosures to fulfill U.S. GAAP and SEC financial reporting requirements.

 

 

During 2023, we sought to implement and will continue to implement a number of measures to address the material weakness, including the following measures:

 

	●	We are continuing our efforts to hire additional qualified internal finance and accounting staff with working experience in U.S. GAAP and SEC reporting requirements.
	●	We have also established clear roles and responsibilities for accounting and financial reporting staff to address accounting and financial reporting issues.
	●	We intend to establish an ongoing program to provide sufficient and appropriate training for financial reporting and accounting personnel, especially training related to U.S. GAAP and SEC reporting requirements.
	●	We have engaged and will continue to engage professional financial advisory firms if necessary to provide ongoing training to our finance and accounting personnel as well as to strengthen our financial reporting expertise and system.

 

We expect to complete the measures discussed above as soon as practicable and will continue to implement measures to remediate our internal control deficiency to comply with Section 404 of the Sarbanes Oxley Act. We expect that we will incur significant costs in the implementation of such measures. However, we cannot assure you that all these measures will be sufficient to remediate our material weakness in time, or at all. If we fail to implement and maintain an effective system of internal controls to remediate our material weakness over financial reporting, we may be unable to accurately report our results of operations, meet our reporting obligations or prevent fraud, and investor confidence and the market price of our ordinary shares may be materially and adversely affected.

 

C. Attestation Report of the Registered Public Accounting Firm

 

As a company with less than US$1.235 billion in revenue for our last fiscal year, we qualify as an “emerging growth company” pursuant to the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other requirements that are otherwise applicable generally to public companies. These provisions include exemption from the auditor attestation requirement under Section 404 of the Sarbanes-Oxley Act of 2002 in the assessment of the emerging growth company’s internal control over financial reporting for 5 years. Therefore, this annual report contains no such attestation of our registered independent accounting firm.

 

D. Changes in Internal Controls Over Financial Reporting

 

Other than as described above, there were no changes in our internal controls over financial reporting that occurred during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 16. RESERVED

 

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

 

Our board of directors has determined that Michael L. Peterson, is an independent director and a member and chairperson of our audit committee, is an “Audit Committee Financial Expert” under Section 407(d)(5) of Regulation S-K promulgated under the Securities and Exchange Act of 1934, as amended, and the corporate governance rules of NYSE American.

 

ITEM 16B. CODE OF ETHICS

 

Our Code of Ethics (“Code of Ethics”) applies to all of our employees, including our chief executive officer, chief financial officer and principal accounting officer. Our Code of Ethics is available on our corporate website, indo-energy.com. If we amend or grant a waiver of one or more of the provisions of our Code of Ethics, we intend to file a current report on Form 6-K to disclose amendments to or waivers from provisions of our Code of Ethics that apply to our principal executive officer, principal financial officer and principal accounting officer by posting the required information on our website.

 

 

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The following table sets forth the aggregate fees for audit and other services provided by our independent registered public accounting firm, Marcum Asia CPAs LLP, for the years ended December 31, 2023 and 2022:

 

$’000		2022				2023
Audit Fees1		$	303			$	345
Tax Fees			-				-
All Other Fees			-				-
Total fees		$	303			$	345

 

(1) “Audit Fees” represent the aggregate fees billed or to be billed for each of the fiscal years listed for professional services rendered by our principal auditor for the audit of our annual financial statements.

 

We have not engaged Marcum Asia CPAs LLP to provide tax compliance, tax advice, tax planning or any other services.

 

In accordance with our charter, the audit committee is required to pre-approve all audit and non-audit services to be performed by our independent auditors and the related fees for such services other than prohibited non-auditing services as promulgated under rules and regulations of the SEC (subject to the inadvertent de minimis exceptions set forth in the Sarbanes-Oxley Act of 2002 and the SEC rules). Subsequent to our initial public offering in December 2020, all services performed by Marcum Asia CPAs LLP for our benefit were pre-approved by the audit committee in accordance with its charter and all applicable laws, rules and regulations.

 

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

 

Not applicable.

 

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

 

We did not purchase any ordinary shares from the open market during the period covered by this annual report.

 

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

 

None.

 

ITEM 16G. CORPORATE GOVERNANCE

 

As a foreign private issuer, as defined in Rule 3b-4 under the Exchange Act, we are permitted to follow certain corporate governance rules of our home country (the Cayman Islands) in lieu of NYSE American’s corporate governance rules. Our corporate governance practices do not deviate from NYSE American corporate governance rules and we are in full compliance with all other applicable NYSE American corporate governance standards; provided, however, that (i) in January 2022 in connection with our financing with L1 Capital, we formally adopted home country practice and thereby opted out of the NYSE American rule that would otherwise require shareholder approval should we issue more than 19.99% of our then outstanding ordinary shares in a financing that is not a “public offering” at less than the then current market value, and (ii) on December 22, 2023, we adopted home country practice and thereby opted out of the NYSE American rule that would otherwise require each issuer listing common stock or voting preferred stock, and/or their equivalents to hold an annual meeting of shareholders no later than one year after the end of the issuer’s fiscal year.

 

ITEM 16H. MINE SAFETY DISCLOSURE

 

Not applicable.

 

 

PART III

 

ITEM 17. FINANCIAL STATEMENTS

 

See Item 18 “Financial Statements.”

 

ITEM 18. FINANCIAL STATEMENTS

 

The financial information required by this item, together with the reports of Marcum Asia CPAs LLP, is set forth on pages F-1 through F-37 and are filed as part of this annual report.

 

ITEM 19. EXHIBITS

 

Exhibit				Incorporated Herein by Reference								Filed
Number		Exhibit Title		Form		File No.		Exhibit		Filing Date		Herewith
3.1		Amended and Restated Memorandum of Association of the Registrant		F-1		333-232894		3.1		November 12, 2019
3.2		Amended and Restated Articles of Association of the Registrant		F-1		333-232894		3.2		November 12, 2019
10.1		Sale and Purchase of Shares and Receivables Agreement, dated June 30, 2018, by and between the Registrant, Maderic Holding Limited, HFO Investment Group Limited, Opera Cove International Limited and WJ Energy Group Limited.		F-1		333-232894		10.1		July 30, 2019
10.2		Debt Conversion Agreement, dated June 30, 2018, by and between the Registrant, Maderic Holding Limited and HFO Investment Group Limited		F-1		333-232894		10.2		July 30, 2019
10.3		Debt Acknowledgement Note, dated June 30, 2018 (Maderic Holding Limited)		F-1		333-232894		10.3		July 30, 2019
10.4		Debt Acknowledgement Note, dated June 30, 2018 (HFO Investment Group)		F-1		333-232894		10.4		July 30, 2019
10.5		Contract regarding acquisition of Citarum Block and/or the 2016 joint study regarding the Citarum Block (Joint Study Agreement)		F-1		333-232894		10.5		November 12, 2019
10.6		Technical Assistance Contract with PT Pertamina in regards to the Kruh Block		F-1		333-232894		10.6		July 30, 2019
10.7		Letter extending Kruh contract		F-1		333-232894		10.7		August 21, 2019
10.8		Employment Agreement, dated February 1, 2019, between the Registrant and Dr. Wirawan Jusuf+		F-1		333-232894		10.8		July 30, 2019
10.9		Share Option Agreement, dated February 1, 2019, between the Registrant and Dr. Wirawan Jusuf+		F-1		333-232894		10.9		July 30, 2019
10.10		Employment Agreement, dated February 1, 2019, between the Registrant and Frank C. Ingriselli+		F-1		333-232894		10.10		July 30, 2019
10.11		Share Option Agreement, dated February 1, 2019, between the Registrant and Frank C. Ingriselli+		F-1		333-232894		10.11		July 30, 2019
10.12		First Amendment to Employment Agreement, dated January 23. 2020, between the Company and Frank C. Ingriselli+		6-K		001-39164		10.1		January 29, 2020

 

 

10.13		Employment Agreement, dated February 1, 2019, between the Registrant and Chia Hsin “Charlie” Wu+		F-1		333-232894		10.12		July 30, 2019
10.14		Share Option Agreement, dated February 1, 2019, between the Registrant and Chia Hsin “Charlie” Wu+		F-1		333-232894		10.13		July 30, 2019
10.15		Employment Agreement, dated February 1, 2019, between the Registrant and Mirza F. Said+		F-1		333-232894		10.14		July 30, 2019
10.16		Share Option Agreement, dated February 1, 2019, between the Registrant and Mirza F. Said+		F-1		333-232894		10.15		July 30, 2019
10.17		Employment Agreement, dated February 1, 2019, between the Registrant and James J. Huang+		F-1		333-232894		10.16		July 30, 2019
10.18		Share Option Agreement, dated February 1, 2019, between the Registrant and James J. Huang+		F-1		333-232894		10.17		July 30, 2019
10.19		Employment Agreement, dated February 1, 2019, between the Registrant and Gregory L. Overholtzer+		F-1		333-232894		10.18		July 30, 2019
10.20		First Amendment to Employment Agreement, dated January 29. 2020, between the Company and Gregory L. Overholtzer+		6-K		001-39164		10.2		January 29, 2020
10.21		Indonesian Energy Corporation Limited 2018 Equity Incentive Plan+		F-1		333-232894		10.19		July 30, 2019
10.22		Securities Purchase Agreement, dated January 21, 2022, between the Company and L1 Capital		6-K		001-39164		10.1		January 25, 2022
10.23		Senior Convertible Promissory Note issued to L1 Capital, dated January 21, 2022		6-K		001-39164		10.2		January 25, 2022
10.24		Form of Ordinary Share Purchase Warrant issued to L1 Capital		6-K		001-39164		10.3		January 25, 2022
10.25		Guaranty, dated January 21, 2022, by WJ Energy Group Limited favor of L1 Capital		6-K		001-39164		10.4		January 25, 2022
10.26		Second Amendment to Employment Agreement, dated January 21, 2022, between the Company and Frank C. Ingriselli+		6-K		001-39164		10.5		January 25, 2022
10.27		Second Amendment to Employment Agreement, dated January 21, 2022, between the Company and Gregory L. Overholtzer+		6-K		001-39164		10.6		January 25, 2022
10.28		First Amendment to Securities Purchase Agreement, dated March 4, 2022, between the Company and L1 Capital		6-K		001-39164		10.1		March 9, 2022
10.29		Amended and Restated Senior Convertible Promissory Note issued to L1 Capital, dated March 4, 2022		6-K		001-39164		10.2		March 9, 2022
10.30		Second Amended and Restated Senior Convertible Note issued to L1 Capital, dated May 16, 2022.		6-K		001-39164		10.1		May 16, 2022
10.31		At The Market Offering Agreement, dated July 22, 2022, by and between the Company and H.C. Wainwright & Co., LLC		6-K		001-39164		1.1		July 22, 2022
10.32		First Amendment to At The Market Offering Agreement, dated March 22, 2024, by and between the Company and and H.C. Wainwright & Co., LLC		F-3		333-278175		10.7		March 22, 2024
10.33		English Translation of Amendment to Operations Cooperation Agreement for Kruh Block, dated August 9, 2023, between PT Pertamina EP and PT Green World Nusantara (the Company’s subsidiary) ^		6-K		001-39164		10.1		September 28, 2023
10.34		Third Amendment to Employment Agreement, dated December 28, 2023, between the Company and Frank C. Ingriselli.		6-K		001-39164		10.1		January 3, 2024
10.35		Third Amendment to Employment Agreement, dated January 1, 2024, between the Company and Gregory L. Overholtzer.		6-K		001-39164		10.2		January 3, 2024
10.36		First Amendment to Employment Agreement, dated January 16, 2024, between the Company and Mirza F. Said.		6-K		001-39164		10.1		January 18, 2024
10.37		First Amendment to Employment Agreement, dated January 16, 2024, between the Company and Chia Hsin “Charlie” Wu.		6-K		001-39164		10.2		January 18, 2024
21.1		Subsidiaries of the registrant		F-1		333-232894		21.1		July 30, 2019
12.1		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted by Section 302 of the of the Sarbanes-Oxley Act of 2002*										X

 

 

12.2

Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted by Section 302 of the of the Sarbanes-Oxley Act of 2002*

X

13.1

Certification of Chief Executive Officer Pursuant to 18 U.S.C. section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002*

X

13.2

Certification of Chief Financial Officer Pursuant to 18 U.S.C. section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002*

X

23.1

Consent of Marcum Asia CPAs LLP

X

99.1

Nominating and Corporate Governance Committee Charter

F-1

333-232894

99.1

July 30, 2019

99.2

Compensation Committee Charter

F-1

333-232894

99.2

July 30, 2019

99.3

Audit Committee Charter

F-1

333-232894

99.3

July 30, 2019

99.4

Home Country Exemption Letter

6-K

001-39164

99.1

December 22, 2023

99.5

Executive Compensation Clawback Policy

X

99.6

Insider Trading Policies and Procedures

101.INS

Inline XBRL Instance Document

X

101.SCH

Inline XBRL Taxonomy Extension Schema Document

X

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document

X

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document

X

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document

X

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document

X

104

Cover Page Interactive Data File (embedded within the Inline XBRL document)

 

+	Management contract or compensatory plan or arrangement.
*	Furnished herewith
^	Certain portions of this exhibit (indicated by “[***]”) have been omitted pursuant to Regulation S-K, Item 601(b)(10) as the Company has determined such portions are both not material and are of the type that the Company treats as private or confidential.

 

 

SIGNATURES

 

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

 

	INDONESIA ENERGY CORPORATION LIMITED
	By:	/s/ Dr. Wirawan Jusuf
	Name:	Dr. Wirawan Jusuf
	Title:	Chairman & Chief Executive Officer

Date: April 26, 2024

 

 

INDONESIA ENERGY CORPORATION LIMITED

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

		Page
Report of Independent Registered Public Accounting Firm (PCAOB ID No: 5395)		F-2
Consolidated Balance Sheets as of December 31, 2023 and 2022		F-3
Consolidated Statements of Operations and Comprehensive Loss for the Years Ended December 31, 2023, 2022 and 2021		F-4
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021		F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021		F-6
Notes to the Consolidated Financial Statements		F-7

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Shareholders and Board of Directors of Indonesia Energy Corporation Limited

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Indonesia Energy Corporation Limited (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations and comprehensive loss, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

 

Basis for Opinion

 

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ Marcum Asia CPAs LLP

 

Marcum Asia CPAs LLP

We have served as the Company’s auditor since 2018.

 

Beijing, China
April 26, 2024

 

 

INDONESIA ENERGY CORPORATION LIMITED

CONSOLIDATED BALANCE SHEETS

 

		December 31, 2023				December 31, 2022
Current assets
Cash		$	2,009,687			$	5,895,565
Restricted cash			1,567,500				-
Accounts receivables			582,335				468,153
Prepayment and other current assets			1,920,576				1,504,101
Total current assets			6,080,098				7,867,819
Non-current assets
Restricted cash			420,000				1,500,000
Property and equipment, net			109,017				201,495
Oil and gas property - subject to amortization, net			7,111,624				7,469,820
Oil and gas property - not subject to amortization			1,155,439				1,151,804
Right of use assets, net			1,097,168				351,446
Deferred charges			938,392				1,013,698
Other non-current assets, net			812,943				1,018,246
Total non-current assets			11,644,583				12,706,509
Total assets		$	17,724,681			$	20,574,328
Liabilities and Equity
Current liabilities
Accounts payables		$	753,823			$	719,095
Short-term operating lease liabilities			629,325				255,845
Accrued expenses			152,078				23,945
Taxes payable			60,698				147,797
Other current liabilities			17,941				70,085
Total current liabilities			1,613,865				1,216,767
Non-current liabilities
Asset retirement obligations			352,636				448,720
Warrant liabilities			482,219				1,389,643
Long-term operating lease liabilities			467,843				95,601
Provision for post-employment benefits			118,250				99,588
Total non-current liabilities			1,420,948				2,033,552
Total liabilities		$	3,034,813			$	3,250,319
Commitments and contingencies			-				-
Shareholders’ Equity
Preferred shares (par value $0.00267; 3,750,000 shares authorized, nil shares issued and outstanding as of December 31, 2023 and 2022, respectively)			-				-
Ordinary shares (par value $0.00267; 37,500,000 shares authorized, 10,142,694 shares issued and outstanding as of December 31, 2023 and 2022)		$	27,046			$	27,046
Additional paid-in capital			54,147,769				54,147,769
Accumulated deficit			(39,583,437	)			(36,940,753	)
Accumulated other comprehensive income			98,490				89,947
Total shareholders’ equity			14,689,868				17,324,009
Total liabilities and shareholders’ equity		$	17,724,681			$	20,574,328

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

INDONESIA ENERGY CORPORATION LIMITED

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

 

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
Revenue		$	3,525,454			$	4,097,403			$	2,452,540
Operating costs and expenses:
Lease operating expenses			2,950,869				2,953,254				2,492,476
Depreciation, depletion and amortization			702,217				1,139,723				810,855
General and administrative expenses			3,368,029				4,602,656				5,250,618
Total operating costs and expenses			7,021,115				8,695,633				8,553,949
Loss from operations			(3,495,661	)			(4,598,230	)			(6,101,409	)
Other income (expense):
Change in fair value of warrant liability			907,424				2,878,660				-
Foreign currency exchange gain			136,788				(130,684	)			28,489
Allowance on other receivable			59,604				-				-
Issuance loss of warrants			-				(133,325	)			-
Issuance costs allocated to warrant liability			-				(465,577	)			-
Other (expense) income, net			(131,631	)			(673,436	)			(10,459	)
Total other income, net			852,977				1,475,638				18,030
Loss before income tax			(2,642,684	)			(3,122,592	)			(6,083,379	)
Income tax provision			-				-				-
Net loss			(2,642,684	)			(3,122,592	)			(6,083,379	)
Comprehensive loss:
Net loss			(2,642,684	)			(3,122,592	)			(6,083,379	)
Actuarial gain for post-employment benefits			8,543				59,243				30,704
Total comprehensive loss			(2,634,141	)			(3,063,349	)			(6,052,675	)
Loss per ordinary share
Basic and diluted		$	(0.26	)		$	(0.35	)		$	(0.82	)
Weighted average ordinary shares outstanding*
Basic and diluted			10,142,694				8,888,421				7,420,414

 

*

The shares are presented on a retroactive basis to reflect the reverse stock split.

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

INDONESIA ENERGY CORPORATION LIMITED

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

 

		Number of Shares				Amount				Number of Shares				Amount				Paid-in Capital				Accumulated Deficit				Comprehensive Income				Total Equity
		Preferred Shares, $0.00267 Par Value								Ordinary Shares, $0.00267 Par Value								Additional								Accumulated Other
		Number of Shares				Amount				Number of Shares				Amount				Paid-in Capital				Accumulated Deficit				Comprehensive Income				Total Equity
Balance as of December 31, 2020			-			$	-				7,407,955			$	19,754			$	40,073,087			$	(27,734,782	)		$	-			$	12,358,059
Net loss			-				-				-				-				-				(6,083,379	)			-				(6,083,379	)
Actuarial gain for post-employment benefits			-				-				-				-				-				-				30,704				30,704
Issuance of shares for compensation of employee and nonemployee services			-				-				40,000				107				225,669				-				-				225,776
Share-based compensation			-				-				-				-				1,288,583				-				-				1,288,583
Balance as of December 31, 2021			-			$	-				7,447,955			$	19,861			$	41,587,339			$	(33,818,161	)		$	30,704			$	7,819,743
Net loss			-				-				-				-				-				(3,122,592	)			59,243				(3,063,349	)
Issuance of ordinary shares by ATM offering			-				-				458,375				1,222				4,365,420				-				-				4,366,642
Conversion of Convertible Note			-				-				1,650,000				4,400				4,028,639				-				-				4,033,039
Exercise of warrants			-				-				325,000				866				3,429,799				-				-				3,430,665
Issuance of shares in exchange of service											62,105				166				210,607												210,773
Exercise of options			-				-				199,259				531				(531	)			-				-				-
Share-based compensation			-				-				-				-				526,496				-				-				526,496
Balance as of December 31, 2022			-			$	-				10,142,694			$	27,046			$	54,147,769			$	(36,940,753	)		$	89,947			$	17,324,009
Balance			-			$	-				10,142,694			$	27,046			$	54,147,769			$	(36,940,753	)		$	89,947			$	17,324,009
Net loss			-				-				-				-				-				(2,642,684	)			-				(2,642,684	)
Actuarial gain for post employment			-				-				-				-				-				-				8,543				8,543
Balance as of December 31, 2023			-			$	-				10,142,694			$	27,046			$	54,147,769			$	(39,583,437	)		$	98,490				14,689,868
Balance			-			$	-				10,142,694			$	27,046			$	54,147,769			$	(39,583,437	)		$	98,490				14,689,868

 

*	The shares are presented on a retroactive basis to reflect the reverse stock split.

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

INDONESIA ENERGY CORPORATION LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
Cash flows from operating activities
Net loss		$	(2,642,684	)		$	(3,122,592	)		$	(6,083,379	)
Adjustments to reconcile net loss to net cash used in operating activities
Issuance loss of warrants			-				133,325				-
Insurance costs allocated to warrant liability			-				465,577				-
Change in fair value of warrant liability			(907,424	)			(2,878,660	)			-
Depreciation, depletion and amortization			702,217				1,139,723				810,855
Amortization of deferred charges			75,306				75,306				78,991
Amortization on Right of Use Asset			472,777				353,997				-
Amortization of issuance discount on Convertible note			(52,144	)			646,250				-
Allowance on other receivable			59,604				-				-
Share-based compensation			-				526,496				1,288,583
Issuance of shares for compensation of employee and non-employee services			-				210,773				225,776
Post-employment benefits costs			27,205				43,438				77,396
Changes in operating assets and liabilities
Accounts receivable			(114,182	)			529,588				134,213
Prepayment and other current assets			(1,026,079	)			(564,100	)			(234,065	)
Other non-current assets			755,303				(98,727	)			209,002
Accounts payable			102,925				(255,154	)			-
Other current liabilities			-				(2,649	)			1,469
Accrued expenses			128,133				(119,853	)			(40,403	)
Taxes payable			(87,099	)			63,121				(17,094	)
Operating lease liabilities			(472,777	)			(353,997	)			-
Net cash used in operating activities			(2,978,919	)			(3,208,138	)			(3,548,656	)
Cash flows from investing activities
Oil and gas exploration and development costs			(419,459	)			(5,414,817	)			(2,448,270	)
Purchase of property and equipment			-				(1,684	)			(311,559	)
Net cash used in investing activities			(419,459	)			(5,416,501	)			(2,759,829	)
Cash flows from financing activities
Proceeds from issuance of convertible notes and warrants, net of issuance cost			-				8,589,000				-
Proceeds from exercise of warrant shares			-				1,950,000				-
Proceeds from issuance of ordinary shares by ATM offering, net of issuance cost			-				4,366,642				-
Repayment of bank loan			-				(980,452	)			-
Repayment of long term loan to a third party			-				(1,000,000	)			-
Net cash provided by financing activities			-				12,925,190				-
Net change in cash and restricted cash			(3,398,378	)			4,300,551				(6,308,485	)
Cash and restricted cash at beginning of year			7,395,565				3,095,014				9,403,499
Cash and restricted cash at end of year		$	3,997,187			$	7,395,565			$	3,095,014
Supplementary disclosure of cash flow information:
Cash paid for:
Interest		$	-			$	23,836			$	15,673
Income tax		$	-			$	-			$	-
Reconciliation of cash and restricted cash
Cash		$	2,009,687			$	5,895,565			$	595,014
Restricted Cash - current			1,567,500				-				1,000,000
Restricted Cash - non-current			420,000				1,500,000				1,500,000
Cash and restricted cash at end of year		$	3,997,187			$	7,395,565			$	3,095,014
Non-cash investing and financing activities
Addition of asset retirement obligations		$	42,998			$	188,873			$	-
Purchase of oil and gas property financed by accounts payable		$	-			$	-			$	1,061,945
Conversion of Convertible Note to ordinary shares		$	-			$	4,033,040			$	-
Right-of-use assets acquired under operating leases in exchange for operating liabilities		$	169,094			$	705,443			$	-

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

INDONESIA ENERGY CORPORATION LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 – ORGANIZATION AND PRINCIPAL ACTIVITIES

 

Indonesia Energy Corporation Limited (the “Company” or “IEC”)

 

Indonesia Energy Corporation Limited was formed on April 24, 2018 as an exempted company with limited liability under the laws of the Cayman Islands and is a holding company for WJ Energy Group Limited (or “WJ Energy”), which in turn owns 100% of the operating subsidiaries in Indonesia, which are described below. The Company has two shareholders: Maderic Holding Limited (or “Maderic”) and HFO Investment Group (or “HFO”), which hold 87.04% and 12.96%, respectively, of IEC’s outstanding shares, prior to the initial public offering (“IPO”). Certain of IEC’s officers and directors own interests in Maderic and HFO. The Company, through its subsidiaries in Hong Kong and in Indonesia, is an oil and gas exploration and production company focused on the Indonesian market. The Company currently holds two oil and gas assets through subsidiaries in Indonesia: one producing block (the “Kruh Block”) and one exploration block (the “Citarum Block”). The Company also identified a potential third exploration block (the “Rangkas Area”).

 

The following diagram illustrates the Company’s structure, including its consolidated holding and operating subsidiaries as of December 31, 2023

 

 

F-7

 

Corporate Structuring

 

Details of the subsidiaries of the Company as of December 31, 2023 are set out below:

 

 SUMMARY OF DETAILS OF THE SUBSIDIARIES OF THE COMPANY

Percentage of

Date of

Place of

effective

Principal

Name

Incorporation

Incorporation

ownership

Activities

WJ Energy Group Limited (“WJ Energy”)

June 3, 2014

Hong Kong

100

%

Holding company

PT Green World Nusantara (“GWN”)

February 27, 2015

Indonesia

100

%

Kruh Block operation

PT Harvel Nusantara Energi (“HNE”)

March 20, 2017

Indonesia

100

%

Holding company

PT Cogen Nusantara Energi (“CNE”)

December 7, 2017

Indonesia

100

%

Citarum Block operation

PT Hutama Wiranusa Energi (“HWE”)

May 14, 2018

Indonesia

100

%

Citarum Block operation

 

Kruh Block Technical Assistance Contract (“TAC”) and Joint Operation Partnership (“KSO”)

 

The Company’s revenue and potential for profit depend mostly on the level of oil production in Kruh Block and the Indonesian Crude Price (“ICP”) that is correlated to international crude oil prices.

 

The Kruh Block operation was governed by the TAC established between GWN and PT Pertamina (Persero) (“Pertamina”), under which the Company had the operatorship to, but not the ownership of, the extraction and production of oil from the designated oil deposit location in Indonesia until May 2020 and the operatorship of Kruh Block continued as a KSO from May 2020 until May 2030, which was further extended to September 2035 in August 2023. This extension effectively gives the Company 13 years to fully develop the existing three oil fields, and five other undeveloped oil and gas bearing structures at Kruh Block. Further, the Amended KSO increases our after-tax profit split from 15% to 35%, for an increase of more than 100%, and increases cost recovery cap from 80% to 100%. During the operations, the Company paid all expenditures and obligations incurred including but not limited to exploration, development, extraction, production, transportation, abandonment and site restoration. These costs, depending on the purpose, are either capitalized on the balance sheet as Oil and gas property – subject to amortization, net, or expensed as lease operating expenses. Section “Oil & Gas Property, Full Cost Method” of Note 2 provides further discussion about the accounting treatment of these costs.

 

On a monthly basis, based on TAC, the Company submitted to Pertamina an Entitlement Calculation Statement (“ECS”) stating the amount of money that GWN is entitled to. Such entitlement is made through the proceeds of the sale, conducted by Pertamina, of the crude oil produced in the block on a monthly basis based on the prevailing ICP, but capped at 65% of such monthly proceeds. In addition, the Company is also entitled to an additional 26.79% of the remaining 35% of the proceeds from the sale of the crude oil as part of the profit sharing. Both of these two portions of entitlements are recognized as revenue of the Company, net of tax. Section “Revenue Recognition” of Note 2 provides further discussion about the accounting treatment of these entitlements.

 

After May 2020, the Company continued the operatorship of Kruh Block under a KSO contract. In essence, the TAC and KSO are very similar in nature due to its “cost recovery” system, with a few important differences to note. The main differences between the two contracts are that: (1) in the TAC, all oil produced is shareable between Pertamina and its contractor, while in the KSO, a Non-Shareable Oil (NSO) production is determined and agreed between Pertamina and its partners so that the baseline production, with an established decline rate, belongs entirely to Pertamina, so that the partners’ revenue and production sharing portion shall be determined only from the production above the NSO baseline; (2) in the TAC, the cost recovery was capped at 65% of the proceeds from the sale of the oil produced in the block, while in the KSO, the cost recovery is capped at 100% of the proceeds from the sale of the oil produced within Kruh Block for the cost incurred during the term under the KSO plus 80% of the operating cost per barrel of oil (“bbl”) multiplying NSO. Any remaining cost recovery balance from the KSO period of contract is carried over to the next period, although the cost recovery balance from the TAC contract were not carried over to the KSO, meaning that the cost recovery balance was reset to nil with the commencement of the operatorship under the KSO in May 2020. As of December 31, 2023 and 2022, the unrecovered expenditures on KSO operations are $6,521,865 and $6,700,186, respectively.

 

F-8

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of presentation and consolidation

 

The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

 

The consolidated financial statements include the financial statements of the Company and all its majority-owned subsidiaries from the dates they were acquired or incorporated. All intercompany balances and transactions have been eliminated in consolidation.

 

Use of estimates

 

The preparation of the consolidated financial statements in conformity with US GAAP requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Significant accounting estimates reflected in the Company’s consolidated financial statements include but are not limited to estimates and judgments applied in the valuation of warrant liabilities, allowance for receivables, estimated useful lives of property and equipment, depletion and impairment of oil and gas property, impairment of long-lived assets, asset retirement obligations, provision for post-employment benefit, income taxes, related deferred tax valuation allowances and going concern forecast. Actual results could differ from those estimates and judgments.

 

Cash

 

Cash consists of cash on hand and bank deposits, which are unrestricted as to withdrawal and use. The Company had no cash equivalents as of December 31, 2023 and 2022.

 

Restricted cash

 

Restricted cash includes cash pledged for bank loan facilities, cash deposits in special account for the abandonment and site restoration and as performance guarantee in the oil and gas concessions in which the Company operates.

 

Foreign Currency Transaction

 

The reporting currency of the Company is United States dollar (“USD”, “dollar”). The currency of the primary economic environment in which the operations of the Company are conducted is dollar. Therefore, the dollar has been determined to be the Company’s functional currency. Non-dollar transactions and balances have been translated into dollars for financial reporting purposes. Transactions in foreign currency (primarily in Indonesian Rupiahs – “IDR”) are recorded at the exchange rate as of the transaction date. Monetary assets and liabilities denominated in foreign currency are translated on the basis of the representative rates of exchange at the balance sheet dates. All exchange gains and losses from re-measurement of monetary balance sheet items denominated in non-dollar currencies are reflected in the statement of operations as they arise.

 

Accounts receivable and other receivables

 

The Company adopted ASU2016-13 from January 1, 2023. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. The standard will replace incurred loss approach with an expected loss model for instruments measured at amortized cost. After review of accounts receivable and other receivables as of January 1, 2023, there is no cumulative-effect adjustment to retained earnings for the beginning balances.

 

Accounts receivable and other receivables as of December 31, 2023 are recorded at net realizable value consisting of the carrying amount less an allowance for expected credit losses as needed. All expected credit losses were measured for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The Company uses forward-looking information to better inform our credit loss estimates. We will continue to use judgment to determine which loss estimation method is appropriate for their circumstances. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company did not have any off-balance-sheet credit exposure relating to its customers, suppliers or others. For the years ended December 31, 2023, the Company recorded $59,604 allowances for doubtful accounts against its other receivables. For the year ended December 31, 2022 and 2021, the Company did not record any allowances for doubtful accounts against its accounts receivable and other receivables nor did it charge off any such amounts.

 

F-9

 

Credit and concentration risk

 

As of December 31, 2023 and 2022, all of the Company’s accounts receivable result from the entitlement of Oil & Gas Property subject to amortization and profit sharing from the sale of the crude oil under the KSO by Pertamina. This concentration of receivables from one party may impact the Company’s overall credit risk, either positively or negatively, in that Pertamina may be similarly affected by changes in economic or other conditions.

 

For the years ended December 31, 2023, 2022 and 2021, 100% of the Company’s revenues were generated through the operatorship of Kruh Block. The Company does not believe that there will be any material adverse change in the operatorship of Kruh Block or the KSO.

 

The Company places its cash and restricted cash, with reputable financial institutions that have high-credit ratings and quality. There has been no recent history of default in relation to these financial institutions.

 

Property and equipment, net

 

Property and equipment are stated at cost less accumulated depreciation and accumulated impairment losses. Cost represents the purchase price of the asset and other costs incurred to bring the asset into its existing use. Maintenance and repairs are charged to expense; major additions to physical properties are capitalized.

 

Depreciation of leasehold improvements is provided using the straight-line method over the shorter of the remaining lease term or their estimated useful lives. Except for leasehold improvements, depreciation of other property and equipment are provided using the declining balance method over their estimated useful lives:

 SCHEDULE OF PROPERTY AND EQUIPMENT ESTIMATED USEFUL LIVES

		Useful life
Housing and welfare		10 years
Furniture and office equipment		5 years
Computer and software		5 years
Production facilities		5 years
Leasehold improvements		Shorter of the remaining lease terms or 5 years
Drilling and production tools		5 years
Equipment		5 years

 

Upon sale or disposal, the applicable amounts of asset cost and accumulated depreciation are removed from the accounts and the net amount less proceeds from disposal is charged or credited to the consolidated statement of operations.

 

Impairment of long-lived assets

 

The Company reviews its long-lived assets or asset group for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may no longer be recoverable. When these events occur, the Company assesses the recoverability of the long-lived assets or asset group by comparing the carrying value of the long-lived assets or asset group to the estimated undiscounted future cash flows expected to result from the use of the assets or asset group and their eventual disposition, when the estimated undiscounted future cash flows is lower than the carrying value, an impairment loss is recognized in the consolidated statements of operations and comprehensive loss for the difference between the fair value, using the expected future discounted cash flows, and the carrying value of the assets.

 

Oil and gas property, net

 

The Company follows the full-cost method of accounting for the oil and gas property. Under the full-cost method, all productive and non-productive costs incurred in the acquisition, exploration and development associated with properties with proven reserves, under the KSO for Kruh Block, are capitalized. As of December 31, 2023 and 2022, all capitalized costs associated with Kruh’s reserves were subject to amortization. Capitalized costs are subject to a quarterly ceiling test that limits such costs to the aggregate of the present value of estimated future net cash flows of proved reserves, computed using the unweighted arithmetic average of the first-day-of the-month oil and gas prices for each month within the 12-month period prior to the end of reporting period, discounted at 10%, and the lower of cost or fair value of proved properties. If unamortized costs capitalized exceed the ceiling, the excess is charged to expense in the period the excess occurs. There were no cost ceiling write-downs for the years ended December 31, 2023, 2022 and 2021.

 

F-10

 

Depletion for each of the reported periods is computed on the units-of-production method. Depletion base is the total capitalized oil and gas property in the previous period, plus the current period capitalization and future development costs. Furthermore, the depletion rate is calculated as the depletion base divided by the total estimated proved reserves that expected to be extracted during the operatorship. Then, depletion is calculated as the production of the period times the depletion rate.

 

For the years ended December 31, 2023, 2022 and 2021, the estimated proved reserves were considered based on the operatorship of the Kruh Block under the TAC through May 2020 and then the KSO from June 2020 and expiring in September 2035.

 

The costs associated with properties with unproved reserves or under development, such as Production Sharing Contract (“PSC”) Citarum Block, are not initially included in the full-cost depletion base. The costs include but are not limited to unproved property acquisition costs, seismic data and geological and geophysical studies associated with the property. These costs are transferred to the depletion base once the reserve has been determined as proven.

 

Operating Leases

 

The Company adopted Accounting Standards Codification 842 (“ASC 842”) on January 1, 2022 using a modified retrospective approach reflecting the application of the standard to leases existing at, or entered into after, the beginning of the earliest comparative period presented in the consolidated financial statements. The Company elected the package of practical expedients permitted under the transition guidance within ASC 842, which among other things, allows the Company to carry forward certain historical conclusions reached under ASC Topic 840 regarding lease identification, classification, and the accounting treatment of initial direct costs. The Company elected not to record assets and liabilities on its consolidated balance sheet for new or existing lease arrangements with terms of 12 months or less. The Company recognizes lease expenses for such lease on a straight-line basis over the lease term.

 

The most significant impact upon adoption relates to the recognition of new Right-of-use (“ROU”) assets and lease liabilities on the Company’s consolidated balance sheets for office space leases. At the commencement date of a lease, the Company recognizes a lease liability for future fixed lease payments and a right-of-use (“ROU”) asset representing the right to use the underlying asset during the lease term. The lease liability is initially measured as the present value of the future fixed lease payments that will be made over the lease term. The lease term includes periods for which it’s reasonably certain that the renewal options will be exercised and periods for which it’s reasonably certain that the termination options will not be exercised. The future fixed lease payments are discounted using the rate implicit in the lease, if available, or the incremental borrowing rate (“IBR”) on a collateralized basis for a similar term as the underlying lease. The Company will evaluate the carrying value of ROU assets if there are indicators of impairment and review the recoverability of the related asset group. If the carrying value of the asset group is determined to not be recoverable and is in excess of the estimated fair value, the Company will record an impairment loss in other expenses in the consolidated statements of operations.

 

F-11

 

Deferred charges

 

Deferred charges mainly represent the compensation paid for the acquisition of the oil and gas mineral rights to the employer of the block, such as Pertamina or SKK Migas, for information, equipment and services, signature bonus and other fees required by law for the operatorship of a TAC, KSO or PSC. As these payments are made as part of the requirements for the participating in the bidding of the oil and gas operatorship contract, such payments are amortized on a straight-line basis throughout the contract period.

 

Asset retirement obligations

 

The Company measures its obligations for the retirement of the oil fields using various assumptions such as the expected period upon the expiry of the contract and the complete depletion of the oil deposits underground, the degree of the damage the operation had done to the oil field, and the related governmental requirements imposed on the Company as a contractor. The asset retirement obligation is reviewed and adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows and changes required by Pertamina.

 

As of December 31, 2023 and 2022, asset retirement obligations were $352,636 and $448,720, respectively.

 

Provision for post-employment benefit

 

Post-employment benefits are recognized, pursuant to the regulatory requirements under the Indonesia Labor Law Article 167 Law No. 13 of 2003, to capture the amount the Company is obligated to pay, in lump-sum, to the employees hired under the governance of the KSO upon its maturity. Such recognition is reviewed on an annual basis during the period in which the employees provide their services to the Company and is performed through the involvement of an actuary.

 

Actuarial gains or losses are recognized in the other comprehensive income (“OCI”) and excluded permanently from net profit or loss. Expected returns on plan assets are not recognized in net profit or loss. Expected returns are replaced by recognizing interest income (or expense) on the net defined asset (or liability) in net profit or loss, which is calculated using the discount rate used to measure the pension obligation. See note 13 for further information.

 

All past service costs will be recognized at the earlier of when the amendment/curtailment occurs or when the entity recognizes related restructuring or termination costs.

 

Such changes are made in order that the net pension assets or liabilities are recognized in the statement of financial position to reflect the full value of the plan deficit or surplus.

 

Revenue recognition

 

The Company adopted ASC Topic 606, “Revenue from Contracts with Customers” on January 1, 2019, using the modified retrospective method applied to contract that was not completed as of January 1, 2019, the TAC with Pertamina. Under the modified retrospective method, prior period financial positions and results were not adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption.

 

The Company recognizes revenue from the entitlement of Oil and gas property - Kruh Block ECS and profit sharing from the sale of the crude oil under the KSO with Pertamina, when the ECS have been submitted to Pertamina after the monthly ICP has been published by the Government of Indonesia. The only performance obligation of the Company is to deliver the crude oil it produces to Pertamina Jirak Gathering Station (“Pertamina-Jirak”), located approximately 3 miles away from Kruh Block. After the volume and quality of the crude oil delivered is accepted and recorded by Pertamina, Pertamina is responsible for the ultimate sales of the crude to the end-users. The total volume of crude oil sold is confirmed by Pertamina and, combining with the monthly published ICP, the Company calculates the entire amount of its entitlement with Pertamina through the Entitlement Calculation Sheets, at which point revenue is recognized by the end of each month.

 

F-12

 

The revenue was calculated based on the proceeds of the sales of the crude oil produced by the Company and conducted by Pertamina, for TAC with a 65% cap on the proceeds of such sale as part of the cost recovery scheme, on a monthly basis, calculated by multiplying the quantity of crude oil produced by the Company and the prevailing ICP published by the Government of Indonesia. In addition, the Company was also entitled to an additional 26.7857% of the remaining 35% of such sales proceeds as part of the profit sharing. Both of these two portions were recognized as revenue of the Company, net of tax. For KSO with a 80% cap on the proceeds of such sale as part of the cost recovery scheme, on a monthly basis, calculated by multiplying the quantity of crude oil produced by the Company and the prevailing ICP published by the Government of Indonesia plus 100% of the operating cost per bbl multiplying NSO. In addition, the Company is also entitled to an additional 52.7963% of the remaining 20% of such sales proceeds as part of the profit sharing. In the TAC, all oil produced was shareable between Pertamina and the Company, while in the KSO, a NSO production is determined and agreed between Pertamina and the Company so that the baseline production, with an established decline rate, belongs entirely to Pertamina, so that the Company’s revenue and production sharing portion shall be determined only from the production above the NSO baseline.

 

The Company does not have any contract assets (unbilled receivables) since revenue is recognized when control of the crude oil is transferred to the refinery and the payment for the crude oil is not contingent on a future event.

 

There were no contract liabilities as of December 31, 2023 and 2022.

 

Income taxes

 

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

 

Uncertain tax positions

 

The Company follows the guidance of ASC Topic 740 “Income taxes”, which prescribes a more likely than not threshold for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Topic also provides guidance on recognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties associated with tax positions, accounting for income taxes in interim periods, and income tax disclosures. The Company recognizes interest on non-payment of income taxes and penalties associated with tax positions when a tax position does not meet more likely than not thresholds be sustained under examination. The tax returns of the IEC’s subsidiaries are subject to examination by the relevant tax authorities. According to the Directorate General of Tax of the Republic of Indonesia, the statute of limitations is 10 years for the company keeping the documents transaction for tax examination. There is no statute of limitation in the case of tax evasion. The Company recognizes the provisions and any interest and penalties within the income tax expense line item in the accompanying Consolidated Statements of Operations. The accrued provisions and any related interest and penalties are included in the other tax liabilities account.

 

For the years ended December 31, 2023, 2022 and 2021, the Company did not have any material interest or penalties associated with tax positions nor did the Company have any significant unrecognized uncertain tax benefits. The Company does not expect that its assessment regarding unrecognized tax position will materially change over the following 12 months. The Company is not currently under examination by an income tax authority, nor has been notified that an examination is contemplated.

 

Warrant Liabilities

 

The Company accounts for the warrants issued in connection with its convertible note financing (see note 8) in 2022 in accordance with the guidance contained in Accounting Standards Codification (“ASC”) 815-40 Derivatives and Hedging - Contracts in Entity’s Own Equity (“ASC 815”) under which the warrants do not meet the criteria for equity treatment and will be recorded as liabilities. Accordingly at initial recognition, the Company classifies such warrants as liabilities at their fair value. This warrant liability is subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the consolidated statements of operations. Such warrants are valued using the Black-Scholes option-pricing model as no observable traded price was available for such warrants. See note 8 for further information.

 

F-13

 

Fair value of financial instruments

 

The Company records certain of its financial assets and liabilities at fair value on a recurring basis. Fair value is considered to be the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the asset or liability. The established fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels of inputs may be used to measure fair value include:

 

Level

1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.

 

Level

2 applies to assets or liabilities for which there are inputs other than quoted prices included within Level 1 that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.

 

Level

3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.

 

The carrying values of the Company’s financial instruments, including cash, restricted cash, accounts receivable, other current assets, accounts payables, other current liabilities, accrued expenses and tax payables, approximate their fair values due to the short-term nature of these instruments.

 

The following tables present information about the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2023 and 2022, indicate the fair value hierarchy of the valuation techniques that the Company utilized to determine such fair value:

 SCHEDULE OF LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS BY LEVEL WITHIN FAIR VALUE HIERARCHY

Description:		Quoted Prices in Active Markets (Level 1)				Significant other Observable Inputs (Level 2)				Significant other Unobservable Inputs (Level 3)
December 31, 2023
L1 Capital Warrants (See note 8)		$	-			$	-			$	482,219
Provision for post-employment benefits (See note 11)		$	-			$	-			$	118,250

 

Description:		Quoted Prices in Active Markets (Level 1)				Significant other Observable Inputs (Level 2)				Significant other Unobservable Inputs (Level 3)
December 31, 2022
L1 Capital Warrants (See note 8)		$	-			$	-			$	1,389,643
Provision for post-employment benefits (See note 11)		$	-			$	-			$	99,588

 

Segment reporting

 

The Company uses the “management approach” in determining reportable segments. The management approach considers the internal organization and reporting used by the Company’s chief operating decision maker (CODM) for making operating decisions and assessing performance as the source for determining the Company’s reportable segments. The Company’s CODM has been identified as the chief executive officer, who reviews consolidated results when making decisions about allocating resources and assessing performance of the Company.

 

The Company manages its business as a single operating segment engaged in upstream oil and gas industry in Indonesia. Substantially all of its revenues are derived in Indonesia. All long-lived assets are located in Indonesia.

 

Comprehensive loss

 

Comprehensive loss consists of two components, net loss and other comprehensive income. Other comprehensive income refers to revenue, expenses, gains and losses that under U.S. GAAP are recorded as an element of equity but are excluded from net income or loss. Other comprehensive income or loss consists of actuarial gain or loss for post-employment benefits.

 

F-14

 

Commitments and contingencies

 

The Company’s estimated loss contingencies are accrued by a charge to income when information available before financial statements are issued or are available to be issued indicates that it is probable that an asset had been impaired, or a liability had been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Legal expenses associated with the contingency are expensed as incurred. If a loss contingency is not probable or reasonably estimable, disclosure of the loss contingency is made in the financial statements when it is at least reasonably possible that a material loss could be incurred.

 

Net Loss per Ordinary Share

 

Basic net loss per share is determined by dividing net loss attributable to ordinary shareholders by the weighted average number of the Company’s ordinary shares, outstanding during the period, without consideration of potentially dilutive securities, except for those ordinary shares that are issuable for little or no cash consideration. Diluted net loss per share is determined by dividing net loss attributable to ordinary shareholders by diluted weighted average ordinary and dilutive ordinary equivalent shares outstanding. Diluted weighted average shares reflects the dilutive effect, if any, of potentially dilutive ordinary shares, such as stock options and warrants calculated using the “treasury stock” and/or “if converted” methods, as applicable. In periods with reported net operating losses, all potential dilutive securities are generally deemed anti-dilutive such that basic net loss per share and diluted net loss per share are equal.

 

For the year end December 31, 2023, the following potentially dilutive securities were excluded from the computation of diluted earnings per share because their effects would be anti-dilutive:

 SCHEDULE OF ANTI DILUTIVE EARNING PER SHARE

		December 31, 2023				December 31, 2022
Warrants issued to L1 Capital (see note 8)			442,240				442,240
Convertible note issued to L1 Capital (see note 8) (i)			-				16,667
Share options granted to the executive management			200,000				200,000
Total			642,240				658,907
Potentially dilutive securities			642,240				658,907

 

(i)	Convertible note is assumed to be converted at the exercise price of $6.00 per share (subject to adjustment) as disclosed in note 8.

 

Recently adopted accounting standards

 

The Company is an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). Under the JOBS Act, emerging growth companies (“EGCs”) can delay adopting new or revised accounting standards issued subsequent to the enactment of the JOBS Act until such time as those standards apply to private companies.

 

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. The ASU requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. Financial institutions and other organizations will now use forward-looking information to better inform their credit loss estimates. Many of the loss estimation techniques applied today will still be permitted, although the inputs to those techniques will change to reflect the full amount of expected credit losses. Organizations will continue to use judgment to determine which loss estimation method is appropriate for their circumstances. The ASU requires enhanced disclosures to help investors and other financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. These disclosures include qualitative and quantitative requirements that provide additional information about the amounts recorded in the financial statements. In addition, the ASU amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. This ASU has subsequently been amended by ASU 2018-19, ASU 2019-04, ASU 2019-05, ASU 2019-10, ASU 2019-11 and ASU 2020-03. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019, and effective for all other entities for annual and interim periods beginning after December 15, 2022. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. The Company adopted ASU2016-13 from January 1, 2023 and concluded that the adoption of this standard did not have a material impact on its condensed consolidated financial statements.

 

Other accounting pronouncements that have been issued or proposed by the FASB or other standards-setting bodies that do not require adoption until a future date are not expected to have a material impact on the Company’s consolidated financial statements upon adoption.

 

Recently issued accounting standards which have not yet been adopted

 

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Group is still evaluating the effect of the adoption of this guidance.

 

In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which enhances the transparency and decision usefulness of income tax disclosures. The amendments address more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The Company is still evaluating the effect of the adoption of this guidance.

 

On March 6, 2024, the SEC approved a rule that will require registrants to provide certain climate-related information in their registration statements and annual reports. The rule requires information about a registrant’s climate-related risks that are reasonably likely to have a material impact on its business, results of operations, or financial condition. The required information about climate-related risks also includes disclosure of a registrant’s greenhouse gas emissions. In addition, the rules will require registrants to present certain climate-related financial metrics in their audited financial statements. The Group is evaluating the potential impact of this rule on the consolidated financial statements and related disclosures.

 

F-15

 

NOTE 3 – LIQUIDITY AND CAPITAL RESOURCES

 

As reflected in the Company’s consolidated financial statements, the Company has incurred a net loss of $2,634,141, $3,063,349 and $6,052,675 for the years ended December 31, 2023, 2022 and 2021, respectively. During the years ended December 31, 2023, 2022 and 2021, the Company had a negative cash flow from operating activities of $2,978,919, $3,208,138 and $3,548,656, respectively. As of December 31, 2023 and 2022, the Company had accumulated deficits of $39,583,437 and $36,940,753, respectively. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

 

The Company has financed the operations primarily through cash flow from operations, loans from banks, and proceeds from equity instrument financing, where necessary. On March 22, 2024, we filed a New F-3 Registration Statement, which includes a Prospectus Supplement and a base prospectus supplemented by the Prospectus Supplement, covering (i) the offering, issuance and sale by us of up to a maximum aggregate offering price of $50,000,000 of our ordinary shares, preferred shares, warrants, debt securities, rights, depositary shares, and/or units from time to time in one or more offerings, and (ii) up to a maximum aggregate offering price of $4,267,622 of our ordinary shares that may be issued and sold from time to time under the ATM Agreement, as amended by the ATM Amendment No.1 on March 22, 2024, with H.C. Wainwright & Co., LLC as Sales Agent. We are not permitted to sell any ATM Shares prior to the effectiveness of the New F-3 Registration Statement. As of the date of this report, the New F-3 Registration Statement has not been declared effective yet.

 

As of April 23, 2024, the Company had approximately $0.75 million of cash, which is placed with financial institutions and is unrestricted as to withdrawal or use. The Company intends to meet the cash requirements for the next 12 months from the issuance date of the Company’s audited consolidated financial statements. Management’s plan for mitigating the conditions of substantial doubt about the Company’s ability to continue as a going concern includes a combination of improving operational efficiency, debt financing and financial support from the Chief Executive Officer and Chairman of the Board of the Company. The Company will collect the receivables more closely and review the payment schedule in a planned manner, especially for seismic and G&G study. The Company will focus on the completion and full interpretation of seismic operations that will take approximately 12 months, and after which the Company will plan to re-start the continuous new well drilling campaign at Kruh Block in 2026, subject to the availability of funding. There will be no new well drilling activity for the next 12 months till 2026. The Company currently does not have any outstanding short-term or long-term bank borrowings balance. Management expects that it will be able to obtain new bank loans based on past experience and the Company’s good credit history. In addition, Mr. Wirawan Jusuf, the Chief Executive Officer and Chairman of the Board of the Company, has agreed to provide $4 million of financial support in the form of debt to the Company to enable the Company to meet its obligations and commitments as they become due for at least next 12 months from the issuance date of this financial statement for the year ended December 31, 2023.

 

The Company believes that the current cash and anticipated cash flows from operating and financing activities will be sufficient to meet its anticipated working capital requirements and commitments for at least the next 12 months after the issuance of the Company’s accompanying audited consolidated financial statements. Management believes that it is probable that the above plans can be effectively implemented, and it is probable that such plans will mitigate the conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern. The Company has prepared the consolidated financial statements on a going concern basis. If the Company encounters unforeseen circumstances that place constraints on its capital resources, management will be required to take various measures to conserve liquidity. Management cannot provide any assurance that the Company will raise additional capital if needed.

 

NOTE 4 – CASH AND RESTRICTED CASH

 

The following table provides a reconciliation of cash and restricted cash reported within the consolidated balance sheets to the total of such amounts shown in the consolidated statements of cash flows:

 

SCHEDULE OF CASH AND RESTRICTED CASH

		2023				2022
		As of December 31,
		2023				2022
Cash		$	2,009,687			$	5,895,565
Restricted cash - current			1,567,500				-
Restricted cash - non-current			420,000				1,500,000
Total Cash and Restricted cash		$	3,997,187			$	7,395,565

 

As of December 31, 2023 and 2022, the restricted cash related to (i) cash held in a special account as extended Guarantee for the performance commitment for Kruh Block with amount of $487,500 and nil respectively, (ii) cash held in a time deposit account at Bank Mandiri’s Jakarta Cut Meutia Branch with amount equal to $1,500,000 and $1,500,000, respectively, used as collateral for the issuance of a bank guarantee related to the implementation of the Company’s contractual commitments for Citarum Block until July 2024.

 

F-16

 

NOTE 5 – PREPAYMENT AND OTHER ASSETS 

 

SCHEDULE OF OTHER ASSETS

		2023				2022
		As of December 31,
		2023				2022
Prepaid VAT taxes		$	1,442,517			$	1,176,771
Other receivables			307,700				186,840
Consumables and spare parts			148,376				121,740
Prepaid expenses			21,983				18,750
Prepayment and other current assets		$	1,920,576			$	1,504,101
Other receivable from well equipment		$	609,604			$	635,052
Deposit and others			134,836				268,666
Durable spare parts			128,107				114,528
Other non-current assets			872,547				1,018,246
Less: allowance on doubtful receivables			(59,604	)			-
Other non-current assets, net		$	812,943			$	1,018,246

 

For the year ended December 31, 2023, the Company sold a rig equipment to a third party. As of the date of this filing, there is an outstanding balance of $609,604, which is expected to be received in 2025. Considering the potential risk of default, the Company recorded $59,604 allowance for the doubtful account.

 

NOTE 6 – OIL AND GAS PROPERTY, NET

 

The following tables summarize the Company’s oil and gas property by classification.

 SCHEDULE OF OIL AND GAS ACTIVITIES

		2023				2022
		As of December 31,
		2023				2022
Oil and gas property – subject to amortization		$	28,035,019			$	28,740,479
Accumulated depletion			(9,064,212	)			(9,411,476	)
Accumulated impairment			(11,859,183	)			(11,859,183	)
Oil and gas property – subject to amortization, net		$	7,111,624			$	7,469,820
Oil and gas property – not subject to amortization		$	1,155,439			$	1,151,804
Accumulated impairment			-				-
Oil and gas property – not subject to amortization, net		$	1,155,439			$	1,151,804

 

F-17

 

The following shows the movement of the oil and gas property – subject to amortization balance.

 SCHEDULE OF MOVEMENT OF THE OIL AND GAS PROPERTY

		Oil and Gas Property – Kruh Block
December 31, 2020		$	1,338,987
Additional capitalization			2,916,102
Depletion			(650,609	)
December 31, 2021		$	3,604,480
Additional capitalization			4,723,463
Asset retirement costs			188,873
Depletion			(1,046,996	)
December 31, 2022		$	7,469,820
Additional capitalization			294,540
Asset retirement costs			(42,998	)
Depletion			(609,738	)
December 31, 2023		$	7,111,624

 

During the years ended December 31, 2023, 2022 and 2021 the Company incurred an aggregated development costs and abandonment and site restoration provisions, which were capitalized, at $294,540, $4,723,463 and $2,916,102 respectively, mainly for the purpose of the geological and geophysical studies and drilling of wells.

 

Depletion recorded for production on properties subject to amortization for the years ended December 31, 2023, 2022 and 2021 were $609,738, $1,046,996 and $650,609 respectively.

 

Furthermore, for the years ended December 31, 2023 and 2022, the Company has conducted ceiling test to which the present value of the estimated future net revenues generated by the oil and gas property - Kruh Block Proven exceed the carrying balances. As a result, no impairment was recognized.

 

NOTE 7 – PROPERTY AND EQUIPMENT, NET

 SCHEDULE OF PROPERTY AND EQUIPMENT, NET

		2023				2022
		As of December 31,
		2023				2022
Drilling and production tools		$	1,499,535			$	1,499,535
Leasehold improvement			323,675				323,675
Production facilities			93,049				93,049
Computer and software			5,605				5,605
Housing and welfare			4,312				4,312
Furniture and office equipment			4,013				4,013
Equipment			1,650				1,650
Total			1,931,839				1,931,839
Property, plant and equipment, gross			1,931,839				1,931,839
Less: accumulated depreciation			(1,822,822	)			(1,730,344	)
Property and equipment, net		$	109,017			$	201,495

 

Depreciation charged to expense amounted to $92,478, $92,727 and $160,246 for the years ended December 31, 2023, 2022 and 2021, respectively.

 

F-18

 

NOTE 8 – FINANCIAL LIABILITY

 

SCHEDULE OF FINANCIAL LIABILITY

		December 31, 2023				December 31, 2022
Convertible note payable, net of debt issuance costs		$	-			$	52,143
Warrant liabilities, net of debt issuance costs		$	482,219			$	1,389,643

 

On January 21, 2022 (the “Initial Closing Date”), the Company closed an initial $5,000,000 tranche (the “First Tranche”) of a total then anticipated $7,000,000 private placement with L1 Capital pursuant to the terms of a Securities Purchase Agreement, dated January 21, 2022, between the Company and L1 Capital (the “Purchase Agreement”). In connection with the closing of the First Tranche, the Company issued to the L1 Capital (i) a 6% Original Issuance Discount Senior Convertible Note in a principal amount of up to $7,000,000.00 (the “Note”) and (ii) a five-year Ordinary Share Purchase Warrant (the “Initial Warrant”) to purchase up to 383,620 ordinary shares at an exercise price of $6.00 per share, subject to adjustment. As of the date of the original Purchase Agreement, a second tranche (the “Second Tranche”) of funding under the Note in the amount of $2,000,000 (the “Second Tranche Amount”) was contemplated. The Note was subject to a deduction of a 6.0% original issuance discount. Except as upon an Event of Default (as defined in the Note), the Note did not bear interest.

 

Beginning 120 days after the Initial Closing Date, the Company was required to commence monthly installment payments of the Note through maturity (or 14 payments) (“Monthly Payments”), which Monthly Payments could be made, at the Company’s election, in cash or ordinary shares (or a combination of cash and ordinary shares), with such ordinary shares being issued at a valuation equal to the lesser of: (i) $6.00 per share or (ii) 90% of the average of the two lowest closing bid prices of the ordinary shares for the ten (10) consecutive trading days ending on the trading day immediately prior to the payment date, with a floor price of $1.20 per share. In addition, at any time following the date of effectiveness of a Registration Statement covering the applicable ordinary shares underlying the Note (such Registration Statement having been declared effective on June 1, 2022), the Note is convertible (in whole or in part), at the option of L1 Capital, into such number of fully paid and non-assessable ordinary shares determined by dividing (x) that portion of the outstanding principal amount of the Note that L1 Capital elects to convert by (y) $6.00 per share, which price was subject to adjustment as provided in the Note. Upon the occurrence of any Event of Default that has not been remedied, the Company would be obligated to pay to L1 Capital an amount equal to one hundred twenty percent (120%) of the outstanding principal amount of the Amended Note on the date on which the first Event of Default has occurred.

 

On March 4, 2022, the Company and L1 Capital entered into a First Amendment to the Purchase Agreement and an Amended and Restated Senior Convertible Promissory Note (the “Amended Note”) pursuant to which, among other items, Second Tranche Amount was increased from $2,000,000 to $5,000,000. Upon the funding of the Second Tranche Amount, L1 Capital was entitled to receive an additional five-year Ordinary Share Purchase Warrant (the “Second Warrant”) to purchase up to 383,620 ordinary shares at $6.00 per share (subject to adjustment).

 

On May 16, 2022, the Company executed and delivered to L1 Capital a Second Amended and Restated Senior Convertible Promissory Note which amends and restates the Amended Note in its entirety (the “Second Amended Note” and collectively with the Note and the Amended Note, the “Notes”). Among other matters, the Second Amended Note provided for an accelerated funding of the Second Tranche Amount, which was funded to the Company on May 23, 2022, at which time the Second Warrant was issued to L1 Capital.

 

Accounting for convertible notes

 

Adoption of ASU 2020-06

 

In August 2020, the FASB issued ASU No. 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). The update removes separation models for (i) convertible debt with a cash conversion feature and (ii) convertible instruments with a beneficial conversion feature. Under ASU 2020-06, these features will be combined with the host contract. ASU 2020-06 does not impact the accounting treatment for conversion features that are accounted for as a derivative under Topic 815. The update also requires the application of the if-converted method to be used for convertible instruments and the effect of potential share settlement be included in the diluted earnings per share calculation when an instrument may be settled in cash or shares. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. The amendment is to be adopted through either a fully retrospective or modified retrospective method of transition, only at the beginning of an entity’s fiscal year. Early adoption is permitted. The Company has elected to adopt the standard as of January 1, 2022.

 

F-19

 

The Company evaluated the terms of its Notes with L1 Capital and concluded that the instrument does not require separation and that there were no other derivatives that required separation. The Company evaluated the embedded features of the Notes in accordance with ASC 815-15-25 and determined that the most significant feature is the equity-like conversion option, which is not clearly and closely related to the debt host instrument. The Company further determined it would not meet the definition of a derivative, and therefore not required to be bifurcated and separately measured at fair value. As a result, there is no equity component, and the Company recorded the Notes as a single liability within long-term debt on the accompanying consolidated balance sheet.

 

The Initial Warrant and the Second Warrant (collectively, the “Warrants”) were issued in connection with the Notes, and exercise of such Warrants are not contingent upon conversion of the Notes; therefore, proceeds were allocated first to the Warrants based on their fair value and the residual were allocated to the Notes.

 

The Company incurred debt issuance costs associated with the Notes in the amount of $811,000, which are allocated to the Warrants based on assessed fair value of Warrants and residual proceeds allocated to Notes, compared to total proceeds received. Debt issuance costs associated with derivative warrant liabilities are expensed as incurred, presented as other expenses in the consolidated statements of operations. Offering costs associated with the Notes were charged as a direct deduction from the principal amount of the Notes. Debt issuance and offering costs are recorded as debt discount, which is amortized as interest expense over the term of the convertible debt instrument using the effective interest method.

 

With regards to the Second Tranche, due to the relatively high closing price of the ordinary shares on May 23, 2022 (the date of issuance of the Second Warrant), the fair value of Second Warrant of $4,833,325 exceeds the net proceeds received (see below for details on accounting for warrants). $133,325 of insurance loss was recognized and no residual proceeds were allocated to Notes. For the year end December 31, 2022, the total proceeds from both tranches of the Notes have supported oil well drilling of the K-27 and K-28 wells and working capital general corporate purposes.

 

During the year ended December 31, 2022, $9,900,000 of the total $10,000,000 principal amount of the Notes has been converted into ordinary shares at $6.00 per share at L1 Capital’s election. On July 21, 2023, the Company repaid the remaining $100,000 principal amount of the Notes to L1 Capital in cash. As of December 31, 2023, the carrying value balance of the convertible note was $0.

 

 SCHEDULE OF CONVERTIBLE DEBT

Convertible note		First Tranche				Second Tranche				Total
Initial recognition		$	3,438,933			$	-			$	3,438,933
Amortization of insurance cost			358,155				288,095			$	646,250
Conversion to ordinary shares			(3,797,088	)			(235,952	)			(4,033,040	)
Balance as of December 31, 2022		$	-			$	52,143			$	52,143
Convertible note, beginning balance		$	-			$	52,143			$	52,143
Amortization of insurance cost			-				47,857				47,857
Repayment			-				(100,000	)			(100,000	)
Balance as of December 31, 2023		$	-			$	-			$	-
Convertible note, ending balance		$	-			$	-			$	-

 

Accounting for warrants

 

The Warrants were issued in conjunction with the convertible note by a separate contract, and legally detachable and separately transferrable. The Warrants were exercisable via “cashless” exercise if there is not an effective registration statement covering resale of the ordinary share under the Warrants. The exercise price per ordinary share under the Warrants was $6.00 and subject to certain adjustments which do not meet the criteria for equity treatment in accordance with the guidance contained in ASC 815-40-15-7E. Accordingly at initial recognition, the Company classifies such warrants as liabilities at their fair value. This warrant liability is subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the consolidated statements of operations.

 

The Company recognized $915,644 for warrant liabilities upon issuance of the Initial Warrant on January 24, 2022. The Company recognized $4,833,325 for warrant liabilities upon issuance of the Second Warrant on May 23, 2022.

 

The Company utilizes the Black-Scholes option-pricing model to estimate the fair value of the Warrants at each reporting period since the Warrants are not actively traded. The estimated fair value of the Warrant liabilities is determined using Level 3 inputs in accordance with ASC 820, “Fair Value Measurement”. Inherent in the Black-Scholes model are assumptions related to expected stock-price volatility, expected life, risk-free interest rate and dividend yield. The Company estimates the volatility of its ordinary shares based on historical volatility of select peer companies that matches the expected remaining life of the Warrants. The risk-free interest rate is based on the U.S. Treasury zero-coupon yield curve on the grant date for a maturity similar to the expected remaining life of the Warrants. The expected life of the Warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which the Company anticipates remaining at zero.

 

F-20

 

The following reflects the inputs and assumptions used:

 

 SCHEDULE OF WARRANTS VALUATION ASSUMPTIONS

		January 24, 2022				May 23, 2022				December 31, 2022				December 31, 2023
Exercise price		$	6.00			$	6.00			$	6.00			$	6.00
Share price		$	3.64			$	14.94			$	4.66			$	2.71
Expected term from grant date (in years)			5.00				5.00				4.10 for Initial Warrant and 4.50 for Second Warrant				3.10 for Initial Warrant and 3.40 for Second Warrant
Expected volatility			96.32	%			95.90	%			96.03	%			82.40	%
Risk-free interest rate			1.53	%			2.88	%			3.99	%			4.01	%
Dividend yield (per share)			-				-				-				-
Warrants valuation assumptions			-				-				-				-

 

During the year ended December 31, 2022, L1 Capital has exercised 325,000 of the Initial Warrant at $6.00 per share while the Company has received $1,950,000 proceeds from exercise of these warrants. As of December 31, 2023, there were 442,240 warrants issued and outstanding.

 

The movement of warrant liabilities is summarized as follows:

 

 SCHEDULE OF WARRANT LIABILITIES

Balance as of January 1, 2022		$	-
Issuance of Initial Warrant as of January 24, 2022			915,644
Issuance of Second Warrant as of May 23, 2022			4,833,325
Issuance of Warrant			4,833,325
50,000 warrant shares exercised on June 16, 2022			(119,343	)
185,000 warrant shares exercised on August 18, 2022			(915,799	)
90,000 warrant shares exercised on August 29, 2022			(445,524	)
Warrant shares exercised			(445,524	)
Change in fair value of warrant liabilities for the year			(2,878,660	)
Balance as of December 31, 2022			1,389,643
Warrant liabilities, beginning balance			1,389,643
Change in fair value of warrant liabilities for the year			(907,424	)
Balance as of December 31, 2023		$	482,219
Warrant liabilities, ending balance		$	482,219

 

NOTE 9 – OPERATING LEASES

 

The Company accounts for leases in accordance with ASC Topic 842, Leases (“ASC 842”). All contracts are evaluated to determine whether or not they represent a lease. A lease conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company has operating leases primarily consisting of facilities with remaining lease terms of one year to three years. The lease term represents the period up to the early termination date unless it is reasonably certain that the Company will not exercise the early termination option.

 

Leases are classified as finance or operating in accordance with the guidance in ASC 842. The Company does not hold any finance leases as of December 31, 2023 and 2022.

 

The Company also has certain leases related to equipment and tools. A short-term lease is a lease with a term of 12 months or less and does not include the option to purchase the underlying asset that we would expect to exercise. The Company has elected to adopt the short-term lease exemption in ASC 842 and as such has not recognized a “right of use” asset or lease liability for these short-term leases.

 

The Company’s lease agreements generally do not provide an implicit borrowing rate, therefore 3-year Indonesia government bond yield to maturity was used for the year ended December 31, 2022 for purposes of determining the present value of lease payments. As of December 31, 2023, the Company used the 3-year tenure secured borrowing rate at 10% per year from Bank UOB (Indonesia) as incremental borrowing rate.

 

F-21

 

The components of lease expense were as follows for each of the periods presented:

 

 SCHEDULE OF LEASE EXPENSE

		December 31, 2023				December 31, 2022
Operating lease expense		$	472,777				353,997
Short-term lease expense			939,500				1,061,609
Total operating lease costs			1,412,277				1,415,606
Other information
Operating cash flows used in operating leases			373,680				323,099
Weighted average remaining lease term (in years)			2.00				1.38
Weighted average discount rate			10	%			5.612	%

 

Future lease payments included in the measurement of operating lease liabilities as of December 31, 2023 is as follows:

 

 SCHEDULE OF OPERATING FUTURE LEASE PAYMENTS

		December 31, 2023
2024		$	662,492
2025			422,683
2026			131,224
Total			1,216,399
Less: discount on operating lease liabilities			(119,231	)
Present value of operating lease liabilities			1,097,168
Less: Current portion of operating lease liabilities			(629,325	)
Non-current portion of operating lease liabilities			467,843

 

NOTE 10 – TAXES

 

The Company and its subsidiaries file tax returns separately.

 

1) Value added tax (“VAT”)

 

The Company’s subsidiaries’ activities and revenues are not subject to VAT. VAT is typically due on events involving the transfer of taxable goods or the provision of taxable services in Indonesia, except for some goods and services, such as mining or drilling products extracted directly from their sources, for example crude oil, natural gas and geothermal energy.

 

Nevertheless, the Company’s subsidiaries are classified as VAT Collectors. As the name implies, VAT Collector is required to collect the VAT due from a taxable enterprise (vendor) on the delivery to it of taxable goods or services and to pass the VAT payment directly to the government, rather than to the vendor or the service provider. The VAT Collectors are currently the State Treasury, State Owned Enterprises (Badan Usaha Milik Negara/BUMN) and some of their subsidiaries, and PSC companies such as the Company’s. This means that, although the Company is not subject to VAT, the Company has the obligation to collect the VAT and pay the VAT on behalf of the Company’s vendors to the Indonesian government.

 

2) Income tax

 

Cayman Islands

 

The Company is incorporated in the Cayman Islands. Under the current laws of the Cayman Islands, the Company is not subject to income or capital gains taxes. In addition, dividend payments are not subject to withholdings tax in the Cayman Islands.

 

F-22

 

Hong Kong

 

The Company’s subsidiary WJ Energy is subject to an income tax rate of 16.5% for taxable income earned in Hong Kong. Hong Kong registered companies are exempt from Hong Kong income tax on their foreign derived income.

 

Indonesia

 

The Company’s subsidiaries incorporated in Indonesia are subject to Indonesia Corporate Income Tax (“CIT”) law. Pursuant to the Indonesia CIT law, given the specific year (2020) in which the KSO was signed, GWN’s KSO operations are subject to a CIT rate of 25%. Unless GWN fully recovers its expenditures, the GWN’s KSO operations are effectively exempted from the application of the CIT. Upon the expiry of the KSO, any unrecovered portion of the Kruh Block oil and gas investment will be deemed as waived by the Company and will not be available for tax deduction purposes for any future earnings. As of December 31, 2023 and 2022, the unrecovered expenditures on KSO operations are $6,521,865 and $6,700,186, respectively.

 

Pursuant to the Indonesia CIT law, standard CIT rate was adjusted from 25% to 22%. Other Indonesia subsidiaries are subject to a flat standard CIT rate of 22%, on which these subsidiaries would not be eligible for 50% tax discount anymore and therefore should use the standard CIT rate from 2021 onwards.

 

The components of the income tax provision are:

 

SCHEDULE OF COMPONENTS OF INCOME TAX PROVISION

			2023				2022				2021
			Years Ended December 31,
			2023				2022				2021
Current		$	-			$	-			$	-
Deferred			-				-				-
Total income tax provision		$	-			$	-			$	-

 

The loss before provision for income taxes is attributable to the following geographic locations for the years ended December 31:

 SCHEDULE OF PROVISION FOR INCOME TAXES

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
Indonesia		$	(1,060,197	)		$	(1,220,088	)		$	(3,724,160	)
Foreign			(1,582,487	)			(1,902,504	)			(2,359,219	)
Total loss before income taxes		$	(2,642,684	)		$	(3,122,592	)		$	(6,083,379	)

 

F-23

 

The reconciliation of income taxes provision computed at the statutory tax rate applicable to income tax provision are as follows: 

 

SCHEDULE OF RECONCILIATION OF INCOME TAXES PROVISION

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
Loss before income tax		$	(2,642,684	)		$	(3,122,592	)		$	(6,083,379	)
Computed income tax benefit with statutory income tax rate			(581,391	)			(686,970	)			(1,338,343	)
Effect of different tax rates in other jurisdictions			306,694				418,276				518,955
Effect of different tax rates for the KSO operations			(26,433	)			(26,458	)			(100,210	)
Effect of tax exemption for unrecovered expenditures on KSO operations			220,274				220,486				835,085
Current year true up			-				-				-
Effect of tax rates adjustment			-				-				(48,370	)
Change in valuation allowance			80,856				74,666				132,883
Total income tax provision		$	-			$	-			$	-

 

The components of the deferred tax assets and deferred tax liabilities are as follows:

 

SCHEDULE OF COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES

		2023				2022
		As of December 31,
		2023				2022
Deferred tax assets
Tax loss carry forwards		$	356,735			$	290,752
Operating lease liabilities			274,292				87,862
Total deferred tax assets, gross			631,027				378,614
Deferred tax liabilities
Operating lease right-of-use assets			(274,292	)			(87,862	)
Total deferred tax liabilities			(274,292	)			(87,862	)
Deferred tax assets, net			356,735				290,752
Less: valuation allowance			(356,735	)			(290,752	)
Total deferred tax assets, net		$	274,292			$	87,862

 

The Company considers positive and negative evidence to determine whether some portion or all of the deferred tax assets will more likely than not be realized. This assessment considers, among other matters, the nature, frequency and severity of recent losses, forecasts of future profitability, the duration of statutory carry forward periods, the Company’s experience with tax attributes expiring unused and tax planning alternatives. Valuation allowances have been established for deferred tax assets based on a more-likely-than-not threshold. The Company’s ability to realize deferred tax assets depends on its ability to generate sufficient taxable income within the carry forward periods provided for in the tax law. As of December 31, 2023 and 2022, the Company had tax operating loss carry forwards of $371,872 and $120,640, respectively from its subsidiary in Hong Kong and $1,342,618 and $1,231,123, respectively from its subsidiaries in Indonesia, which can be carried forward to offset taxable income. The net operating loss will be carried forward indefinitely under Hong Kong Tax regulations, while the net operating loss began to expire in year 2023 if not utilized under Indonesian Tax regulations. As of December 31, 2023 and 2022, the Company had a valuation allowance against deferred tax assets on tax loss carry forward of $356,735 and $290,752, respectively. The change in valuation allowance of $65,982 was due to current additions of $80,856 offset by foreign exchange differences of $14,874.

 

F-24

 

NOTE 11 – PROVISION FOR POST-EMPLOYMENT BENEFITS

 

Provision for post-employment benefits consists of the following:

 SCHEDULE OF PROVISION FOR POST- EMPLOYMENT BENEFITS

		As of December 31,
		2023				2022
Provision for post-employment benefits		$	118,250			$	99,588

 

The provision for post-employment benefits is recognized in the period in which the benefit is earned by the employee, rather than when it is paid or payable.

 

The following outlines how each category of employee benefits is measured, providing reconciliation on present value of Defined Benefit Obligation and Plan Asset.

 

 SCHEDULE OF RECONCILIATION ON PRESENT VALUE OF DEFINED BENEFIT OBLIGATION AND PLAN ASSETS

		As of December 31,
		2023				2022
Present Value of Defined Benefit Obligation (“DBO”) and Fair Value of Plan Assets
Present Value of DBO, at the Beginning of Year		$	99,588			$	115,393
Current service cost			27,737				36,824
Interest cost on the DBO			6,191				6,615
Past Service Cost-Vested			(6,723	)			-
Employee benefits are already noted for quit employees			-				-
Present Value of DBO, (expected) at the End of Year			126,793				158,832
Actuarial gain on DBO			(8,543	)			(59,244	)
Present Value of DBO, (actual) at the End of Year		$	118,250			$	99,588
The effect of asset ceiling			-				-
Provision for post-employment benefits		$	118,250			$	99,588

 

The following are key information for the recalculation of employee benefits obligations as of December 31, 2023 and 2022:

 SCHEDULE OF KEY INFORMATION FOR THE RECALCULATION OF EMPLOYEE BENEFITS OBLIGATION

		2023				2022
		As of December 31,
		2023				2022
Liabilities at the Beginning of Year		$	99,588			$	115,393
Post-employment benefits costs			27,205				43,439
Actuarial gain on liabilities			(8,543	)			(59,244	)
Liabilities at the End of Year		$	118,250			$	99,588

 

F-25

 

The Company recorded actuarial gains of $8,543, $59,244 and $30,704 for the years ended December 31, 2023, 2022 and 2021, respectively.

 

The Company realized no actuarial gain for the years ended December 31, 2023, 2022 and 2021.

 

The following table summarizes the quantitative information about the Company’s level 3 fair value measurements in the determination of the balance of the post-employment benefits, which utilize significant unobservable inputs:

 SCHEDULE OF QUANTITATIVE INFORMATION ABOUT FAIR VALUE MEASUREMENTS OF POST EMPLOYMENT BENEFITS

Actuarial Assumption		December 31, 2023				December 31, 2022
Discount Rate			6.77% and 6.25	%			6.77% and 5.17	%
Expected Return on Plan Assets			N/A				N/A
Wage Increase Rate			7.00	%			7.00	%
Mortality Rate			Table Mortality Index (“TMI”) of Indonesia, TMI IV 2019				Table Mortality Index (“TMI”) of Indonesia, TMI IV 2019
Disability Rate			5% of TMI IV 2019				5% of TMI IV 2019
Normal retirement age			58 Years (All employees are assumed to retire at pension age). With work contract until May 22, 2030				58 Years (All employees are assumed to retire at pension age). With work contract until May 22, 2030

 

Withdrawal Rate		Age				Rate				Age				Rate
			20 – 29				6.0	%			20 – 29				6.0	%
			30 – 39				5.0	%			30 – 39				5.0	%
			40 – 44				3.0	%			40 – 44				3.0	%
			45 – 49				2.0	%			45 – 49				2.0	%
			50 – 57				1.0	%			50 – 57				1.0	%
			>57				0.0	%			>57				0.0	%

 

F-26

 

NOTE 12 – SHARE BASED COMPENSATION EXPENSES

 

Share options

 

a) Description of share option plans

 

On October 31, 2018, the Company’s board of directors and shareholders adopted a 2018 Omnibus Equity Incentive Plan for the Company.

 

On February 1, 2019, the Company entered into share option agreements, an Incentive Share Option (“Option”) to purchase ordinary shares of the Company, with the senior management team of the Company, as part of the Company’s equity incentive plan, granting options to purchase a total number of 1,700,000 ordinary shares of the Company. The option shares were distributed to the President, Chief Executive Officer, Chief Operating Officer, Chief Business Development Officer and Chief Investment Officer of the Company, with the exercise price per share equal to the price per ordinary share paid by public investors in the Company’s registered IPO.

 

In connection with the Reverse Stock Split, the total number of share options granted on February 1, 2019, decreased from 1,700,000 to 637,500.

 

On December 19, 2019, associated with the Company’s registered IPO, a mutual understanding between the Company and the executive management, about the nature of the compensatory and equity relationships established by the Option award were established. 637,500 share options were granted to the executive management with an exercise price of $11.00.

 

b) Valuation assumptions

 

The estimated fair value of each share option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

 

SCHEDULE OF BLACK SCHOLES STOCK OPTION PRICING VALUATION ASSUMPTIONS

		Date of grant
Expected volatility			96.49% - 99.62	%
Risk-free interest rate			1.79	%
Expected term from grant date (in years)			3.50-6.00
Dividend rate			-
Dilution factor			0.9203
Fair value			$7.01-$8.26

 

The expected volatility at each grant date was estimated based on the annualized standard deviation of the daily return embedded in historical share prices of comparable peer companies with a time horizon close to the expected expiry of the term of the share options. The weighted average volatility is the expected volatility at the grant date weighted by the number of share options. The Company has never declared or paid any cash dividends on its capital stock, and the Company does not anticipate any dividend payments in the foreseeable future. The contractual term is the remaining contract life of the share options. The Company estimated the risk-free interest rate based on the yield to maturity of U.S. treasury bonds denominated in US dollars at the share option grant date.

 

c) Share options activities

 

SCHEDULE OF SHARE OPTIONS ACTIVITIES

		Options Outstanding				Weighted Average Exercise Price				Weighted Average Remaining Contractual Life				Aggregate Intrinsic Value
										(In years)
Outstanding as of January 1, 2020			-				-				-				-
Granted			637,500			$	11.00				8.80				-
Exercised			-				-				-				-
Forfeited			-				-				-				-
Outstanding as of December 31, 2020			637,500			$	11.00				7.80				-
Granted			-				-				-				-
Exercised			-				-				-				-
Forfeited			-				-				-				-
Outstanding as of December 31, 2021			637,500			$	11.00				6.80				-
Granted			-				-				-				-
Exercised			(437,500	)			-				-				-
Forfeited			-				-				-				-
Vested as of December 31, 2022			200,000			$	11.00				5.80				-
Outstanding as of December 31, 2022			200,000			$	11.00				5.80				-
Granted			-				-				-				-
Exercised			-				-				-				-
Forfeited			-				-				-				-
Outstanding as of December 31, 2023			200,000			$	11.00				4.80				-

 

F-27

 

On March 3, 2022, certain of the Company’s executive officers exercised 437,500 vested options to purchase restricted ordinary shares on a “net share settlement” basis. 199,259 shares were issued upon exercise.

 

For the years ended December 31, 2023, 2022 and 2021, share-based compensation expenses recognized associated with share options granted by the Company were nil, $526,496, and $1,288,583, respectively. As of December 31, 2023 and 2022, there no unrecognized share-based compensation related to the share options granted to the Company’s executive management.

 

Restricted shares

 

On April 15, 2020, the Company issued 31,818 ordinary shares to ARC Group Ltd. as a compensation for the advisory services provided in connection with the Company’s initial public offering, the fair market value of the shares was $3.51 on the issuance date; On the same date, the Company also issued 12,500 ordinary shares to TraDitigal Marketing Group, Inc. as a compensation for the marketing services provided in connection with the Company’s initial public offering, the fair market value of the shares was also $3.51.

 

On September 7, 2021, the Company issued 35,000 ordinary shares to Frank C. Ingriselli, the President of the Company, as a compensation as per his Employment contract, the fair market value of the shares was $4.96 on the issuance date; On September 15, 2021, the Company also issued 5,000 ordinary shares to TraDigital Marketing Group, Inc. as a compensation for the digital marketing services provided in order to enhance investor awareness, the fair market value of the shares on the issuance date was $5.01.

 

On January 1, 2022, the Company issued 60,000 of the Company’s restricted ordinary shares to Frank C. Ingriselli, the Company’s President, pursuant to his employment agreement with the Company, with 30,000 shares vesting on July 1, 2022 and 30,000 shares vesting on January 1, 2023. Such ordinary shares were valued at $2.85 per share, which was based on the closing price of the shares traded on the NYSE American exchange on January 3, 2022.

 

On April 28, 2022, the Company issued 2,105 ordinary shares to Srax, Inc. as compensation for the advisory services provided in connection with the Company’s investor relations efforts. Such ordinary shares were valued at $19.00 per share, which was based on the closing price of the shares traded on the NYSE American exchange on April 28, 2022.

 

The Company has recorded compensation of employee and non-employee services associated with above issuance of ordinary shares of nil, $210,773 and $225,776 for the years ended December 31, 2023, 2022 and 2021, respectively.

 

NOTE 13 – EQUITY

 

The Company was established under the laws of the Cayman Islands on April 24, 2018 and IEC issued 1,000 ordinary shares to Maderic. The authorized number of ordinary shares was 100,000,000 shares with par value of US$0.001 each upon establishment.

 

On June 30, 2018, the Company entered into two agreements with Maderic and HFO (the two then shareholders of WJ Energy): a Sale and Purchase of Shares and Receivables Agreement and a Debt Conversion Agreement (collectively, the “Restructuring Agreements”). The intention of the Restructuring Agreements was to restructure the Company’s capitalization. As a result of the transactions contemplated by the Restructuring Agreements: (i) WJ Energy (including its assets and liabilities) became a wholly-owned subsidiary of the Company, (ii) loans amounting to $21,150,000 and $3,150,000 that were owed by WJ Energy to Maderic and HFO, respectively, were converted for nominal value into ordinary shares of the Company and (iii) the Company issued an aggregate of 15,999,000 ordinary shares to Maderic and HFO. The above-mentioned transaction is accounted for as a nominal share issuance (the “Nominal Share Issuance”).

 

On November 8, 2019, the Company implemented a one-for-zero point three seven five (1 for 0.375) stock split of the Company’s ordinary shares by way of share consolidation under Cayman Islands law (the “Reverse Stock Split”), which in turn decreased the total of 16,000,000 issued and outstanding ordinary shares to a total of 6,000,000 issued and outstanding ordinary shares for the purpose of achieving a certain share price as part of certain listing requirements of the NYSE American. Any fractional ordinary share that would have otherwise resulted from the Reverse Stock Split was rounded up to the nearest full share. The Reverse Stock Split maintained the shareholders’ percentage ownership interests in the Company at 87.04% owned by Maderic (5,222,222 ordinary shares) and 12.96% owned by HFO (777,778 ordinary shares), out of a total of 6,000,000 issued ordinary shares. The Reverse Stock Split also increased the par value of the ordinary shares from $0.001 to $0.00267 and decreased the number of authorized ordinary shares of the Company from 100,000,000 to 37,500,000 and authorized preferred shares from 10,000,000 to 3,750,000. The Reverse Stock Split did not alter the total dollar amount of the ordinary shares of the Company. All number of shares and per share data presented in the consolidated financial statements and related notes have been retroactively restated to reflect the Reverse Stock Split stated above.

 

On December 19, 2019, the Company listed its ordinary shares on the NYSE American in the IPO. As a result, the Company issued a total of 1,363,637 ordinary shares at a price to the public of $11.00 per share in connection with its IPO and received net proceeds of approximately US$12.5 million, after deducting underwriting discounts and the offering expenses. Upon the completion of the IPO, the Company had a total of 7,363,637 ordinary shares.

 

On April 15, 2020, the Company issued 31,818 ordinary shares to ARC Group Ltd. as a compensation for the advisory services provided in connection with the Company’s initial public offering; On the same date, the Company also issued 12,500 ordinary shares to TraDigital Marketing Group, Inc. as a compensation for the digital marketing services provided in order to enhance investor awareness.

 

F-28

 

On September 7, 2021, the Company issued 35,000 ordinary shares to Frank C. Ingriselli, the President of the Company, as a compensation as per his employment contract.

 

On September 15, 2021, the Company issued 5,000 ordinary shares to TraDigital Marketing Group, Inc. as a compensation for the digital marketing services provided in order to enhance investor awareness.

 

On January 1, 2022, the Company issued 60,000 of the Company’s restricted ordinary shares to Frank C. Ingriselli, the Company’s President, pursuant to his employment agreement with the Company, with 30,000 shares vesting on July 1, 2022 and 30,000 shares vesting on January 1, 2023.

 

On March 3, 2022, certain of the Company’s executive officers exercised vested options to purchase restricted ordinary shares on a “net share settlement” basis. 199,259 shares were issued upon exercise.

 

On April 28, 2022, the Company issued 2,105 ordinary shares to Srax, Inc. as compensation for the advisory services provided in connection with the Company’s investor relations efforts.

 

From June 2, 2022 to June 9, 2022, L1 Capital elected to convert an aggregate of $9,600,000 principal amount of the Notes into ordinary shares at $6.00 per share. On August 18, 2022, L1 Capital elected to further convert $300,000 principal amount of the Notes into ordinary shares at $6 per share. In total, 1,650,000 ordinary shares were issued upon convertible note conversion.

 

On June 16, 2022, L1 Capital exercised 50,000 Warrants to purchase 50,000 ordinary shares at $6.00 per share.

 

On the same day, L1 Capital exercised 185,000 warrants to purchase a like number of ordinary shares at a price of $6.00 per share for proceeds to the Company of $1,110,000. On August 29, 2022, L1 Capital exercised an additional 90,000 warrants to purchase a like number of ordinary shares at a price of $6.00 per share for proceeds to the Company of $540,000. In total, 325,000 ordinary shares were issued upon warrant exercise.

 

On July 22, 2022, the Company entered into an At The Market Offering Agreement (the “ATM Agreement”) with H.C. Wainwright & Co., LLC (the “Sales Agent”), acting as the Company’s sales agent, pursuant to which the Company may offer and sell, from time to time, to or through the Sales Agent, ordinary shares (the “ATM Shares”) having an aggregate gross offering price of up to $20,000,000. Under the ATM Agreement, the ATM Shares, if offered and sold by the Company, will be offered and sold pursuant to a prospectus dated February 16, 2021 and a prospectus supplement, dated July 22, 2022, that form a part of the Company’s shelf registration statement on Form F-3 (File No. 333-252520), which registration statement was declared effective by the Securities and Exchange Commission (“SEC”) on February 16, 2021. On August 25, 2022, the Company sold 177,763 ATM Shares at $10.7407 per share for net proceeds (after Sales Agent commissions) of $1,801,193. On August 25, 2022, the Company sold an additional 280,612 ATM Shares at $10.1090 per share for net proceeds (after Sales Agent commissions) of $2,750,449.

 

As of December 31, 2023 and 2022, the Company has a total of 10,142,694 ordinary shares outstanding.

 

NOTE 14 – COMMITMENTS AND CONTINGENCIES

 

Litigation

 

From time to time, the Company may be subject to routine litigation, claims, or disputes in the ordinary course of business. The Company defends itself vigorously in all such matters. In the opinion of management, no pending or known threatened claims, actions or proceedings against the Company are expected to have a material adverse effect on its financial position, results of operations or cash flows. However, the Company cannot predict with certainty the outcome or effect of any such litigation or investigatory matters or any other pending litigation or claims. There can be no assurance as to the ultimate outcome of any such lawsuits and investigations. The Company has no significant pending litigation as of December 31, 2023.

 

Commitments

 

As a requirement to acquire and maintain the operatorship of oil and gas blocks in Indonesia, the Company follows a work program and budget that includes firm capital commitments.

 

The Kruh Block covers a 258 square kilometer area with a TAC contract until May 20, 2020, continued with a KSO contract until May 20, 2030, which was extended to 2035. The Company has material commitments in regard to Kruh Block and material commitments in regard to the exploration activity in the Citarum Block and development and exploration activities in Kruh Block following the extension of the operatorship in May 2020. The Company has also entered into a joint study program for the Rangkas Area to evaluate the oil and gas potential of the area. The following table summarizes future commitments amounts on an undiscounted basis as of December 31, 2022 for all the planned expenditures to be carried out in Kruh Block, Citarum Block and the Rangkas Area:

 

F-29

SUMMARY OF FUTURE COMMITMENTS AMOUNTS ON AN UNDISCOUNTED FOR ALL THE PLANNED EXPENDITURES

						Future commitments
		Nature of commitments				2024				2025				2026 and beyond
Citarum Block PSC
Geological and geophysical (G&G) studies			(a)			$	-			$	150,000			$	950,000
2D seismic			(a)				-				-				6,050,000
3D seismic			(a)				-				-				2,100,000
Drilling			(b)(c)				-				-				30,000,000
Total commitments - Citarum PSC						$	-			$	150,000			$	39,100,000
Kruh Block KSO															-
Operating commitments			(d)			$	1,687,622			$	1,562,162			$	74,595,092
Production facility							-				-				1,300,000
G&G studies			(a)				100,000				100,000				350,000
3D seismic			(a)				1,140,000				-				-
Drilling			(a)(c)				-				-				21,000,000
Workover							-				-				-
Certification							-				-				250,000
Abandonment and Site Restoration			(a)				53,085				53,085				504,309
Total commitments - Kruh KSO						$	2,980,707			$	1,715,247			$	97,999,401
Total Commitments						$	2,980,707			$	1,865,247			$	137,099,401

 

Nature of commitments:

 

	(a)	Both firm commitments and a 5-year work program according to the Company’s economic model are included in the estimate. Firm capital commitments represent legally binding obligations with respect to the KSO for Kruh Block or the PSC for Citarum Block in which the contract specifies the minimum exploration or development work to be performed by us within the first three years of the contract. In certain cases where we execute contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated.
	(b)	Includes one exploration and two delineation wells.
	(c)	Abandonment and site restoration are primarily upstream asset removal costs at the drilling completion of a field life related to or associated with site clearance, site restoration, and site remediation, based on Indonesian government rules.
	(d)	Operating commitments are primarily production operation costs related to or associated to the maintenance well work scheduled to be performed on the oil wells with respect to the Kruh Block KSO.

 

NOTE 15 – SUBSEQUENT EVENTS

 

Management has evaluated subsequent events and transactions that occurred after the balance sheet date up to the date that the financial statements were issued. Based upon this review, the Company did not identify any subsequent events that would have required adjustment or disclosure in the financial statements except the following.

 

On January 30, 2024, the Company issued 60,000 of the Company’s restricted ordinary shares to Frank C. Ingriselli, the Company’s President, pursuant to his employment agreement with the Company, with 30,000 shares vesting on July 1, 2024 and 30,000 shares vesting on January 1, 2025.

 

On March 22, 2024, the Company filed a New F-3 Registration Statement, which includes a Prospectus Supplement and a base prospectus supplemented by the Prospectus Supplement, covering (i) the offering, issuance and sale by us of up to a maximum aggregate offering price of $50,000,000 of our ordinary shares, preferred shares, warrants, debt securities, rights, depositary shares, and/or units from time to time in one or more offerings, and (ii) up to a maximum aggregate offering price of $4,267,622 of our ordinary shares that may be issued and sold from time to time under the ATM Agreement, as amended by the ATM Amendment No.1 on March 22, 2024, with H.C. Wainwright & Co., LLC as Sales Agent. We are not permitted to sell any ATM Shares prior to the effectiveness of the New F-3 Registration Statement. As of the date of this report, the New F-3 Registration Statement has not been declared effective.

 

 

SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) 

 

The following supplemental unaudited information regarding the Company’s oil and gas activities is presented pursuant to the disclosure requirements of ASC 932. All oil and gas operations are located in Indonesia.

 

All of the Company’s operations are directly related to oil and natural gas producing activities from the Kruh Block in Indonesia.

 

Capitalized Costs Relating to Oil and Gas Producing Activities

 

SCHEDULE OF CAPITALIZED COSTS

		2023				2022				2021
		As of December 31,
		2023				2022				2021
Proved properties
Mineral interests		$	15,084,658			$	15,084,658			$	15,084,658
Wells, equipment and facilities			13,907,363				13,655,822				8,743,485
Total proved properties			28,992,021				28,740,480				23,828,143
Unproved properties
Mineral interests			1,155,439				1,151,804				1,151,804
Uncompleted wells, equipment and facilities			-				-				-
Total unproved properties			1,155,439				1,151,804				1,151,804
Less accumulated depletion and impairment			(21,880,397	)			(21,270,660	)			(20,223,663	)
Net Capitalized Costs		$	8,267,063			$	8,621,624			$	4,756,284

 

Costs Incurred in Oil and Gas Property Exploration, and Development

 

Amounts reported as costs incurred include both capitalized costs for exploration and development activities and costs charged to expense for normal maintenance operational activities under TAC and KSO of Kruh Block. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

 

SCHEDULE OF COSTS INCURRED IN OIL AND GAS PROPERTY EXPLORATION, AND DEVELOPMENT

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
GWN (Kruh)
Exploration		$	-			$	-			$	-
Development			251,542				4,912,336				2,916,102
Total Exploration and Development Activities		$	251,542			$	4,912,336			$	2,916,102
CNE (Citarum)
Exploration		$	-			$	-			$	-
Development			3,635				-				38,309
Total Exploration and Development Activities		$	3,635			$	-			$	38,309
GWN (Rangkas)
Exploration		$	-			$	-			$	-
Development			-				-				-
Total Exploration and Development Activities		$	-			$	-			$	-
Total Costs Incurred in Oil and Gas Property Exploration, and Development		$	255,177			$	4,912,336			$	2,954,411

 

Results of Operations from Oil and Gas Producing Activities

 

Results of operations for producing activities consist of all activities within the operating reporting segment. Revenues are generated from entitlement of oil and gas property –Kruh Block Proven and profit sharing of the sale of the crude oil under the KSO. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities used in oil and gas operations, including expenditures made and obligations incurred in the exploration, development, extraction, production, transportation, marketing, abandonment and site restoration; and production-related general and administrative expense. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

 

SCHEDULE OF RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

		2023				2022				2021
		Years Ended December 31,
		2023				2022				2021
Oil and gas revenues		$	3,525,454			$	4,097,403			$	2,452,540
Production costs			(2,943,173	)			(2,953,254	)			(2,492,476	)
Depletion, depreciation, and amortization			(702,217	)			(1,139,723	)			(810,855	)
Result of oil and gas producing operations before income taxes		$	(119,936	)		$	4,426			$	(850,791	)
Provision for income taxes			-				-				-
Results of oil and gas producing operations		$	(119,936	)		$	4,426			$	(850,791	)

 

F-31

 

Proved Reserves the Company Expects to Lift in Kruh Block

 

The Company’s proved oil reserves have not been estimated or reviewed by independent petroleum engineers. The estimate of the proved reserves for the Kruh Block was prepared by IEC representatives, a team consisting of engineering, geological and geophysical staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

 

The Company’s estimates of the proven reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers, and Pertamina, and revised as warranted by additional data. Revisions are due to changes in, among other things, development plans, reservoir performance, the KSO effective period and governmental restrictions.

 

Kruh Block’s general manager, Mr. Denny Radjawane, and the Company’s Chief Technology Officer, Mr. Charlie Wu, have reviewed the reserves estimate to ensure compliance to SEC guidelines for (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities. The estimate of reserves was also reviewed by the Company’s Chief Operating Officer and Chief Executive Officer.

 

The table below shows the individual qualifications of the Company’s internal team that prepares the reserves estimation:

 

SCHEDULE OF INDIVIDUAL QUALIFICATIONS OF RESERVES ESTIMATION

						Total
Reserve		University				professional				Field of professional experience (years)
Estimation Team*		degree major		Degree level		experience (years)				Drilling & Production		Petroleum Engineering				Production Geology				Reserve Estimation
Charlie Wu		Geosciences		Ph.D.			46			12			-				34			23
Frans Watimena		Petroleum Engineering		M.S.			35			20			15				-			6
Denny Radjawane		Geophysics		M.S.			33			12			-				21			15
Fransiska Sitinjak		Petroleum Engineering		M.S.			20			6			14				-			9
Yudhi Setiawan		Geology		B.S.			21			15			2				4			2
Oni Syahrial		Geology		B.S.			17			2			-				15			9
Juan Chandra		Geology		B.S.			18			2			-				16			10

 

*

The individuals from the reserves estimation team are member of at least one of the following professional associations: American Association of Petroleum Geologists (AAPG), Indonesian Association of Geophysicist (HAGI), Indonesian Association of Geologists (IAGI), Society of Petroleum Engineers (SPE), Society of Indonesian Petroleum Engineers (IATMI) and Indonesian Petroleum Association (IPA).

 

F-32

 

In the “cost recovery” system of a KSO, under which Kruh Block operates or will operate, the production share and net reserves entitlement to the Company reduces in periods of higher oil price and increases in periods of lower oil price. This means that the estimated net proved reserves quantities are subject to oil price related volatility due to the method in which the revenue is derived throughout the contract period. Therefore, the net proved reserves are estimated based on the revenue generated by the Company according to the KSO economic model.

 

As of December 31, 2023 and 2022, the Company estimates that it will be entitled to approximately 74.16% and 57.56% of the revenues from the sales of the crude oil produced throughout the operatorship in Kruh Block. The estimates are based on the extension of the Kruh Block operatorship to September 2035 for the 2023 model and to May 2030 for the 2022 model, and the cost recovery balance reset to nil in May 2020.

 

Following the confirmation of the Kruh Block extension, the Company approved a development plan for a drilling program of 14 Proved Undeveloped Reserves (or PUD) wells, according to the schedule below:

 SCHEDULE OF PROVED UNDEVELOPED RESERVES WELLS

		Unit\Year		2026				2027				2028				2029				Total
Planned PUD wells		Gross well			4				4				4				2				14
Future wells costs (1)		US$			6,000,000				6,000,000				6,000,000				3,000,000				21,000,000
Costs already paid		US$			-				-				-								-
Total gross PUD added		Bbls			750,189				727,140				884,661				447,478				2,809,468
Total net PUD added		Bbls			556,365				539,271				656,094				331,864				2,083,594

 

(1)	Future wells costs are the capital expenditures associated with the new wells costs and do not include other capital expenditures such as production facilities.

 

F-33

 

The fiscal 2023 and 2022 proved developed and undeveloped reserves are summarized in the tables below:

 SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES

		Crude Oil (Bbls) as of December 31,
		2023				Note		2022				Note
Total Proved Developed (PDP) and Undeveloped Reserves (PUD)
Beginning of the period			2,056,407						3,253,617
Revisions of previous estimates			1,165,999			(a)			(1,121,980	)		(1)
Improved recovery			(19,131	)		(b)			(12,763	)		(2)
Purchase of minerals in place			-						-
Extensions and discoveries			-						-
Production			(58,616	)		(c)			(62,467	)		(3)
Sale of minerals in place			-						-
End of the period			3,144,659						2,056,407
Net Proved Developed Reserves (PDP) and Undeveloped Reserves (PUD)
Beginning of the period			1,183,615						1,517,841
Revisions of previous estimates			1,206,228			(d)			(290,926	)		(4)
Improved recovery			(14,188	)		(e)			(7,346	)		(5)
Purchase of minerals in place			-						-
Extensions and discoveries			-						-
Production			(43,472	)		(f)			(35,954	)		(6)
Sale of minerals in place			-						-
End of the period			2,332,183						1,183,615
Total Proved developed reserves (PDP)
Beginning of the period			371,076						311,211
Revisions of previous estimates			41,862			(g)			5,476			(7)
Improved recovery			(19,131	)					(12,763	)
Purchase of minerals in place			-						-
Extensions and discoveries			-			(h)			125,425			(8)
Production			(58,616	)		(i)			(58,273	)		(9)
Sale of minerals in place			-						-
End of the period			335,191						371,076
Total Proved undeveloped reserves (PUD)
Beginning of the period			1,685,331						2,942,406
Revisions of previous estimates			1,124,137			(j)			(1,127,456	)		(10)
Improved recovery			-						-
Purchase of minerals in place			-						-
Extensions and discoveries			-			(k)			(125,425	)
Production			-			(l)			(4,194	)
Sale of minerals in place			-						-
End of the period			2,809,468						1,685,331
Net Proved developed reserves (PDP)
Beginning of the period			213,582						145,182
Revisions of previous estimates			92,667			(m)			37,095			(11)
Improved recovery			(14,188	)					(7,346	)
Purchase of minerals in place			-						-
Extensions and discoveries			-			(n)			72,191
Production			(43,472	)		(o)			(33,540	)		(12)
Sale of minerals in place			-						-
End of the period			248,589						213,582
Net Proved undeveloped reserves (PUD)
Beginning of the period			970,033						1,372,659
Revisions of previous estimates			1,113,561			(p)			(328,021	)		(13)
Improved recovery			-						-
Purchase of minerals in place			-						-
Extensions and discoveries			-			(q)			(72,191	)
Production			-			(r)			(2,414	)		(14)
Sale of minerals in place			-						-
End of the period			2,083,594						970,033

 

F-34

 

	(a)	The revision of previous estimates in the amount of 1,165,999 bbls refers to the sum of 1) revision of previous PDP reserves estimates of 41,862 bbls (note g) and 2) revision of previous PUD reserves estimate of 1,124,137 bbls (note j).
	(b)	The improved recovery amount of -19,131 bbls refers to the amount variation of crude oil production of 58,616 bbls (note i) in 2023 compared to previous estimates of 77,747 bbls (prediction in previous year’s model) for Kruh Block in 2022 as a result of rescheduling of drilling program and reserves revision.
	(c)	The production in the amount of 58,616 bbls refers to the amount of total gross crude oil produced from 1) PDP reserves production in the amount of 58,616 bbls (note i) and 2) PUD reserves production in the amount of zero bbls (note l) in the Kruh Block.
	(d)	The revisions of previous estimates of 1,206,228 bbls refers to the total amount of 1) net PDP reserves revision of previous estimates in the amount of 92,667 bbls (note m), and 2) net PUD reserves revision of previous estimates in the amount of 1,113,561 bbls (note p).
	(e)	The Improved recovery in the amount of -14,188 bbls refers to the net share (74.16%) of crude oil production variation of -19,131 bbls (note b) as a result of rescheduling of drilling program.
	(f)	The net PDP and PUD production of -43,472 bbls refers to the sum of the net PDP production in the amount of -43,472 bbls (note o) and net PUD production in the amount of zero bbls (note r).
	(g)	The revisions of previous estimates in the amount of 41,862 bbls refers to the total gross amount of PDP reserves variation as a result of production and well conditions; and the reserves gain from the additional 5 years production and greater profit split to 2035.
	(h)	No new drilling in 2023 resulted in zero extensions and discoveries.
	(i)	The PDP production in the amount of -58,616 bbls refers to the gross amount of PDP reserves produced in 2023.
	(j)	The revisions of previous estimates in the amount of 1,124,137 bbls refers to the total gross amount of PUD reserves variation from the 1,685,331 bbls in 2022 to 1,191,048 bbls in 2023 during the same period to 2030; and offset by the reserves gain of 1,618,420 bbls from 5 years additional production and greater split.
	(k)	No new drilling in 2023 resulted in zero extensions and discoveries.
	(l)	The PUD production in the amount of zero bbls refers to no PUD reserves converted to production in 2023.
	(m)	The revision of previous estimates of net PDP reserves in the amount of 92,667 bbls refers to the sum of 1) net share difference (74.16%) in 2023 as compared to (57.56%) in 2022 of the beginning total PDP reserves in the amount of 371,076 bbls and 2) net share (74.16%) of revision of previous estimates of total PDP reserves estimates in the amount of 41,862 bbls (note g).
	(n)	No new drilling in 2023 resulted in zero extensions and discoveries.
	(o)	The net PDP production in the amount of 43,472 bbls refers to the net share (74.16%) of gross amount of 58,616 bbls (note i) PDP reserves produced in 2023.
	(p)	The revision of previous estimates of net PUD reserves in the amount of 1,113,561 bbls refers to the sum of (1) net share difference (74.16%) in 2023 as compared to (57.56%) in 2022 of the beginning total PUD reserves in the amount of 1,685,331 bbls, and (2) net share (74.16%) of revision of previous estimates of total PUD reserves estimates in the amount of 1,124,137 bbls (note j).
	(q)	No new drilling in 2023 resulted in zero extensions and discoveries.
	(r)	The net PUD production in the amount of zero bbls reflects the PUD reserves converted to production in 2023.

 

F-35

 

	(1)	The revision of previous estimates in the amount of -1,121,981 bbls refers to the sum of 1) revision of previous PDP reserves estimates of 5,475bbls (note g) and 2) revision of previous PUD reserves estimate of -1,127,456 bbls (note 10).
	(2)	The improved recovery amount of -12,763 bbls refers to the amount variation of crude oil production of 58,273 bbls (note 9) in 2022 compared to previous estimates of 71,036 bbls (prediction in previous year’s model) for Kruh Block in 2021 as a result of rescheduling of drilling program and reserves revision.
	(3)	The production in the amount of 62,467 bbls refers to the amount of total gross crude oil produced from 1) PDP reserves production in the amount of 58,273 bbls (note 9) and 2) PUD reserves production in the amount of 4,194 bbls in the Kruh Block.
	(4)	The revisions of previous estimates of -290,926 bbls refers to the total amount of 1) net PDP reserves revision of previous estimates in the amount of 37,094 bbls (note 11), and 2) net PUD reserves revision of previous estimates in the amount of -328,019 bbls (note 13).
	(5)	The Improved recovery in the amount of -7,346 bbls refers to the net share (57.56%) of crude oil production change of -12,763 bbls (note 2) as a result of rescheduling of drilling program.
	(6)	The net PDP and PUD production of -35,954 bbls refers to the sum of the net PDP production in the amount of -33,540 bbls (note 12) and net PUD production in the amount of -2,414 bbls (note 14).
	(7)	The revisions of previous estimates in the amount of 5,475 bbls refers to the total gross amount of PDP reserves variation as a result of production.
	(8)	The extension and discoveries in the amount of 125,425 bbls refers to the gain of PDP reserves from the completion of two new wells, K-27 and K-28.
	(9)	The PDP production in the amount of 58,616 bbls refers to the gross amount of PDP reserves produced in 2022.
	(10)	The revisions of previous estimates in the amount of -1,127,456 bbls refers to the total gross amount of PUD reserves variation from the 2,942,406 bbls in 2021 to 1,814,950 bbls in 2022 during the same period to 2030.
	(11)	The revision of previous estimates of net PDP reserves in the amount of 37,094 bbls refers to the sum of 1) net share difference (57.56%) in 2022 as compared to (46.65%) in 2021) of the beginning total PDP reserves in the amount of 311,211 bbls and 2) net share (57.56%) of revision of previous estimates of total PDP reserves estimates in the amount of 5,475 bbls (note 7).
	(12)	The net PDP production in the amount of 33,540 bbls refers to the net share (57.56%) of gross amount of 58,273 bbls (note 9) PDP reserves produced in 2022.
	(13)	The revision of previous estimates of net PUD reserves in the amount of -328,019 bbls refers to the sum of 1) net share difference (57.56%) in 2022 as compared to (46.65%) in 2021 of the beginning total PUD reserves in the amount of 2,942,406 bbls, and 2) net share (57.56%) of revision of previous estimates of total PUD reserves estimates in the amount of -1,127,456 bbls (note 10).
	(14)	The net PUD production in the amount of 2,414 bbls reflects the net PUD reserves converted to production in 2022.

 

F-36

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

 

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2023 and 2022, respectively, in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

 SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

		2023				2022
		As of December 31,
		2023				2022
Future cash inflows		$	181,000,717			$	114,735,610
Future production costs (1)			(99,160,999	)			(64,815,304	)
Future development costs			(29,867,500	)			(29,404,571	)
Future income tax expenses			(18,037,976	)			(7,591,667	)
Future net cash flows		$	33,934,242			$	12,924,068
10% annual discount for estimated timing of cash flows			(18,318,152	)			(4,690,738	)
Standardized measure of discounted future net cash flows at the end of the year		$	15,616,090			$	8,233,330

 

(1)	Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and general and administrative expense supporting the Company’s oil and gas operations.

 

Future cash inflows are computed by applying the ICP previous 12 months average monthly price, to year-end quantities of proved reserves. ICP is determined by the Directorate General of Oil and Gas (“DGOG”) of The Ministry of Energy and Mineral Resources of Indonesia (“MEMR”) on a monthly basis and presented as the monthly price of the crude oil according to the region where the oil is produced. The discounted future cash flow estimates do not include the effects of the Company’s derivative instruments, if any. See the following table for average prices.

 SCHEDULE OF AVERAGE PRICES

		Years ended December 31,
		2023				2022				2021
Average crude oil price per Bbl		$	77.61			$	96.94			$	67.02

 

Future production and development costs, which include abandonment and site restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

 

Sources of Changes in Discounted Future Net Cash Flows

 

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves at year end are set forth in the table below.

 SCHEDULE OF SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS

		2023				2022				2021
		Year ended December 31,
		2023				2022				2021
Standardized measure of discounted future net cash flows at the beginning of the year		$	8,233,330			$	7,597,232			$	5,579,842
Extensions, discoveries and improved recovery, less related costs			500,000				500,000				500,000
Revisions of previous quantity estimates			40,409,026				(19,526,823	)			(14,979,996	)
Changes in estimated future development costs			(584,751	)			340,200				4,046,951
Purchases (sales) of minerals in place			-				-				-
Net changes in prices and production costs			(6,345,840	)			15,310,987				19,129,705	)
Accretion of discount			(13,627,414	)			23,577				638,201
Sales of oil and gas produced, net of production costs			(2,643,773	)			(4,244,775	)			(4,328,719	)
Development costs incurred during the period			121,822				4,540,497				2,724,238
Change in timing of estimated future production and other			-				-				-
Net change in income taxes			(10,446,308	)			3,692,435				(5,712,990	)
Standardized measure of discounted future net cash flows at the end of the year		$	15,616,090			$	8,233,330			$	7,597,232