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

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

For the fiscal year ended December 31, 2020

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)

Gedung Graha Anugerah

Jl. Raya Pasar Minggu No. 17A

Kelurahan Pancoran, Kecamatan Pancoran

Jakarta Selatan 12780 - Indonesia

(Address of principal executive offices)

James J. Huang

Chief Investment Officer

Phone: +62 21 576 8888

Email: james.huang@indo-energy.com

(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, 2020, there were 7,407,955 shares of the registrant’s ordinary shares, $0.00267 par value per share, issued and 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 [X]
		Emerging growth company [X]

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 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
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	36
ITEM 4A.	UNRESOLVED STAFF COMMENTS	78
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	79
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	94
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	114
ITEM 8.	FINANCIAL INFORMATION	116
ITEM 9.	THE OFFER AND LISTING	116
ITEM 10.	ADDITIONAL INFORMATION	116
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	123
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	124
PART II		124
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	124
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OR PROCEEDS	124
ITEM 15.	CONTROLS AND PROCEDURES	124
ITEM 16.	RESERVED	126
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	126
ITEM 16B.	CODE OF ETHICS	126
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	126
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	127
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	127
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	127
ITEM 16G.	CORPORATE GOVERNANCE	127
ITEM 16H.	MINE SAFETY DISCLOSURE	127
PART III		127
ITEM 17.	FINANCIAL STATEMENTS	127
ITEM 18.	FINANCIAL STATEMENTS	127
ITEM 19.	EXHIBITS	128
	GLOSSARY OF TERMS	129

-i-

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 to meet our goals and strategies, including our plans to drill additional wells at Kruh Block, to develop Citarum Block or acquire rights in additional oil and gas assets in the future;

● the economic, capital markets and social impact of the worldwide novel coronavirus (COVID-19) pandemic 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 oil and gas products and the growth of the oil and gas market in Indonesia and worldwide;

● our expectations regarding our relationships with the 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.

-ii-

RISK FACTORS SUMMARY

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.;

● 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;

● the global pandemic of COVID-19 and volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects;

● 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 may not adhere to our proposed drilling schedule, and our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control;

● 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;

● negative changes in global, regional or Indonesian economic activity could adversely affect our business;

● 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;

● we are a holding company, and will rely on dividends paid by our subsidiaries for our cash needs. Any limitation on the ability of our subsidiaries to make dividend payments to us, or any tax implications of making dividend payments to us, could limit our ability to pay our parent company expenses or pay dividends to holders of our ordinary shares;

● 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, 2020.

● 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; and

● 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.

-iii-

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. Selected Financial Data

The following table summarizes our financial data. We have derived the following statements of operations data for the years ended December 31, 2020, 2019 and 2018 and balance sheet data as of December 31, 2020 and 2019 from our audited financial statements included elsewhere in this annual report. The following statements of operations data for the year ended December 31, 2017 and balance sheet data as of December 31, 2018 and 2017 have been derived from our audited financial statements for the years ended December 31, 2018 and 2017, which are not included in this annual report. Our historical results are not necessarily indicative of the results that may be expected in the future. Numbers in the following tables are in U.S. dollars except share numbers.

STATEMENT OF OPERATIONS DATA:

	Years Ended December 31,
	2020			2019			2018		2017
Revenue	$	1,980,773		$	4,183,354		$	5,856,341	$	3,703,826
Lease operating expenses		2,017,856			2,474,230			2,540,353		2,811,006
Depreciation, depletion and amortization		698,851			876,676			1,156,494		1,187,217
General and administrative expenses		6,533,642			2,434,099			2,016,110		1,258,069
Other income(expense)		317,878			(72,084	)		2,396		66,574
Net (loss) income		(6,951,698	)		(1,673,735	)		140,988		(1,619,040	)
(Loss) income per ordinary share attributable to the Company
Basic and diluted		(0.94	)		(0.28	)		0.02		(0.27	)
Weighted average ordinary shares outstanding
Basic and diluted		7,395,120			6,048,568			6,000,000		6,000,000

1

BALANCE SHEET DATA:

	December 31,		December 31,		December 31,		December 31,
	2020		2019		2018		2017
Current assets	$	11,241,389	$	15,074,725	$	4,000,171	$	4,565,571
Total assets		15,575,808		21,155,337		9,877,486		8,670,516
Current liabilities		1,827,795		2,739,068		2,672,644		3,808,275
Total liabilities		3,217,749		4,961,412		4,803,980		28,057,054
Ordinary shares		19,754		19,636		16,000		16,000
Total equity (deficit)	$	12,358,059	$	16,193,925	$	5,073,506	$	(19,386,538	)

B. Capitalization and Indebtedness

Not applicable.

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

Investing in our ordinary shares involves a high 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.

2

Decreases in oil and gas prices have 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. 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 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, 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 2020 with very significant swings in the price of oil as a result of the global novel coronavirus pandemic, and we may continue to be subject to oil and gas price-related risks while the pandemic persists and for so long as the global economy remains uncertain.

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, 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, 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.

3

Drilling oil and natural gas wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of 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;

● 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.

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 may vary from 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 results of exploration efforts and the acquisition, review and analysis of the seismic data;

● the availability of sufficient capital resources to us and the other participants for the drilling of the 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.

4

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

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 we have experienced since mid-2014 and which was exacerbated during the COVID-19 pandemic, caused, have 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.

The outbreak of COVID-19 and volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects.

The outbreak of COVID-19 and its development into a pandemic in March 2020 have resulted in significant disruption globally. Actions taken by various governmental authorities, individuals and companies around the world to prevent the spread of COVID-19 have restricted travel, business operations, and the overall level of individual movement and in-person interaction across the globe, including the United States and Indonesia. Furthermore, the impact of the pandemic, including a resulting reduction in demand for oil and natural gas, coupled with the sharp decline in commodity prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of the Petroleum Exporting Countries (“OPEC”) has led to significant global economic contraction generally and in the oil and gas exploration industry in particular. While an agreement to cut production has since been announced by OPEC and its allies, the situation, coupled with the impact of COVID-19, has continued to result in a significant downturn in the oil and gas industry, which resulted in lower revenue and cost recovery entitlements for the year ended December 31, 2020 than in 2019.

The COVID-19 pandemic has caused us to modify our business practices, including by restricting employee travel, requiring employees to work remotely and cancelling physical participation in meetings, events and conferences, and we may take further actions as may be required by government authorities or that we determine are in the best interests of our employees, customers and business partners. There is no certainty that such measures will be sufficient to mitigate the risks posed by COVID-19 or otherwise be satisfactory to government authorities. If a number of our employees were to contract COVID-19 at the same time, our operations could be adversely affected.

A sustained disruption in the capital markets from the COVID-19 pandemic, specifically with respect to the energy industry, could negatively impact our ability to raise capital. In the past, we have financed our operations by the issuance of equity securities. However, we cannot predict when the macro-economic disruption stemming from COVID-19 will ebb or when the economy will return to pre-COVID-19 levels, if at all. This macro-economic disruption may disrupt our ability to raise additional capital to finance our operations in the future, which could materially and adversely affect our business, financial condition and prospects, and could ultimately cause our business to fail.

5

The extent to which COVID-19 ultimately impacts our business, results of operations and financial condition will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of COVID-19 or variants of COVID-19, its severity, the actions to contain COVID-19 or treat its impact (such as vaccinations), and how quickly and to what extent normal economic and operating conditions can resume. Even after COVID-19 has subsided, we may continue to experience materially adverse impacts to our business as a result of its global economic impact, including any recession that has occurred or may occur in the future, and lasting effects on the price of oil and natural gas.

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 and we expect to continue to utilize these 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. This is particularly the case as we raised less funds than we had anticipated in our December 2019 initial public offering, which could require us to modify our drilling and other operational plans.

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 are faced with challenges relative to the allocation of those funds, which is requiring us to modify our business plan and which could create challenges for our ability to fully fund our plans.

In addition, and 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.

6

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. 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 estimate, 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 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, 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. 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.

7

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 may not adhere to our proposed drilling schedule.

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, our final determination of whether and when to drill any scheduled or budgeted wells (whether in Kruh Block or otherwise) 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.

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 the ability to operate during such conditions. 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.

8

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;

● uncontrollable pressures or flows of oil or gas or well fluids; and

● public health risks and pandemic outbreaks, such as the recent novel coronavirus pandemic.

With respect to the early 2020 novel coronavirus outbreak in particular, the full effects of this outbreak around the world are presently unknown and unpredictable and could have a material adverse effect on (i) the demand for our oil and gas in Indonesia, (ii) our ability to staff our drilling operations and (iii) our supply chain.

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.

9

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.

10

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 have and 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.

11

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;

● weather conditions;

● price and level of foreign imports;

● terrorist activity;

● availability of pipeline and other secondary capacity;

● general economic conditions;

● global risks of a potential coronavirus outbreak, or other global or local public health uncertainties;

● domestic and foreign governmental regulation; and

● the price and availability of alternative fuel sources.

12

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

The process of estimating oil reserves in accordance with SEC requirements 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 will likely require further financing. In addition, we may 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.

13

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

This annual 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.

14

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 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 production sharing contract 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 if we are unable 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.

15

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 (or the Oil and Gas Law) went into effect on November 23, 2001. This 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. Of particular significance is the fact that the Government is expected to enact a new oil and gas law in the future. The form, timing and contents of this new law remain uncertain; several draft amendments to the current Oil and Gas Law have been submitted to the House of Representatives and were given “priority” listing in the 2017 National Legislation Program (Program Legislasi Nasional). As a result, there is a possibility that the current Indonesian oil and gas law will be significantly amended or that a new Indonesian oil and gas law will be issued in the future. The scope of any possible revisions to the Indonesian oil and gas law remains uncertain. 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.

16

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 No. 11 of 2020 on Job Creation (or the Omnibus Law) and its implementing regulation, Government Regulation No. 22 of 2021 on Environment Protection and Management (or GR 22/2021), require an entity conducting oil and gas business operations have its environmental impact assessment report (Analisis Mengenai Dampak Lingkungan, or 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, our environmental permit may be revoked should we fail to meet the obligations contained in the relevant AMDAL or UKL or UPL, which can in turn 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.

17

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 each of the countries 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 “Borrow-to-use permit of forest area (Izin Pinjam Pakai Kawasan Hutan, or IPPKH)” from the Indonesian Ministry of Forestry. Borrow-to-use permit of forest area 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. In 2014, the Indonesian government further specified that priority of Borrow-to-use permit of forest area would be given to geothermal, oil and gas production activities.

The application for a Borrow-to-use permit must satisfy both administrative and the technical requirements. The maximum validity period for a Borrow-to-use permit 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 Borrow-to-use permit may be granted for a maximum period of two years and it is non-extendable. Prior to 2018, the application and process of Borrow-to-use permit of forest area was complex because applicants had to process 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 “online single submission (OSS)” processing system in 2018 by the Ministry of Forestry, the time required for processing the permit was changed from 180 work days to 34 work days. However, this new system has yet to be fully implemented, and numerous documents and other permits (including the local governor’s recommendation and environmental permits) as well as a work program and maps are required before Borrow-to-use permit of forest area can be submitted to the Ministry of Forestry. Any delay of in the issuance to us of Borrow-to-use permit of forest area, or our inability to main 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.

18

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 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.

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.

19

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, economic conditions, whether due to the COVID-19 pandemic or any other such downturn for any other reason, 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 the oil and gas extraction. During 2020, Indonesian gross domestic product declined for the first time in several years with a decline of 2.1% according to the International Monetary Fund, and 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 or developed 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.

20

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, 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 April 2021, the central government has issued at least 50 implementing regulations making the Omnibus Law one of the most sweeping regulatory reform 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. 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.

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. For example, since 2000, thousands of Indonesians have participated in demonstrations in Jakarta and other Indonesian cities both for and against former presidents Abdurrahman Wahid, Megawati Soekarnoputri and Susilo Bambang Yudhoyono and current President Joko Widodo as well as in response to specific issues, including fuel subsidy reductions, privatization of state assets, anti-corruption measures, decentralization and provincial autonomy, and the American-led military campaigns in Afghanistan and Iraq. Although these demonstrations were generally peaceful, some turned violent.

Indonesia had a general election in May 2019 and the Indonesian Election Committee (KPU) announced on May 22, 2019 that President Joko Widodo had won the election. He was then inaugurated on October 20, 2019. President Joko Widodo’s opposing candidate, Prabowo Subianto, had filed a suit with the Indonesian Constitutional Court challenging the outcome of the election, but he was appointed by President Joko Widodo to be a member of the cabinet, serving as the Ministry of Defense. This uncertainty in the political conditions in Indonesia could adversely impact our business.

In addition, effective January 1, 2015, a fixed diesel subsidy of Rp1,000 per liter was implemented and the gasoline subsidy was ended. Although the implementation did not result in any significant violence or political instability, the announcement and implementation also coincided with a period where crude oil prices had dropped very significantly from 2014. With the purpose to provide stability of the retail sale price of the gasoline and diesel, the Energy and Mineral Resources Ministry issued on February 28th Ministerial Decree No. 62/2020 that erases a price floor for unsubsidized gasoline and diesel set by a previous decree, providing flexibility to reduce prices as low as possible. The new decree still maintains a price ceiling for such fuels pegged to prices in Singapore. The Government reviews and adjusts the price for fuel on monthly basis and implements the adjusted fuel price in the following month. There can be no assurance that future increases in crude oil and fuel prices will not result in political and social instability.

Furthermore, separatist movements and clashes between religious and ethnic groups have also resulted in social and civil unrest in parts of Indonesia, such as Aceh in the past and in Papua currently, where there have been clashes between supporters of those separatist movements and the Indonesian military, including continued activity in Papua, by separatist rebels that has led to violent incidents. There have also been inter-ethnic conflicts, for example in Kalimantan, as well as inter-religious conflict such as in Maluku and Poso.

Also, labor issues have also come to the fore in Indonesia. In 2003, the Government enacted a new labor law that gave employees greater protections. Occasional efforts to reduce these protections have prompted an upsurge in public protests as workers responded to policies that they deemed unfavorable.

As a result, 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.

21

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 or for any other reason.

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, including the May 2005 bombing in Central Sulawesi, the Bali bombings in October 2002 and October 2005 and the bombings at the JW Marriot and Ritz Carlton hotels in Jakarta in July 2009, which resulted in deaths and injuries. On January 14, 2016, several coordinated bombings and gun shootings occurred in Jalan Thamrin, a main thoroughfare in Jakarta, resulting in a number of deaths and injuries.

Although the Government has successfully countered some terrorist activities in recent years and arrested several of those suspected of being involved in these incidents, terrorist incidents may continue 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.

22

An additional significant event that as of the date of this annual report is still unfolding and uncertain is the novel coronavirus outbreak which began in early 2020 and the related disease, COVID-19, which was declared as a pandemic by the World Health Organization on March 11, 2020. Indonesian government officials called for social distancing and isolation and considered to enforce a lockdown in affected areas in an attempt to minimize the spread of the virus. The restrictions currently in place, whether mandated by the Government or implemented locally, or if other COVID-19 related conditions persist in Indonesia, the adverse economic situation in Indonesia may greatly impact our business and operations.

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. 

Whilst 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 annual report, Indonesia’s sovereign foreign currency long-term debt was rated “Baa2” by Moody’s, “Negative” by Standard & Poor’s and “BBB” by Fitch Ratings. Indonesia’s short-term foreign currency debt is rated “A-2” by Standard & Poor’s and “F2” by Fitch Ratings.

23

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.

Indonesian Law No.25 of 1999 regarding Fiscal Decentralization and Law No.22 of 1999 regarding Regional Autonomy were passed by the Indonesian parliament in 1999 and further implemented by Government Regulation No.38 of 2007. Law No.22 of 1999 has been revoked by and replaced by the provisions on regional autonomy of Law No.32 of 2004 as amended by Law No.8 of 2005 and Law No.12 of 2008. Law No.32 of 2004 and its amendments were revoked and replaced by Law No.23 of 2014 regarding Regional Autonomy as amended by Government Regulation in Lieu of Law No.2 of 2014, Law No.2 of 2015 and Law No.9 of 2015. Law No.25 of 1999 has been revoked and replaced by Law No.33 of 2004 regarding the Fiscal Balance between the Central and the Regional Governments respectively. 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.

24

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, and will rely on dividends paid by our subsidiaries for our cash needs. Any limitation on the ability of our subsidiaries to make dividend payments to us, or any tax implications of making dividend payments to us, 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. We will rely on dividends paid by our subsidiaries for our cash needs, including the funds necessary to pay dividends and other cash distributions to our shareholders, to service any debt we may incur and to pay our operating expenses. If applicable laws, rules and regulations in Indonesia 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. 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 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.”

25

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 Act (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 shareholder 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.

26

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.

27

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 or other disposition of their shares in the PFIC.

28

Based upon our current and anticipated method of operations, we do not believe that we should be a PFIC with respect to our 2020 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.

On May 28, 2020, the National People’s Congress of the People’s Republic of China approved a proposal to impose a new national security law for Hong Kong and authorized the Standing Committee of the National People’s Congress to proceed to work out details of the legislation to be implemented in Hong Kong (the “Decision”). While the details of the new law are still scarce as of the date of this annual report, there is a risk that the Decision 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, our holding subsidiary which is incorporated in Hong Kong. As the Decision is new and details of the new law unavailable as of the date of this annual report, it is difficult to predict the impact, in any, the new law 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.

Risks Related to Our Ordinary Shares

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.

Although our ordinary are listed on the NYSE American, an active U.S. public market for our ordinary shares may not be sustained. If an active 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 downward fluctuations, which creates the risk of loss of your investment in our ordinary shares.

Our ordinary share price has been 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 the ordinary shares on the NYSE American has been and may in the future fluctuate as a result of several factors, including the following:

● 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;

● 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;

29

● 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 (such as the global novel coronavirus pandemic) 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.

Our auditor’s opinion on our December 31, 2020 financial statements include an explanatory paragraph in respect to there being substantial doubt about our ability to continue as a going concern.

We have experienced net losses of $6,951,698 and $1,673,735, and net cash used in operating activities of $5,186,048 and $439,794 for the years ended December 31, 2020 and 2019, respectively. As of December 31, 2020, we had net current assets of $9,413,594, however, considering our planned level of capital expenditures expected during the next twelve months, there will be an expected capital deficit to occur. These conditions raise substantial doubt about our ability to continue as a going concern, and our auditor’s report on our December 31, 2020 financial statements includes an explanatory paragraph in respect to there being substantial doubt about our ability to continue as a going concern. If additional financing is required to alleviate our capital deficit, we cannot predict whether this additional financing will be in the form of equity, debt, or another form, and we may not be able to obtain the necessary additional capital on a timely basis, on acceptable terms, or at all, from any source. In the event that financing sources are not available, or if we are unsuccessful in increasing our gross profit margin and reducing operating losses, we may be unable to implement our current plans for expansion, repay debt obligations or respond to competitive pressures, any of which would have a material adverse effect on the our business, prospects, financial condition and results of operations. If we cannot continue as a viable entity, our shareholders may lose some or all of their investment in our company.

We may not be able to maintain the listing of our ordinary 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 have no commitments for any financing, and no assurance can be provided that we will be able to raise funds when needed. Further, 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.

30

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, owns and exercises voting and investment control of approximately 70.50 % of our ordinary shares as of the date of this report. In addition, HFO Investment Group, an entity controlled by the adult sister of James J. Huang, our Chief Investment Officer, owns and exercises voting and investment control of approximately 8.72% 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:

● composition of our Board of Directors and, through it, any determination with respect to our business direction and policies, including the appointment and removal of officers;

● any determinations with respect to mergers or other business combinations;

● our acquisition or disposition of assets; and

● our corporate financing activities and the approval of equity incentive plans.

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, 2020. If we fail to remediate this weakness or otherwise develop and maintain an effective system of internal control over financial reporting, we may be unable to accurately report our financial results or prevent fraud.

We have identified a “material weakness” and other control deficiencies including significant deficiencies in our internal control over financial reporting for the year ended December 31, 2020. As defined in the standards established by the Public Company Accounting Oversight Board of the United States, or 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.

31

In connection with the audits of our consolidated financial statements for the years ended December 31, 2020 and 2019, the material weaknesses 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 the remedial measures had not been fully implemented in the limited time that elapsed since our initial public offering in December 2019, our management concluded that one material weakness had not been remediated as of December 31, 2020. See “Item. 15 Controls and Procedures—Internal Control over Financial Reporting.” As a result of the material weakness, our management has concluded that as of December 31, 2020, 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 material weaknesses or significant deficiencies in the future.

Upon completion of our initial public offering, we became 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 our annual reports on Form 20-F beginning with 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, after we become a public company, our reporting obligations may place a significant strain on our management, operational and financial resources and systems for the foreseeable future. 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 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.

32

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 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. 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.

33

Sales of a substantial number of our ordinary shares in the public market by our existing shareholders could cause our share price to fall.

Sales of a substantial number of our ordinary shares in the public market, or the perception that these sales might occur, could depress the market price of our ordinary shares and could impair our ability to raise capital through the sale of additional equity securities. We are unable to predict the effect that sales may have on the prevailing market price of our ordinary shares. All of the ordinary shares owned by our existing shareholders are subject to lock-up agreements with the underwriters of our initial public offering that restrict the shareholders’ ability to transfer our ordinary shares for at least six months from the date of the closing of the offering of the ordinary shares. Substantially all of our outstanding ordinary shares will become eligible for unrestricted sale upon expiration of the lock-up period. In addition, ordinary shares issued or issuable upon exercise of options and warrants vested as of the expiration of the lock-up period will be eligible for sale at that time. Sales of ordinary shares by these shareholders could have a material adverse effect on the trading price of our ordinary shares.

Shares eligible for future sale may depress our stock price.

As of the date of this annual report, we had 7,407,955 ordinary shares outstanding, 6,770,455 of which were held by our affiliates and. In addition, 637,500 ordinary shares were subject to outstanding options granted under certain stock option agreements entered into with our management team. All of the ordinary shares held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act. Sales of 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.

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.

34

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 $1.07 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. 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.

35

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.

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 with an average annual GDP growth of above 5% for the past 10 years, according to the World Bank. Today, Indonesia is the world’s 16th largest economy, a member of the G-20 and the world’s fourth most populous nation with a population of over 262 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-20th 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) Annual Report 2019 and the BP Statistical Review of World Energy 2020, Indonesia held proven oil reserves of 2.5 billion barrels at the end of 2019.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).

36

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 production sharing contract 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) (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.

37

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 Indonesian Crude Price (the “ICP”) for the type of crude oil we produce collapsed by more than 75% and began 2016 at US$25.83 per barrel. Since 2016, political and economic factors forced the global crude oil supply and demand to a balance and ICP rose again to reach the average of US$61.89 for the year ended December 31, 2019. According to Forbes, in the first quarter of 2020, the Covid-19 outbreak had a large impact on oil prices worldwide. As Saudi Arabia increased oil production and lowered prices beginning of March, despite a lack in demand in the wake of the virus outbreak, benchmark oil prices collapsed by 25%. The ICP was depressed to an average price of US$ 37.58 per barrel for the year ending December 31, 2020 which, compared to the year ending December 31, 2019, is a decline of 39.28% (although in the first half of 2021, the average ICP price has risen).

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 the PWC 2020 Guide, investment in the oil and gas industry was around US$12.1 billion in 2019, the highest since 2016 due to the rise in oil and gas prices triggering some investment interest. On a gas reserve basis, as stated in the BP Statistical Review of World Energy 2019 (or the BP 2019 Report), Indonesia ranks 13^th in the world and the 2^nd in the Asia-Pacific region, following China.

According to the DGOG, in 2020, investment of US$10.47 billion has been realized in upstream activities in Indonesia. The SKK Migas Annual Report recorded that at the end of 2019, Indonesia had a total of 199 PSCs, comprising 92 PSCs in production stage and the remaining 107 in the exploration stage. SKK Migas also reported that total investment in 2019 was US$12.2 billion. Roughly 75% of oil upstream activities are focused in Western Indonesia, where our blocks are located. SKK MIGAS also recorded that there are 42 main projects in the upstream sector until 2027. With the total investment amount of US$ 43.3 billion. According to 2020 PWC report, the first half of 2020 investment in upstream oil and gas only reached USD 5.6 billion from the total full year MoEMR target of USD 14.5 billion. Meanwhile, different to the MoEMR, SKK Migas has projected oil and gas upstream investment will only reach USD 11.6 billion in 2020 from the previously forecast USD 13.83 billion, since the COVID-19 pandemic has forced oil and gas companies to cut their capital expenditure. In order to boost oil and gas investment and production, the Indonesian government changed the PSC system in March 2018 from cost recovery to gross split, and further revoked 18 regulations and 23 requirements for certifications, recommendations and permits, each in an attempt to reduce duplication in certification, shorten bureaucracy and simplify the regulatory regime. 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.

According to the BP 2019 Report, Indonesia’s oil consumption in 2018 reached 1.78 million barrels per day, 43% of which was met by domestic production. The MEMR specified that Indonesia exported 74.4 million barrels of oil and imported 113 million barrels of oil in 2018. SKK Migas recorded Thailand and the United States as the top two countries Indonesia exported oil and condensate to in 2018, respectively at 13.65 million barrels and 11.03 million barrels.

38

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 PWC 2017 Report, generating capacity at the end of 2016 was standing at around 59.6 gigawatts, struggling to keep up with the electricity demand from Indonesia’s growing middle class population and its manufacturing sector. The Indonesian Secretariat General of National Energy Council has reported in their Indonesia Energy Outlook 2019 that Indonesia power plant capacity in 2018 reached 64.5 GW or it increased 3% compared to the capacity in 2017. The Indonesian Secretariat General of National Energy Council has reported that Indonesia’s gas demand is estimated to rise from 1.67 TCF in 2015 to 2.45 TCF in 2025 with the bulk of demand originating from Java and Bali, particularly for power stations and fertilizer plants.

According to Indonesia Energy Outlook 2018 report published by the Indonesian Agency for the Assessment and Application of Technology, from 2016 to 2050, with an average Indonesian GDP growth rate of above 5% per year, together with a population growth of 0.71% per year, Indonesia’s total energy demand is expected to grow at an average rate of 5.3% per year. For the same period, natural gas demand average growth rate is estimated at 6.3% per year, industrial sector energy demand average growth rate is expected at 6.1% per year and total electricity demand is expected to increase 740% by 2050. Also, natural gas demand for electricity generation is estimated to continue to increase with an average growth rate of 4.9% per year while the transportation energy demand is expected to grow at an average rate of 4.6% per year.

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. The annual growth of gas transmission and distribution pipeline in 2017 was only 4.7% with 483.57 km of additional pipeline length from 2016. Total gas distribution pipeline infrastructure in 2017 was 10,670.55 km and according to Government plans, by 2030 Indonesia is expected to add a total of 6,989 km of gas pipeline network.

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.

39

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 the recent low oil prices qualified 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.

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.

40

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, Indonesia’s state-owned oil and natural gas corporation, until May 2020 and the operatorship of Kruh Block shall continue as a Joint Operation Partnership (KSO) from May 2020 until May 2030. 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. 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 4.39 million barrels (net crude oil proved reserves of 2.63 million barrels) and probable undeveloped gross crude oil reserves of 2.15 million barrels as of December 31, 2020 determined on a May 2030 contract expiration date. 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.

41

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 is 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 is 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) are advanced by GWN and later repaid to GWN by Pertamina. Pursuant to the Kruh TAC, all the oil produced in Kruh Block is delivered to Pertamina and, subsequently, GWN recovers 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 is 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 is around 74% of the total production times the ICP. On a monthly basis, we submit to Pertamina an Entitlement Calculation Statement (ECS) stating the amount of money that we are 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.

42

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.

As of May 22, 2020, we commenced the continuation of our operatorship of Kruh Block under a KSO contract that has a term until May 2030. 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% (sixty-five percent) 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, 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.

In March 2021, we mobilized the drilling rig to drill 3 back-to-back producing wells at our 63,000 acre Kruh Block. Each of the 3 wells are expected to average production of 173 barrels of oil per day over the first year of production. We anticipate that each well will cost approximately $1.5 million to drill and complete. Based on the terms of our contract with the Indonesian government and an assumed oil price of $63.50/barrel, each well is expected to generate $3.33 million in net revenue in its first year, which is more than double the cost to drill each well. Also in March 2021, we received necessary permits that will allow us to move forward to commence our previously announced drilling plans in 2021 for Kruh Block. In April 2021, we announced that new drilling for these 3 wells had commenced. A total of 5 wells are planned in 2021, 6 wells in 2022 and 7 wells in 2023, for a total of 18 new wells on Kruh Block expected over three years. No assurances can be given that these new wells will generate the amounts of oil we estimate, if any at all.

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, Kruh-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 (Kruh-19) to obtain additional geological information. After seismic data re-interpretation and modelling, we initiated our drilling campaign for 2 wells, Kruh-21 (K-21) and Kruh-22 (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.

43

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 (or 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.

44

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 expenditures 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%. As of December 2020, we have produced a total of 72,524 barrels of oil from the Kruh structure. The production rate is expected to increase given the commencement of new drilling at Kruh Block in April 2021.

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 by 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.

As of December 31, 2020 and 2019, considering the operatorship of Kruh Block ending in May 2030, net proved reserves have a net ratio of approximately 61.13% and 43.55% 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 results in a net proved reserves ratio of 74.37% of total reserves at that point in time. In contrast, as of December 31, 2018, with an assumed extension of the Kruh Block operatorship to May 2030 and with the cost recovery balance reset to zero in May 2020, we estimate that we will be entitled to approximately 42.72% of the revenues from the sales of the crude oil produced throughout the operatorship in Kruh Block until May 2030, considering the cost recovery balance estimations and profit sharing portions throughout the Kruh Block operatorship period, resulting on a net proved reserves ratio of 42.72% of total reserves.

45

Following the confirmation of the Kruh Block extension, our board of directors approved a development plan for a drilling program of 18 Proved Undeveloped Reserves (or PUD) wells at Kruh Block, according to the schedule below:

	Unit\Year	2021		2022		2023		Total
Planned PUD wells	Gross well		5		6		7		18
Future wells costs (1)	US$		7,500,000		9,000,000		10,500,000		27,000,000
Total gross PUD added	Bbls		1,299,469		1,219,638		1,551,413		4,070,520
Total net PUD added	Bbls		794,392		745,589		948,410		2,488,391

(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.

We commenced new drilling operations in Kruh Block in March 2021, and new drilling of 3 wells commenced in April 2021. Our originally anticipated drilling commencement date was delayed due to COVID-19 and the government permitting process.

For Proved Developed (or PDP) reserves, as a result of more effective reservoir management, we produced 72,524 bbls for the year ended December 2020, an increase of 2,687 bbls from our June 2020 estimate, and a decrease of 135 bbls from our December 2019 estimate. Effective oil field maintenance ensures our realization meets production forecast.

The gross oil reserves were reduced from 4,619,992 bbls as of December 31, 2019 to 4,393,408 bbls as of December 31, 2020 mostly due to the production and rescheduling of our drilling plan. As of December 31, 2020, the net reserves were estimated as 2,631,512 bbls using a per barrel crude price of US$37.58 (historical 12-month average price calculated as the average ICP for each month in 2020). In a “cost recovery” system such as the Kruh KSO contract, the production share and net reserves entitlement to our company increases in periods of lower oil prices (61.13% net share for ICP, US$37.58 in year 2020) and decreases in periods of higher oil prices (43.55% net share for ICP, US$66.12 in year 2019). 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, 2020 in Kruh Block:

	Crude Oil Proved Reserves at Kruh Block
Gross Crude Oil Reserves
Gross Crude Oil Proved Developed Producing Reserves (PDP)	Bbl	322,887
Gross Crude Oil Proved Undeveloped Reserves (PUD)		4,070,521
Total Gross Crude Oil Reserves	Bbl	4,393,408
Net Crude Oil Reserves
Net Crude Oil Proved Developed Producing Reserves (PDP)	Bbl	143,120
Net Crude Oil Proved Undeveloped Reserves (PUD)		2,488,392
Total Net Crude Oil Reserves	Bbl	2,631,512

46

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$37.58 (historical 12-month average price calculated as the average ICP for each month in 2020). 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 TAC and KSO economic models.

As of December 31, 2020, Kruh Block had 4 oil producing wells (K-20, K-21, K-22 and K-23 in Kruh field) covering 47 acres. There were 18 proved undeveloped oil locations in Kruh (6), North Kruh (7) and West Kruh (5) field covering 491 acres. In the West Kruh field, there are additional 9 probable locations covering 279 acres. See details on table below.

PDP, PUD and Probable Locations and Acreage for the Kruh Block as of December 31, 2020
Reserves Category	Kruh Field				North Kruh Field				West Kruh Field				Total
	Locations		Acreage		Locations		Acreage		Locations		Acreage		Locations		Acreage
Proved Dev Producing (PDP)		4		58		-		-		-		-		4		58
Proved Undeveloped (PUD)		6		73		7		263		5		155		18		491
Total Proved		10		131		7		263		5		155		22		549
Probable		-		-		-		-		9		279		9		279
Total Proved & Probable		10		131		7		263		14		434		31		828

47

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, 2020:

Gross and Net Developed and Undeveloped Acreage of Kruh Block as of December 31, 2020
	Developed Acreage				Undeveloped Acreage				Total Acreage
Kruh Block	Gross		Net		Gross		Net		Gross		Net
Kruh Field		58		35		73		45		131		80
North Kruh Field		-		-		263		161		263		161
West Kruh Field		-		-		155		95		155		95
Other		-		-		63,204		38,638		63,204		38,638
Total		58		35		63,695		38,939		63,753		38,974

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:

48

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.

49

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.

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.

50

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:

51

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 Production Sharing Contracts (or 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.

52

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). Upon its approval, we will start an Environmental Base Assessment for the region in conjunction with a local university and 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 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 2018, there were a total of 338 exploration wells drilled in Indonesia and 238 out of the 338 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			Total
Total Exploration Wells		96			75			64			33			33			15			22			338
Total Discovery Wells		65			53			47			27			23			10			13			238
Success Ratio		68	%		71	%		73	%		82	%		70	%		67	%		59	%		70	%
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%.

53

In 2020, further technical work in the Citarum block resulted additional 9 prospects and 9 exploration leads (T series prospects and leads on the maps below). 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.

54

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

55

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.

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 2025.

56

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, 2020:

Gross and Net Developed and Undeveloped Acreage of Citarum Block as of December 31, 2020
	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Citarum Block		-		-		969,807		550,317		969,807		550,317
Total		-		-		969,807		550,317		969,807		550,317

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.

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. 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 2020 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. The timeline for the tender is contingent upon the DGOG’s plans and schedule

57

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.

58

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 recently added management team located in the United States consists of our President and Chief Financial Officer. Our President brings 41 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 38 years of financial business experience, mostly as either a chief financial officer or controller, including over 16 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.

59

● 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.

60

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.

61

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.

62

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.

The Omnibus Law amended several provisions of the Oil and Gas Law. However, the changes were relatively limited pending the enactment of the proposed amendments 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.

63

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 2008 on Procedures of Determining and Bidding Oil and Gas Working Areas (or MEMR Regulation 35/2008) 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 35/2008, 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$1,000,000 from a well-known bank domiciled in Jakarta 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.

64

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:

65

● 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.

66

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.

67

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 and lastly by the MEMR Regulation No. 20 of 2019 (MEMR 20/2019), 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 Ministry of Energy and Mineral Resources (MoEMR) 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 No. 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;

68

● 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.

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.

69

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.

70

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.

71

We are a party to a TAC with respect to our operations in Kruh Block, under which we are 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 shall be recovered in the succeeding years. Together with our share split, our monthly revenue is around 74% of the total production times Indonesian Crude Price.

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 Environmental Impact Assessment Report (Analisis Mengenai Dampak Lingkungan, or AMDAL). Minister of Environment and Forestry Regulation No. P.38/MENLHK/SETJEN/KUM.1/7/2019 of 2019 on Types of Business Plan and/or Activities Requiring an Environmental Impact Assessment requires companies whose operations involve the exploitation of oil and gas; pipelines of oil and gas under the sea; the construction of oil refineries, LPG refineries, or LNG refineries; the regasification of LNG; lubricating oil refineries; and coal bed methane field development, 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).

72

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 Environment Information System, a newly established system to support environmental protection operations and management. Government Regulation 101 of 2014 on Management of Hazardous and Toxic Waste Materials and Government Regulation No. 74 of 2001 on Management of Hazardous or Toxic Materials (Bahan Berbahaya dan Beracun), require 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. Law No. 32 of 2009 on Environment 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 (or 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 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 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.

73

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 Decree No. 31 of 2013 on Expatriate Utilization and the Development of Indonesian Employees in the Oil and Gas Business (or MEMR Decree 31/2013). MEMR Decree 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 Decree 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 Regulation 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 Regulation 6/2018 revokes MEMR Decree 31/2013 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.

74

Contract Period

Law No. 13 of 2003 on Manpower, as amended by the Omnibus Law (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 type 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).

75

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.

Other Labor Compliance Obligations

Under Law No. 8 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 two major shareholders: Maderic Holdings Limited (or Maderic) and HFO Investment Group (or HFO), own 70.50% and 8.74%, respectively, of our issued and outstanding ordinary shares. Certain of our officers and directors or their family members own and control Maderic or HFO (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, 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.

76

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 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 existing shareholders’ 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 the date of this report, Maderic owns 70.50% of our issued and outstanding shares, while HFO owns approximately 8.74 % of our issued and outstanding shares. As of the date of this report, we have 7,407,955 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:

77

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.

Corporate Information

Our principal executive offices are located at Gedung Graha Anugerah, Jl. Raya Pasar Minggu No. 17A, Kelurahan Pancoran, Kecamatan Pancoran, Jakarta Selatan 12780 - Indonesia. Our telephone number at this address is +62 21 576 8888. 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.

78

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 produce oil through our subsidiary GWN, which is a party that we acquired in 2014 and operates the Kruh Block, under a Technical Assistance Contract (or TAC) with PT Pertamina (Persero) (or Pertamina) until May 2020. GWN shall continue the operatorship of the block from May 2020 until May 2030 under a Joint Operation Partnership (or KSO) with Pertamina. Kruh Block covers an area of 258 km² (63,753 acres) and is located onshore 16 miles northwest of Pendopo, Pali, South Sumatra. The TAC contract is based on a “cost recovery” system, in which all operating costs (expenditures made and obligations incurred in the exploration, development, extraction, production, transportation, marketing, abandonment and site restoration) are advanced by GWN upon occurrence and later reimbursed to GWN by Pertamina based on certain agreed conditions, which are described elsewhere in this annual report.

Our reserves estimate of 3 fields (Kruh, North Kruh and West Kruh) within the Kruh TAC 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 3 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 United States Securities and Exchange Commission (or 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.

79

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 Operating 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.		43		12	-	33	22
Djoko Martianto	Petroleum Engineering	B.S.		41		31	12	-	10
Denny Radjawane	Geophysics	M.S.		30		12	-	20	14
Fransiska Sitinjak	Petroleum Engineering	M.S.		17		7	12	-	8
Yudhi Setiawan	Geology	B.S.		18		12	4	6	3
Oni Syahrial	Geology	B.S.		14		-	-	14	8
Juan Chandra	Geology	B.S.		15		-	-	15	9

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.

80

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 on 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. 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 is recognized based on the prevailing ICP through GWN from the 65% (sixty-five percent) of monthly proceeds as monthly cost recovery entitlement plus 26.7857% (twenty six point seven eight five seven percent) of the remaining proceeds from the sale of the crude oil after monthly cost recovery entitlement as part of the profit sharing. For the 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 are also entitled to an additional 23.5294% (twenty-three point five two nine four percent) of the remaining 20% of such sales proceeds as part of the profit sharing. 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 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% (sixty-five percent) 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 were reset to nil with the commencement of the operatorship under the KSO in May 2020.

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 2019 and 2018 was the volatility in the price of crude oil. For the year ended December 31, 2020, ICP decreased to an average of $37.58 per Bbl., 39.28% lower when compared to the ICP average of $61.89 per Bbl. for the year ended December 31, 2019, which reduced the financial performance of our company in 2019.

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 March 2021 and new drilling commenced in April 2021. The reserve estimate will be updated in mid-2021 after new production begins in the second quarter of 2021.

81

Key Components of Results of Operations

For the years ended December 31, 2020 and 2019

Financial and operating results for the year ended December 31, 2020 compared to the year ended December 31, 2019 are as follows:

● Total oil production decreased approximately 20.29%, from 90,989 Bbl. for the year ended December 31, 2019 to 72,524 Bbl. for the same period in 2020, which resulted in lower revenue and cost recovery entitlements for the year ended December 31, 2020 than for the same period in 2019. This decrease was due to the decrease of the reservoir pressure which comes naturally in the primary recovery production phase for our four existing wells.

● ICP decreased 39.28% from an average price of $61.89 per Bbl. for the year ended December 31, 2019 to $37.58 per Bbl. for the same period in 2020, reducing our revenue and cost recovery entitlements. 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.

● Revenue decreased by $2,202,581, or 52.65%, from $4,183,354 for the year ended December 31, 2019 to $1,980,773 for the same period in 2020 due to a combination of lower ICP and lower production.

● General and administrative expenses increased by $4,099,543 or 168.42%, for the year ended December 31, 2020 when compared to the same period in 2019. Major expenses for the years ended December 31, 2020 were employee salary (including share-based compensation expense), professional fees, director and officer insurance expense, and travel expenses.

82

● The amount of lease operating expenses decreased by approximately $456,374 or 18.45%, for the year ended December 31, 2020 when compared to the same period in 2019 mainly because of the decline in production in Kruh Block.

● We incurred net loss of $6,951,698 for the year ended December 31, 2020 from a net loss of $1,673,735 for the same period in 2019 due to a combination of the factors stated above.

● The average production cost per barrel of oil for the year ended December 31, 2020 was $27.82 compared to $21.34 for the year ended December 31, 2019, computed using production costs disclosed pursuant to FASB ASC Topic 932 and only to exclude ad valorem and severance taxes, an increase of 30% due to a combination of the factors discussed above.

For the years ended December 31, 2019 and 2018

Financial and operating results for the year ended December 31, 2019 compared to the year ended December 31, 2018 are as follows:

● Total oil production decreased approximately 23.55%, from 119,017 Bbl. for the year ended December 31, 2018 to 90,989 Bbl. for the same period in 2019, which resulted in lower revenue and cost recovery entitlements for the year ended December 31, 2019 than for the same period in 2018. This decrease was due to the decrease of the reservoir pressure which comes naturally in the primary recovery production phase for our four existing wells.

● ICP decreased 6.40% from an average price of $66.12 per Bbl. for the year ended December 31, 2018 to $61.89 per Bbl. for the same period in 2019, reducing our revenue and cost recovery entitlements. The ICP, that correlates to the international crude oil price, is determined by MEMR. Throughout 2019, 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.

● Revenue decreased by $ 1,672,987, or 28.57%, from $ 5,856,341 for the year ended December 31, 2018 to $ 4,183,354 for the same period in 2019 due to a combination of lower ICP and production.

● General and administrative expenses increased by $417,989, or 20.73%, for the year ended December 31, 2019 when compared to the same period in 2018. Major expenses for the years ended December 31, 2019 and 2018 were $824,780 and $693,332 in legal and other professional expenses associated with our initial public offering, which was consummated in 2019, $829,577 and $922,377 in salaries and employee benefits, and $247,817 and nil in share-based compensation, respectively.

83

● The amount of lease operating expenses decreased by approximately $66,123 or 2.60%, for the year ended December 31, 2019 when compared to the same period in 2018 mainly because of the decline in production in Kruh Block.

● We incurred net loss of $1,673,735 for the year ended December 31, 2019 from a net income of $140,988 for the same period in 2018 due to a combination of the factors stated above.

● The average production cost per barrel of oil for the year ended December 31, 2019, was $27.19 compared to $21.34 for the year ended December 31, 2018, computed using production costs disclosed pursuant to FASB ASC Topic 932 and only to exclude ad valorem and severance taxes, an increase of 27.40% 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 lessens 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.

A decline in oil and gas prices (including as was experienced in the first quarter of 2020) (i) will reduce our internally generated cash flow, which in turn will reduce the funds available for exploring for and replacing oil and gas capitalized property, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas capitalized property in relation to the costs of exploration, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

The global outbreak and pandemic of the novel coronavirus (COVID-19) in 2020, including in Indonesia, has and may continue to impact our operations, which might affect our total oil production. Since the outbreak, crude oil prices have been negatively impacted to a significant extent due to low oil demand, increased production and disputes between the Organization of the Petroleum Exporting Countries (or OPEC) and Russia on production cuts. As a consequence, our revenue and profit is expected to decrease due to the factors discussed above, and other unforeseen and unpredictable consequences of the COVID-19 outbreak.

84

Further, in the first half of 2020 there was a sharp decline in commodity prices following the announcement of price reductions and production increases in March 2020 by members of OPEC, which has led to significant global economic contraction generally and in the oil and gas exploration industry in particular. Together with the COVID-19 pandemic, it is unclear and not predictable the long lasting effects on global energy prices and our results of operations and financial condition. Please see the Risk Factor entitled “The outbreak of COVID-19 and volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects.”

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 March 2021 and new drilling commenced in April 2021. The reserve estimate will be updated in mid-2021 after new production begins in the second quarter of 2021.

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, 2020, 2019 and 2018:

	For The Years Ended
	December 31,		December 31,		December 31,
	2020		2019		2018
Revenue	$	1,980,773	$	4,183,354	$	5,856,341
Lease operating expenses		2,017,856		2,474,230		2,540,353
Depreciation, depletion and amortization		698,851		876,676		1,156,494
General and administrative expenses