Oil and natural gas development entails the risk that operational accidents and disasters may occur in the process of exploration, development, production and transportation. Various information systems are used in operations. While safety measures are in place for these systems, there is the risk that operations may be suspended due to unforeseen failures of these systems caused by events such as natural disasters and cyberattacks. Should such an unforeseen failure of information systems, or an accident, disaster or other such incident occur, there is the risk that costs may be incurred, excluding compensation covered by insurance, due to infrastructural damage, as well as the risk of a major accident or disaster involving loss of life. In addition, a cost for recovery or opportunity loss from the interruption of operations could occur.

Furthermore, labor disputes in projects that the Group is involved in or the spread of infectious diseases such as COVID-19 may lead to a shortage of employees required for operations and other necessities, difficulty in procuring materials, equipment and services as well as transportation of produced goods, instructions or orders from the governments of oil-producing countries to suspend operations, changes in the policies of partners in a joint business and other developments. Such events may fully or partly suspend or delay operations.

For its domestic natural gas business, the Company has continued to procure natural gas regasified from imported LNG as source gas since January 2010. Furthermore, the Company has manufactured regasified LNG from imported LNG at Naoetsu LNG Terminal from August 2013. An inability to procure natural gas regasified from imported LNG and other imported gas as source gas due to issues concerning suppliers or the Company’s Naoetsu LNG Terminal, an inability to produce domestic gas due to issues in the domestic gas field, or compromised pipeline operations due to accidents or disasters along the pipeline network, may interfere with the Company’s ability to supply its customers. This could in turn have an adverse effect on the Company’s domestic natural gas business.

With regard to environmental problems, there is a possibility of soil contamination, air pollution, and freshwater and seawater pollution. The Group has established a “Health, Safety and Environment Policy,” and as a matter of course abides by the environmental laws, regulations, and standards of the countries in which we operate and give due consideration to the environment in the conduct of business, based on our independent guidelines. In the event of an operating accident or disaster which impacts the environment, there is the possibility of incurring a response or cost burden for recovery from that incident, of incurring obligation of payment for procedural costs, compensation or other cost related to the start of civil, criminal or government procedures, or of incurring loss from the interruption of operations. Furthermore, in the event of changes to or the strengthening of the environmental laws, regulations, and standards (including support measures for the promotion of new, renewable energies) of the countries in which we operate, it may be necessary for the Group to devise additional measures with an associated cost burden and it could affect on the financial results of the Group.

The Company strives to prevent accidents and incidents from happening to avoid these risks of disasters, accidents, system failures and other developments from materializing. However, risks are always present, and if they materialize, they may have a significantly adverse effect on the Group’s results.

Although the Group maintains insurance against loss or damage in the natural course of its operations to a reasonable extent, insurance may not cover all damages. Also, such accidents or issues could result in administrative sanctions or damage the Group’s credibility and reputation as an oil and natural gas development company, and could therefore have an adverse effect on future business activities.

The Group engages in stable production of crude oil and natural gas in the Ichthys gas-condensate field (Australia), the onshore and offshore Abu Dhabi oil fields (United Arab Emirates), the Minami Nagaoka Gas Field (Japan) and so on. The areas in which the Group operates are spread broadly throughout Asia-Oceania (particularly Japan, Indonesia and Australia), the Middle East and Africa, Eurasia including the Caspian Sea area and the Americas. For fiscal 2022, however, the Asia and Oceania region accounted for about 40% of the Group’s production volume and the Middle East and Africa region accounted for about 43%, with these two regions making up the vast majority of the Group’s operations.

The Group currently relies heavily on specific geographical areas and assets for its production volume, and the occurrence of operational issues at these assets could have an adverse effect on the Group’s operational results.

Expiration dates are often stipulated in the agreements related to participating interests, which form the basis of the Group’s overseas business activities. Should an agreement in which an expiration date is stipulated not be extended, re-extended or renewed, or should the terms and conditions be less favorable (including a reduction in the proportion of the Group’s interest) than those existing at the time of extension, re-extension or renewal, there could be an adverse effect on the Group’s results. INPEX Group policy to work with our business partners toward the extension, re-extension or renewal of these agreements, should an existing agreement not be extended, re-extended or renewed as a result of agreement negotiations with the national petroleum company of an oil-producing country, or in the event of agreement terms and conditions (including a reduction in the Group’s participating interest) that are more disadvantageous than the situation at the time of the extension, re-extension or renewal, this could have an adverse effect on the Group’s business or results. Even should the agreements stipulating expiration dates be extended, re-extended or renewed, we anticipate that the remaining recoverable reserves at that time will have decreased due to production developments. Although the Group is striving to acquire interests that can substitute these properties, failure to acquire participating interests in oil and gas fields to fully substitute for these properties could have an adverse effect on the Group’s results. In addition, the period for exploration in oil and gas fields currently under exploration is fixed by contracts, and in the case of fields where oil and/or gas reserves are found that are deemed to be commercialized, and the Company is unable to decide on the transition to the development stage by the expiration of the current contract, efforts will be made through negotiations with the government of the oil- or gas-producing country in question to have the periods extended. However, there remains the possibility that such negotiations may not be successfully concluded, in which event the Company would be forced to withdraw from operations in the oil or gas field concerned. Also, as a rule, when there has been a major breach of contract on the part of one party, it is customary for the other party to have the right to cancel the agreement before the expiration date. The agreements for properties in these principal geographical business areas contain similar provisions. The Group has never experienced early cancellation of an agreement due to breach of contract, and we do not anticipate such an occurrence in the future. Nevertheless, a major breach of contract on the part of a party to an agreement could result in cancellation of an agreement before the expiration date.

And in natural gas development and production activities, in many cases we are selling and supplying gas based on long-term sales and supply contracts in which expiration dates are stipulated. We plan to make efforts with partners to extend or re-extend the expiration date before the deadline stipulated in these contracts. Nevertheless, inability to extend the contracts, or the occurrence of cases in which extension is made but sales and supply volumes are reduced, could have an adverse effect on the Group’s business or results. Furthermore, the Company may need to purchase or procure additional natural gas from a third party due to events such as changes in the sales terms during the sales or supply contract period, full or partial suspension or delay of project operations or unexpected changes in demand. This could have an effect on the Group’s business or results.

INPEX CORPORATION (the “Company”) commissioned DeGolyer and MacNaughton, an independent petroleum engineering consultant in the United States, to assess the main proved reserves of the Group of which projects with a significant amount of future development investment might materially affect future performance. An assessment of other projects was undertaken by the Company. The definition of proved reserves is based on the U.S. Securities and Exchange Commission’s (SEC) Regulation S-X, Rule 4-10(a), which is widely known among U.S. investors. Regardless of whether the deterministic approach or probabilistic approach is used in evaluation, proved oil and gas reserves are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions, from the date of evaluation through to the expiration date of the agreement granting operating rights (or in the event of evidence with a reasonable certainty of agreement, extension through to the expiration of the projected extension period). For definition as “proved reserves,” operators must have a reasonable degree of certainty that the recovery of hydrocarbons has commenced or that the project will commence within an acceptable period of time. This definition is widely regarded as being conservative. Nevertheless, the strictness of the definition does not imply any guarantee of the production of total reserves during a future production period. In this context, when probabilistic methods are employed, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the sum of estimated proved reserves.

For further details on proved reserves of crude oil, condensate, LPG and natural gas held by the Group, including equity-method, affiliates accounted please see the section “Oil and Gas Reserves and Production Volume” on P. 115 of our Integrated Report 2022.

A reserve evaluation depends on the available geological and engineering data from oil and gas reservoirs, the maturity of development plans and a considerable number of assumptions, factors and variables including economic conditions as of the date such an estimate is made. Reserves may be revised in the future on the basis of geological and engineering data as well as development plans and information relating to changes in economic and other conditions made newly available through progress in production and operations. As a result, there is a possibility that reserves will be restated upwards or downwards. As to the reserves under a PSC, not only production, but also oil and gas prices, investments, recovery of investments due to contractual conditions and remuneration fees may affect the economic entitlement. This may cause reserves to increase or decrease. In this way, the assessed value of reserves could fluctuate because of various data, assumptions and changes of definition.

In the oil and natural gas development business, companies frequently form business partnerships for the purpose of the dispersion of risk and financial burden. In such partnerships, one of the companies becomes the operator, which performs the actual work and bears the responsibility for operations on behalf of the partners. The companies other than the operator, as non-operators, participate in the business by providing a predetermined amount of funds and either carefully examining the exploration and development plan devised and implemented by the operator, or participating in some operations.

The Group intends to actively pursue operator projects, focusing on the large-scale Ichthys LNG and other projects taking into consideration the effective application of business resources as well as the balance between operator and non-operator projects, based on the Group’s knowhow and technical capability, which has been acquired through considerable operational experience at each of the exploration, development and production stages. The Company has significant expertise as an operator in the development and production of crude oil and natural gas both in Japan and overseas as well as a wealth of know-how and knowledge accumulated over many years as a participant in LNG and other projects in such countries as Indonesia and Australia. In addition, we believe that by utilizing the services of specialized subcontractors and highly experienced external consultants, a practice similar to foreign oil companies including the majors, it will be possible to execute business appropriately as an operator including LNG projects.

Engaging in project coordination as an operator contributes to the expansion of opportunities in acreage acquisition through enhancement of technical capabilities and greater presence in oil-producing countries and the industry. At the same time, there are risks such as constraints on the recruitment of personnel with specialized operational skills and an increase in financial commitments. Inability to adequately cope with such risks could have an adverse effect on the Group’s operational results.

In the oil and natural gas development business, as previously mentioned, several companies often engage in joint business for the purpose of dispersion of risk and financial burden. In such cases, the partners generally enter into a joint operating agreement among themselves to decide on the decision-making procedure for execution of the joint business, or to decide on an operator that conducts business on their behalf. A company that is a partner in one property in which the Group is engaged in joint business may become a competitor in the acquisition of other participating interests, even though the relationship with the partner may be good.

In undertaking the joint business, participants in principle bear a financial responsibility in proportion to their interest share. Any inability of a joint business partner to fulfill this financial responsibility may adversely affect the project.

Considerable time and expense is required for exploration activities. Even when promising resources are discovered through exploration, substantial expenses including production facility construction costs, and an extended period of time, are necessary at the development stage leading up to production. For this reason, a long period of 10 years or more is required from the time of exploration and development investment until the recovery of funds through production and sales. In particular, the large-scale LNG projects require a very large amount of investment, and the financing of these projects could be impacted by changes in the economic and financial environment. Following the discovery of resources, a delay in the development schedule or the loss of the economic viability of the properties during the development process leading up to production and the commencement of sales could have an adverse effect on the Group’s operational results. Such delays or losses may occur due to changes in the business environment including a delay in the acquisition or modification of government approvals, the occurrence of unanticipated problems related to geological conditions, fluctuations in the price of oil or gas, fluctuations in foreign exchange rates, or escalating prices of equipment and materials. In the case of LNG projects, such delays or losses may occur due to an inability to complete such procedural requirements as FID owing to the lack of any long-term contractual agreement with prospective purchasers with respect to production.

The Group books in its accounts, as an asset retirement obligation, the estimated present value of costs related to mine abandonment that will become necessary after finishing operation and production in oil and gas production facilities and the like in accordance with agreements with the authorities of oil-producing countries, applicable laws and regulations and the like. If it is later found that the estimated present value of those costs falls short due to a change in the procedures used for mine abandonment, a rise in expenses for procuring drilling materials and equipment or any other reason, the Group will be required to increase the amount of that asset retirement obligation, which could adversely affect the financial condition and results of operations of the Group.

Crude oil prices and natural gas prices at our overseas businesses are largely determined by international market conditions. In addition, these prices fluctuate significantly due to the influence of a variety of factors including global and regional supply and demand (including a growing downward pressure on demand due to the shift towards a net zero carbon society), trends and conditions in the global economy (including the impact of the contraction of economic activity due to the global pandemic) and financial markets as well as trends in the policies of oil-producing countries and agreements between oil-producing countries on production volume and other matters. The vast majority of these factors are beyond the control of the Company. In this regard, INPEX is not in a position to accurately predict movements in future crude oil and natural gas prices. The Group’s sales and profits are subject to the effects of such price fluctuations. A fluctuation of US$1 in the price of crude oil is expected to have a ¥6 billion impact on the Group for the year ending December 31, 2023, as estimated at the beginning of the fiscal period. Such effects are highly complex and are caused by the following factors.

1. 1. Although a majority of natural gas selling prices in overseas businesses are linked to crude oil prices, they are not in direct proportion to crude oil prices.
2. 2. Because sales and profits are determined on the basis of crude oil prices and natural gas prices at the time sales are booked, actual crude oil transaction prices and the average oil price during the accounting period do not necessarily correspond.

Moreover, although the Company is taking measures to reduce a portion of the risks associated with crude oil price fluctuations, these measures by no means cover all possible risks. As a result, the impact of fluctuations in crude oil prices cannot be completely eliminated.

Since the natural gas business in Japan uses domestically produced natural gas and imported LNG as feedstock, changes in the market price for LNG have an effect on feedstock prices and sales prices. There is also the possibility that changes in the competitive environment associated with electric power and gas system reforms will have an effect on natural gas sales prices and sales volumes.

Also, should the recovery of an amount invested in a business asset held by the Group be no longer expected—due to a decrease in profitability associated with changes in the business environment on the basis of changes in future market conditions— since the Group would reduce that business asset’s book value to reflect the level of recoverability and the amount of that reduction would be deemed impairment loss, there is the possibility that there could be an adverse effect on the Group’s results of operations.

As most of the Group’s business consists of E&P conducted overseas, associated revenues (sales) and expenditures (costs) are denominated in foreign currencies (primarily in U.S. dollars), and profit and loss is subject to the effects of the foreign exchange market. In the event of appreciation in the value of the yen, yen-denominated sales and profits decrease. Conversely, in the event of depreciation in the value of the yen, yen-denominated sales and profits increase.

On the other hand, when borrowing necessary funds, the Company borrows in foreign currencies. In the event of appreciation in the value of the yen, a foreign exchange gain on foreign-currency denominated borrowings is recorded as a result of fiscal year-end conversion; in the event of depreciation in the value of the yen, a foreign exchange loss is incurred. For this reason, the exchange risk associated with the above business is diminished and the impact of fluctuations in exchange rates on profit and loss tends to be mitigated. A ¥1 appreciation/depreciation against the U.S. dollar is expected to have a ¥3.2 billion impact on the Group for the year ending December 31, 2023. Moreover, although the Company is taking measures to reduce a portion of the risks associated with movements in foreign currency exchange rates, these measures by no means cover all possible risks. As a result, the impact of fluctuations in foreign currency exchange rates cannot be completely eliminated.

The Group raises some of its business capital through borrowing. Much of these borrowings are variable-rate long term borrowings in U.S. dollars. Accordingly, the Company’s profits are subject to the influence of fluctuations in U.S. dollar interest rates. Furthermore, although the Group has devised methods to reduce a portion of interest rate risk, these methods do not cover all risks of interest rate fluctuation incurred by our Group and do not entirely remove the effect of fluctuations in interest rates.

In order to achieve the goals of the Paris Agreement and amid growing interest in addressing climate change on a global scale, efforts are being made worldwide to reduce greenhouse gas (GHG) emissions, which are recognized as the cause of climate change and global warming. The Group identifies, assesses and manages climate change risks in line with the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD), and specifically recognizes the following risks. The potential for these climate change risks materializing is expected to grow over the medium to long term, and if they do, they could have an adverse effect on the Group’s performance.

In the event that the countries and regions where the Group operates strengthen climate change actions based on the Paris Agreement or other accords, making changes or enhancements to environmental laws, regulations or standards, including carbon pricing systems such as emissions trading and carbon taxes, the Group would be required to implement additional measures and, in turn, incur financial commitments that could have an adverse effect on the Group’s performance.

If demand for the Group’s oil and natural gas products declines as a result of accelerated progress in low-carbon related technologies and increased price competitiveness of low-carbon products, or due to a preference for low-carbon energy, this may have an adverse effect on the Group’s business and performance.

If investors and financial institutions place more importance than in the past on direct and indirect GHG emissions from the Group’s business as an evaluation item for climate change risk in investment and financing, the Group’s financing and its related terms and conditions may be adversely affected.

Acute risks due to extreme meteorological phenomena such as tropical cyclones and floods, and chronic risks such as rises in average temperature and sea levels over the long term may adversely affect the operations of the Group’s facilities.

The Group engages in a large number of oil and natural gas development projects overseas. Because the Group’s business activities, including the acquisition of participating interests, are conducted on the basis of contracts with the governments of oil-producing countries and other entities, steps taken by oil-producing countries to further tighten controls applicable to home country natural resources, suspension of operation due to conflicts and other factors, and other such changes in the political, economic, and social circumstances in such oil-producing countries or neighboring countries (including international disputes, government involvement, stage of economic development, economic growth rate, capital reinvestment, resource allocation, restriction of economic activities by global community, government control of foreign exchange or foreign remittances, and the balance of international payments), the application of production ceilings in OPEC + member countries and changes in the legal system and taxation system of those countries (including the establishment or abolition of laws or regulations and changes in their interpretation or enforcement) as well as lawsuits could have a significant impact on the Group’s business or results unless the impact is compensated by insurance. Additionally, against the background of rising development costs and other changes in the business environment, the progress of oil and gas projects and the need to address environmental issues, the governments of oil-producing countries may seek to renegotiate the fiscal conditions including conditions of existing oil contracts related to participating interests. In the event that fiscal conditions of contracts are altered, this could have an adverse effect on the Group’s business performance.

In order to respond to the risks listed in items 1 through 4 above, we have introduced guidelines for economic and risk evaluation we conduct on a per-project basis and are recognizing major risks. 　
　When acquiring new projects in the upstream oil and natural gas business, the New Ventures & Global Exploration Division centrally analyzes and examines whether to take on new projects, and takes action against these risks in cooperation with related departments. For existing projects, the INPEX Value Assurance System (IVAS) Committee works as a cross-organizational mechanism mainly for technical evaluation at each project phase, such as exploration, evaluation and development. At the same time, we conduct economic and risk evaluation in principle at least once a year. For major projects, we report a summary of risk evaluation results to the Board of Directors each year. Regarding the renewable energy business and the hydrogen/CCUS business, the Renewable Energy & New Business Division and the Hydrogen & CCUS Development Division coordinate their respective businesses overall, conduct economic evaluation, and evaluate risks and take action against them. When acquiring new projects, the INPEX Value Assurance System (IVAS) Committee and external experts conduct verifications, and a summary of risk evaluation results is reported at Board of Directors Meetings for important projects.
We strive to actively manage risks related to our business in general through measures including formulating and maintaining an emergency/crisis response plan and conducting regular emergency response drills at ordinary times, to enhance our ability to respond to emergency situations caused by events such as major accidents and disasters. In addition, we have formulated a Business Continuity Plan (BCP) and review it as appropriate to prevent important operations from being interrupted. We have been implementing our BCP and taking necessary measures including working from home since 2020 due to the spread of COVID-19. At the same time, we have set up the Corporate Crisis Management Team to assess the state of the entire company including overseas offices.
Furthermore, the Information Security Committee meets both on a regular basis and as needed, taking action on information security on an organizational and systematic basis, as well as conducting education and training including prevention of information leakage.
To manage health, safety and environment (HSE) risk, we strive to continuously improve health and safety, process safety and environmental conservation in our business activities by identifying, analyzing and evaluating HSE risks for each business site based on the HSE Risk Management Procedure established under the HSE Management System. While establishing and implementing measures to address risks, we monitor HSE risks by ensuring that headquarters regularly receives and reviews risk management status reports. We are also working on the company-wide management of security-related risks based on the relevant guidelines and standards. For non-operator projects as well, we are increasing our involvement in their HSE management according to the risks of each project.
We conduct financial risk management regarding crude oil and natural gas prices, currency exchange rates, interest rates and securities prices by identifying their respective risks associated with fluctuations and establishing corresponding management and hedging methods.
To tackle climate change, we have set our goal of achieving net zero carbon emissions by 2050 in line with the Paris Agreement objectives. Towards this goal, the Group will actively promote five business pillars to offer solutions responding to the needs of society in an age of transformation towards a net zero carbon society. Specifically, we will (1) develop a hydrogen business, (2) reduce CO2 emissions from the oil and gas business (promotion of CCUS, etc.), (3) enhance and emphasize renewable　energy initiatives, (4) promote carbon recycling and cultivate new business opportunities and (5) promote forest conservation. By actively promoting these 5 net zero businesses, we will proactively respond to the shift towards a net zero carbon society and aim to be a pioneer of energy transformation.
We manage country risk by, among others, establishing guidelines for handling country risks in the countries where we operate, including setting a maximum target amount of accumulated investments in high-risk countries.
Furthermore, we have developed a mechanism to counter legal risk by establishing the Legal Unit as an independent organization that can provide appropriate legal guidance to business divisions and management regarding matters such as important agreements and lawsuits. Legal support services have also been expanded for operations in Japan and abroad.
Although we strive to manage risks and mitigate their impact by taking these countermeasures, they by no means cover all possible risks. As a result, the impact from individual events cannot be completely eliminated.

The Group has entered into production sharing contracts with countries including Indonesia and Caspian Sea area, and therefore holds numerous participating interests in those regions.

Production sharing contracts are agreements by which one or several oil companies serve as contractors that undertake at their own expense exploration and development work on behalf of the governments of oil-producing countries or national oil companies and receive production from the projects as cost recovery and compensation. That is to say, when exploration and development work results in the production of oil or natural gas, the contractors recover the exploration and development costs they incurred by means of a share in the production. The remaining production (crude oil and gas) is shared among the oil-producing country or national oil company and the contractors according to fixed allocation ratios. (The contactors’ share of production after cost recovery is called “profit oil and gas.”) On the other hand, in cases when exploration fails and expected production is not realized, the contractors are not to recover their invested funds.

When a company in the Group owns participating interests under production sharing contracts, as mentioned above, in the role of contractor it invests technology and funds in the exploration and development of the property, recovers the invested costs from the production produced, and receives a share of the remaining production after recovery of invested costs as compensation.

Costs invested on the basis of production sharing contracts are recorded on the balance sheet as assets for which future recovery is anticipated under the item “Recoverable accounts under production sharing.” After the start of production, recovered costs on the basis of those agreements are deducted from this balance sheet item.

As production received under production sharing contracts is divided into the cost recovery portion and the compensation portion, the method of calculating cost of sales is also distinctive. That is to say, the full amount of production received is temporarily charged to cost of sales as the cost of received production, and subsequently the amount of the compensation portion is calculated and this amount is booked as an adjustment item to cost of sales (“Free of charge production allocated”). Consequently, only the cost recovery portion of production after deduction of the compensation portion is booked as cost of sales.

Although the government of Japan (the Minister of Economy, Trade and Industry) holds 21.19 of the Company’s common shares issued (excluding treasury shares) and a Class A Stock as of March 28, 2022, the Company autonomously exercises business judgment as a private corporation. There is no relationship of control, such as through the dispatch of officers or other means between the Company and the Japanese government. Moreover, we believe that no such relationship will develop in the future. Furthermore, there is no concurrent posting or secondment to the Company of officers or employees from the Japanese government.

The Ministry of Economy, Trade and Industry (METI) holds 21.19% of the Company’s common shares issued (excluding treasury shares). METI succeeded to the shares that had been held by Japan National Oil Corporation (JNOC) following the dissolution of JNOC on April 1, 2005. With regard to the liquidation and disposition of the oil and gas upstream assets owned by JNOC, the Policy Regarding the Disposal of Oil and Gas Development-Related Assets Held by Japan National Oil Corporation (hereinafter, the “Report”) was announced on March 18, 2003 by the Japan National Oil Corporation Asset Evaluation and Liquidation Deliberation Subcommittee of the Advisory Committee on Energy and Natural Resources, an advisory body of the Ministry of Economy, Trade and Industry. The Report describes the importance of appropriate timing in selling the shares on the market, taking into consideration enterprise value growth. In addition, METI may, in accordance with the Supplementary Provision Article 13 (1) 2 of the “Special Measures Act for Reconstruction Finance Keeping After the Great East Japan Earthquake” (“the Reconstruction Finance Keeping Act“ (provisional translation, the same shall apply hereinafter)) enacted December 2, 2011, sell off the Company’s shares in Japan or overseas after examining the possibility of disposal of the said shares based on a review of the holdings from the perspective of energy policy. This could have an impact on the market price of the Company’s shares.

METI also holds one share of the Company’s Class A Stock. As the holder of a Class A Stock, METI possesses veto rights over certain resolutions of the Company’s general shareholders’ meetings and meetings of the Board of Directors. For details on the Class A Stock, please refer to “4. CLASS A STOCK” on P. 113 of our Annual Report 2021.

In the aforementioned Report, INPEX CORPORATION (prior to the integration with Teikoku Oil; reorganized on October 1, 2008) was identified as a company that should comprise part of a core company, and is expected to play a role in efficient realization of a stable supply of energy for Japan through the involvement by a national flagship company. In response to the Report, the Company (also, the Group since our acquirement of Teikoku Oil on October 1, 2008) has sought to promote efficient realization of a stable supply of energy for Japan while taking advantage of synergy with the efforts of active resource diplomacy on the part of the Japanese government, and has aimed to maximize shareholder value by engaging in highly transparent and efficient business operations.

As a result, with regard to the integration by means of transfer of shares held by JNOC proposed in the Report, INPEX CORPORATION and JNOC concluded the Basic Agreement Concerning the Integration of Assets Held by JNOC into INPEX CORPORATION of February 5, 2004 (hereinafter the “Basic Agreement”) and a memorandum of understanding related to Basic Agreement (hereinafter “MOU”). On March 29, 2004, INPEX CORPORATION and JNOC entered into related contracts including the Basic Contract Concerning the Integration of Assets Held by JNOC into INPEX CORPORATION (hereinafter the “Basic Contract”), achieving the agreement on the details including the treatment of the project companies subject to the integration and shareholding ratios.

In 2004 INPEX CORPORATION accomplished the integration of Japan Oil Development Co., Ltd. (JODCO), INPEX Java Ltd. (disposal was completed on September 30, 2010) and INPEX ABK, Ltd. which are three of four companies covered by the Basic Agreement. Although INPEX Southwest Caspian Sea Ltd. (now INPEX Southwest Caspian Sea, Ltd.) would become a wholly owned subsidiary of INPEX CORPORATION by means of a share exchange and the procedures were undertaken, the share exchange contract was invalidated owing to failure to accomplish the terms and conditions of the share exchange contract and the planned share exchange was cancelled. Following the dissolution of JNOC on April 1, 2005, the Minister of Economy, Trade and Industry succeeded to the INPEX Southwest Caspian shares held by JNOC. The Company continues to study the possibility to acquire the shares. However, the METI’s future treatment of these shares is undecided and, depending on the result of review in accordance with the Reconstruction Finance Keeping Act, acquisition of INPEX Southwest Caspian shares could be unavailable.The treatment of Sakhalin Oil and Gas Development Co., Ltd. (hereinafter “SODECO”), INPEX Masela, Ltd., INPEX North Caspian Sea, Ltd., INPEX North Makassar, Ltd. (liquidation proceedings completed on December 19, 2008), and INPEX Offshore North Campos, Ltd. (following the acquisition of all shares in this company by private-sector shareholders, including INPEX CORPORATION, this company was sold to a third-party in October 2019), was agreed between INPEX CORPORATION and JNOC in the MOU of February 5, 2004. Regarding the treatment of shares of SODECO, refer to the following section “(2) Treatment of the shares of Sakhalin Oil and Gas Development (SODECO) owned by the Japanese government”. With regard to the transfer to INPEX CORPORATION of the shares in the above project companies other than SODECO, it was decided that the shares are to be transferred for cash compensation as soon as prerequisites such as the consent of the oil-producing country and joint venture partners and the possibility of appropriate asset evaluations are in place. However, the transfer of shares held by JNOC in the above companies has not been decided and the shares in the above project companies were succeeded to by the Japan Organization for Metals and Energy Security (hereinafter “JOGMEC”) on the dissolution of JNOC on April 1, 2005, except shares related to INPEX North Makassar, Ltd., to which the Minister of Economy, Trade and Industry succeeded. JOGMEC states in its “medium-term objective” and “medium-term plan” that the shares succeeded to from JNOC will be disposed of at an appropriate time and in an appropriate manner. However, the timing and manner of disposal for those shares in the above companies held by JOGMEC that have not been acquired by INPEX CORPORATION have not been decided, and it is possible that the Company will be unable to acquire these shares.

The Japanese government (the Minister of Economy, Trade and Industry) owns 50% of the shares of SODECO. SODECO was established in 1995 to engage in an oil and natural gas exploration and development project located on the northeast continental shelf off Sakhalin Island. The Company holds 6.08% of SODECO shares issued and outstanding.
Regarding the future of this project, we will take appropriate measures while considering the current international situation and trends in factors including the activities of the government.

Following a speculative acquisition or an attempt at management controlled by foreign capital, Class A Stock is designed and issued to be highly transparent while not unreasonably impeding the efficiency and flexibility of management and to keep the effects of any such speculative acquisition to the necessary minimum. At the same time, Class A Stock maintains the Company’s role in the efficient implementation of a stable supply of energy for Japan as a core business, so that management is not conducted in a way contradictory to that role and no negative impact is felt. Nevertheless, the anticipated risks in connection with the Class A Stock include the following.