Manual-formatted

Notes to Accounts Page 524

Notes to Accounts Page 525

D. FINANCIAL RISK DISCLOSURES 22.15 IND-AS PROVISIONS 22.15.1 Scope Ind-AS-107 Financial instruments requires disclosures of the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the end of the reporting period, and how the entity manages those risks. 22.15.2 Exceptions to the scope: This Ind AS shall be applied by all entities to all types of financial instruments, except a. Those interests in subsidiaries, associates or JV b. Employers’ rights and obligations arising from employee benefit plans. c. Financial instruments, contracts and obligations under share-based payment transactions. d. Instruments that are required to be classified as equity instruments. 22.15.3 Requirements Disclose information that enables users of financial statements to evaluate the nature and extent of risks arising from financial instruments to which the entity is exposed at the end of the reporting period. Following is the summary of disclosures required: 22.15.3.1 Qualitative disclosures – • The exposures to risks for each type of financial instrument and how they arise - Market Risk - fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices (interest rate risk, currency risk and other price risk, such as equity price risk and commodity risk.) - Credit risk- counterparty will not meet its obligations under a financial instrument or customer contract, leading to a financial loss. - Liquidity risk- risk of a shortage of funds • Managements objectives, policies and processes for managing the risk and the methods used to measure the risk • Any changes in above two from the previous period 22.15.3.2 Quantitative disclosures The quantitative disclosures provide information about the extent to which the entity is exposed to risk, based on information provided internally to the entity’s KMP. Following are the key disclosures: a. Market risk: Notes to Accounts INDEX Page 526

• Sensitivity analysis for each type of market risk (e.g. Increase/decrease in basis points for interest rate risk and impact on PBT, change in USD rate and impact on PBT for currency risk) • Methods and assumption used in analysis b. Credit risk: • Maximum exposure to credit risk at the end of reporting period (e.g. trade receivables, finance lease receivables , investments , loans) • Description of collateral held as security and other credit enhancements and their financial effects • Information about credit quality of financial assets that are neither past due not impaired • Ageing analysis for financial assets that are past due or impaired c. Liquidity risk: • Maturity analysis for non-derivative financial liabilities (e.g. loans , trade payables , other financial liabilities payable on demand , Less than 3 months, 3 to 12 months, 1 to 5 years, over 5 year) • Maturity analysis for derivative financial liabilities • A description of how it manages the liquidity risk inherent in the above requirement Notes to Accounts Page 527

RISK MANAGEMENT DISCLOSURES BY IOCL FOR THE YEAR Notes to Accounts Page 528

Notes to Accounts Page 529

Notes to Accounts Page 530

Notes to Accounts Page 531

Notes to Accounts Page 532

Notes to Accounts Page 533

Notes to Accounts Page 534

Notes to Accounts Page 535

E. RELATED PARTY TRANSACTIONS 22.16 BACKGROUND The provisions relating to related party transactions (RPTs) are covered by Companies Act 2013, SEBI regulations, 2015 (Regulation-23) and Ind AS 24-Related Party Disclosures. The definition of the term “related party” has been widened and the compliance requirements with respect to approvals, disclosures, etc. of related party relationships and transactions Notes to Accounts INDEX Page 536

have increased. SEBI regulations require that a Company should prepare and disclose a policy on dealing with related party transactions on the website and in the annual report. Key implications of these provisions can be summarized as follows: • RPTs to be at arm’s length price and in the ordinary course of business • RPTs and subsequent modification require prior audit committee approval • Audit Committee have the power to obtain professional advice from external sources/ full access to information contained in the records of the company • Directors report also contains a section on RPTs • RPTs which are not in the ordinary course or not at arm’s length require - Prior approval of board - Prior approval of shareholders (special resolution) exceeding specified thresholds • SEBI regulation requires prior approval of shareholders for all material RPTs even when the same are on ordinary course / arm’s length • Policy of dealing with RPTs to be disclosed on website and in annual report The process can be broken into four steps: • Identification of related parties • Identification of relevant transactions • Approval process • Disclosures 22.17 IDENTIFICATION OF RELATED PARTIES A related party is a person or entity that is related to the entity that is preparing its financial statements. A person or a close member of that person’s family is related to a reporting entity if that person: • has control or joint control of the reporting entity • has significant influence over the reporting entity; or • is a member of the key management personnel (KMP) of the reporting entity or of a parent of the reporting entity. Broadly an entity will be a related party if it is a: • Subsidiary companies & its fellow subsidiary, joint venture & associates. • Associate companies and their subsidiaries • Joint Ventures and their subsidiaries • The trusts for post-employment benefit plan for the benefit of employees of the company or it’s related entities. • A firm in which a KMP or his relative is a partner. • A private company in which a KMP is a member or director. Notes to Accounts INDEX Page 537

• A public company in which a KMP is a director and holds along with his relatives, more than 2% of its paid-up share capital A person shall be considered a relative if: • They are members of a Hindu Undivided Family • They are husband and wife • They are related in the following manner - Father (including stepfather) - Mother (including stepmother) - Son (including stepson) and his spouse - Daughter and her spouse - Brother (including stepbrother) - Sister (including stepsister) Close members of the family of a person are those family members who may be expected to influence, or be influenced by, that person in their dealings with the entity including: • that person’s children, spouse or domestic partner, brother, sister, father and mother; • children of that person’s spouse or domestic partner; and • dependants of that person or that person’s spouse or domestic partner. The list of all related parties to the company is compiled and circulated by the Corporate Office at each reporting date of the financial statement. 22.18 IDENTIFICATION OF RELATED PARTY TRANSACTIONS A related party transaction is a transfer of resources, services or obligations between company and its related party, regardless of whether a price is charged. For such transactions there is a need to sensitize Materials Department / Contract cell / any other department dealing with agency line up of respective locations and also to the Finance concurrence teams that before approval of these transactions, the same must be reported to Audit Committee and along with Agenda duly approved by Divisional head to Company Secretarial department. 22.19 APPROVAL OF THE TRANSACTIONS In line with the provisions of Section 177 of the Companies Act, 2013 and regulation 23 of SEBI regulations, all related party transactions requires prior approval of Audit Committee. Omnibus approval can be taken for transactions which are of repetitive nature and for non- repetitive transactions/ new transactions, prior approval is required. Divisions are requested to follow the approval guidelines and instructions issued by Company Secretary. Notes to Accounts INDEX Page 538

22.20 DISCLOSURES a. It is appropriate to disclose the related party relationship when control exists (in case of subsidiaries ), irrespective of whether there have been transactions between the related parties. This is because the existence of control relationship may prevent the reporting entity from being independent in making its financial and operating decisions. The disclosure of the name of the related party and the nature of the related party relationship where control exists may sometimes be at least as relevant in appraising an entity’s prospects as are the operating results and the financial position presented in its financial statements. As a practical measure, the company discloses all the relationships with its’ related parties, irrespective of whether there have been transactions between related parties. b. The company shall disclose compensation paid to Key Managerial Personnel in total and for each of the following categories: • short-term employee benefits • post-employment benefits • other long-term benefits • termination benefits • Sitting Fess to Independent Directors • share-based payment c. If the company has related party transactions during the periods covered by the financial statements, it shall disclose information about those transactions and outstanding balances, including commitments, • The amount of the transactions • The amount of outstanding balances, including commitments, and - their terms and conditions, including whether they are secured, and the nature of the consideration to be provided in settlement - details of any guarantees given or received • Provisions for doubtful debts related to the amount of outstanding balances • The expense recognised during the period in respect of bad or doubtful debts due from related parties. d. These disclosures shall be made separately for each of the following categories: • Entities with joint control of, or significant influence over, the entity • Subsidiaries • Associates • Key Management Personnel of the entity or its parent • Other Related parties (Post employment benefit plans-Trust, relatives of KMPs) Notes to Accounts INDEX Page 539

e. Items of a similar nature may be disclosed in aggregate except when separate disclosure is necessary for an understanding of the effects of related party transactions on the financial statements of the entity. f. Disclosures that related party transactions were made on terms equivalent to those that prevail in arm’s length transactions are made only if such terms can be substantiated. g. The company shall disclose the following about the transactions and related outstanding balances with Government entities: • The name of the government and the nature of its relationship with the reporting entity (i.e. control, joint control or significant influence) • The following information in sufficient detail to enable users of financial statements to understand the effect of related party transactions on its financial statements. - The nature and amount of each individually significant transaction - For other transactions that are collectively, but not individually, significant, a qualitative or quantitative indication of their extent. Presently only qualitative disclosures are given for this category of related parties. Refer annexure for the disclosures made in annual accounts. h. In order to automate the capturing of transactions with Related Parties, Trading Partner functionality has been enabled in SAP, which captures the transactions with enabled vendors and customers. All the vendors and customers of related parties has been identified and the functionality is enabled through COIS. In case of identification of new related party or vendor/customer account, the same shall be intimated by the units to Head Office which shall in turn forward the request to COIS. i. In case a transaction with related party is not routed through vendor/customer, the trading partner functionality may be enabled in GLs to ensure their capturing. j. The report of Related Party Transactions shall be drawn through PACE which will be based on transactions captured by Trading Partner Functionality in SAP and the same standard report can be used for reporting to Audit Committee. Notes to Accounts Page 540

Notes to Accounts Page 541

Notes to Accounts Page 542

Notes to Accounts Page 543

Notes to Accounts Page 544

Notes to Accounts Page 545

Notes to Accounts Page 546

Notes to Accounts Page 547

F. EXPLORATION & PRODUCTION 22.21 BACKGROUND Indian Oil Corporation has a vision of becoming international integrated E&P major company with substantial presence in upstream sector of the business in both overseas and domestic assets. Accordingly, IOC forayed into E&P business in 1995, in line with the vision of being “The Energy of India - A Globally Admired Company” and has been making continuous efforts to expand its E&P portfolio, both in domestic as well as overseas. At present, IOC is engaged in active exploration/ appraisal/ development & production activities in domestic blocks and overseas acreages. IOC’s overseas assets are straddled across various countries through various contracting regimes. IOC conducts a substantial portion of its E&P activities in partnership or joint ventures with international and domestic oil & gas companies. IOC has been participating in E&P blocks either independently as an operator or through incorporated/unincorporated JVs with other upstream operators. Activities in these blocks are being governed by the concerned Production Sharing Contract (PSC) or Joint Operating Agreement (JOA). Apart from in-house management of these blocks, there are many other procedural requirements to be fulfilled by operator/non-operating partner as per the contract/JOA. For the overall management of the blocks, convinced practices are being followed. To maintain the uniformity in the practices being followed for the effective management of blocks, accounting manual has been prepared. 22.22 PROCESS OF ACQUISITION OF E&P BLOCKS An acquisition can be made through biding under Licensing Round or through Farm-in any existing assets. 22.22.1 Bidding under Licensing Round: Most of countries bring licensing rounds for exploration of hydrocarbon. In India licensing rounds are carried out through Directorate General of Hydrocarbon (DGH) regulatory body of MoP&NG. Major steps involved in acquisition of a block in this route: • A Detail Technical and financial Due diligence, • Decision to work as 100% operator or in Jointly with other partner, • Selection of bidding partner (if we want to bid jointly with other company) – signing of Joint Bidding Agreement, • Finalization of Bidding parameters, • Sectorial experience, • Minimum work program, • Revenue sharing contract with Government and partner (if any), Notes to Accounts INDEX Page 548

• Joint Operating Agreement with other partners, • Payment of license fee & compensation to the farmers 22.22.2 Farm-in An arrangement whereby an Operator generally buys in or acquires an interest in a lease owned by another Operator on which oil or gas has been discovered or is being produced. Often farm-ins are negotiated to help the original owner with development costs and to secure for the buyer a source of crude oil or natural gas. Following are the major steps in Farm-in Acquisition: • Opportunities offered by seller / investment bankers / other oil companies • In-house evaluation • Scouting for partners • Due-diligence – Technical, Financial & Legal • Negotiation of price with seller • Execution of agreements 22.23 MODE OF ACQUISITION For Acquisition of block, generally joint venture / SPV is created among all the consortium partners. A joint venture (JV) can be structured in two ways - as an unincorporated joint venture (UJV) or an incorporated joint venture (IJV). 22.23.1 Salient Features of UJV & IJV: a. Unincorporated Joint Venture ( UJV) • Not a legal entity • Known as jointly controlled operations • Relationship governed by joint venture agreement known as JOA • Operator responsible for carrying out day-to-day operations • Decisions taken in Operating Committee and Management Committee • Participation in all domestic blocks through UJV b. Incorporated Joint Venture ( IJV) • A legal entity • Known as jointly controlled entity • Participation in overseas blocks through UJV as well as IJV Notes to Accounts INDEX Page 549

22.24 AGREEMENTS RELATED TO ACQUISITION AND OPERATION OF E&P BLOCKS Generally following types of Agreements executed between Regulator and partners. • Joint Bidding Agreements ( JBA) • Production Sharing Contracts (PSC) • Joint Operating Agreements (JoA) 22.24.1 Joint Bidding Agreements (JBA) Joint Bidding Agreement is signed between proposed consortiums for bidding round. In this modalities and liabilities of all partners are defined. Participating Interest of all the partners are usually agreed in this agreement and sharing of pre-bid expenses are also part of it. 22.24.2 Production Sharing Contracts (PSC) Production sharing contract is signed once the block is awarded. This agreement is signed between Govt and Bidder. In India, this agreement is signed between Govt of India and Bidder (Consortium) In production sharing agreements the country's government awards the execution of exploration and production activities to an oil company. The oil company bears the mineral and financial risk of the initiative and explores, develops and ultimately produces the field as required When successful, the company is permitted to use the money from produced oil to recover capital and operational expenditures, known as \"cost oil\". The remaining money is known as \"profit oil\", and is split between the government and the company, typically at a rate of about 80% for the government, 20% for the company In PSC, all the bidding parameters on which basis, block is awarded to bidder are mentioned. Rights and Liabilities of bidder, Role of Regulator and functioning mechanisms are defined this contracts. 22.24.3 Joint Operating Agreements (JoA) JOA is typically entered into when more than one party holds title to the oil and gas leasehold estate in a prescribed geographical area Joint Operating agreement is signed among the consortium partners. A JOA provides the contractual basis for the cooperative exploration, development, and production of oil and gas properties among the partners The JOA serves two main functions: A basis for the sharing of rights and liabilities under the Petroleum License. Usually this is allocated according to each party's PI under the JOA. The declaration of PI is one of the essential provisions in a JOA. All rights and liabilities arising in connection with the PL will be shared between the licensees in proportion to their PIs Notes to Accounts INDEX Page 550

To provide a set of rules for the conduct of operations under the PL. Operation involves designating one of the licensees as operator for the responsible for conducting the day-to- day operations subject to the supervision of a JOC which is representative of all licensee. Notes to Accounts Page 551

Phases and Activities related to E&P •Researching and analyzing an area‘s historic geologic data Prospecting Acquisition •Purchasing of oil and gas (outright ownership) •Obtaining a lease or concession, •Entering into a PSC, •Entering into a JV or Farm-in or Farm-out, Exploration •Detailed examination of a geographical area of interest of sufficient oil and gas producing potential, •Conducting topographical, geological, geochemical and geophysical studies •Carrying out exploratory drilling, trenching and sampling activities •Determining the technical feasibility and commercial viability of oil and gas deposits found •Appraisal wells to gain info about the size and characteristics of the reservoir, to assess commercial potential, to estimate the recoverable reserves Appraisal •Detailed engineering studies to determine how best the reservoir can be developed or Evaluation •Surveys for transportation and infrastructure requirement •Market and finance studies •Establishment of access of the oil and gas reserve and other preparations for commercial production •Gaining access to and preparing well locations for drilling; clearing ground; draining; building roads; gas lines; power lines to develop reserves •Construction of platforms or preparing drill sites from which to drill wells for production Development •Installation of necessary equipments and other facilities to get the oil / gas to the surface and for handling, storing and processing Production •Extraction of oil and gas and its processing to make it transportable and marketable •Activities: •Lifting oil and gas to the surface •Gathering production from individual wells to a common point in the field •Field processing •Storage Abandon- •To be done when oil and gas production is commercially unviable ment •Ceasing the production •Removal of equipments and other facilities •Restoring the production sites Notes to Accounts Page 552

22.25 INVOLVEMENT OF FINANCE 22.25.1 Regular Activities • Evaluation of business proposal • Review of agreements • Post-Acquisition • Annual budget review • Cash call payments • Non operator audit • Coordination for JV accounts and its review • Conversion of overseas blocks financial statements as per Indian GAAPs • Periodic reporting of information to management • RBI Compliance 22.25.2 Quarterly / Annual Activities of Finance • Review of Operating/ Management Committees ‘Resolution • Dry wells need to be charged as per information provided by Operator • Information seek for Unfinished work programme liability • Seek Provisional Expenditure statement of each E&P Blocks and booking of IOCL’s share as per its Participating interest, • Checking of License expiry of each block and providing accounting treatment • Revaluation of Old liability booked for unfinished work programme • Reserves estimation to be taken from Operator / E&P department • Depletion to be booked as per Unit of Production method • Contingent / Statutory liability – disclosure / accounting treatment 22.26 ACCOUNTING TREATMENT OF COST INCURRED IN DIFFERENT PHASES 22.26.1 Pre-acquisition costs Expenditure incurred before obtaining the right(s) to explore, develop and produce oil and gas are expensed as and when incurred. 22.26.2 Exploration stage Acquisition cost relating to projects under exploration is initially accounted as “Intangible assets under development”. The expenses on oil and gas assets that is classified as intangible include: - acquired rights to explore - Exploratory drilling costs Notes to Accounts INDEX Page 553

Cost of Survey and prospecting activities conducted in the search of oil and gas are expensed as exploration cost in the year in which these are incurred If the project is not viable based upon technical feasibility and commercial viability study, then all costs relating to Exploratory Wells is expensed in the year when determined to be no use / plugged / abandoned. If the project is proved to be viable, then all costs relating to drilling of hydrocarbon bearing Exploratory Wells shall be continued to be presented as “Intangible Assets under Development”. 22.26.3 Development stage Acquisition cost relating to projects under development stage is presented as “Capital work- in-progress”. When a well is ready to commence commercial production, the capitalized costs corresponding to prove developed oil and gas reserves is reclassified as ‘Completed wells/ Producing wells’ from “Capital work-in-progress/ Intangible asset under development” to the gross block of assets. Examples of Oil and Gas assets that might be classified as Tangible Assets include development drilling cost, piping and pumps and producing wells. 22.26.4 Production Phase Production costs include pre-well head and post-well head expenses including depreciation and applicable operating costs of support equipment and facilities are expensed off. Depletion is calculated using the Unit of Production method based upon proved and developed reserves. 22.26.5 Abandonment Phase In case of development / production phase, abandonment / decommissioning amount is recognized at the present value of the estimated future expenditure. Any change in the present value of the estimated decommissioning expenditure other than the unwinding of discount is adjusted to the decommissioning provision and the carrying value of the corresponding asset. The unwinding of discount on provision is charged in the statement of profit and loss as finance cost. 22.26.6 Support equipment facilities Depreciation on support equipment and facilities used for exploration and drilling activities is initially capitalized as part of exploration cost, development cost or producing properties. 22.26.7 Asset Retirement obligation Back-ground Many entities have obligations to dismantle, remove and restore items of property, plant and equipment. In this Appendix such obligations are referred to as ‘decommissioning, Notes to Accounts Page 554

restoration and similar liabilities’. Under Ind AS 16, the cost of an item of property, plant and equipment includes the initial estimate of the costs of dismantling and removing the item and restoring the site on which it is located, the obligation for which an entity incurs either when the item is acquired or as a consequence of having used the item during a particular period for purposes other than to produce inventories during that period. Recognition Applicability to IOCL Provision for decommissioning liability is required if- • there is any legal obligation as per the agreements in relation to leasehold property or • Constructive obligation. These provisions are applicable to IOC for its E&P assets. The initial estimate of the costs of decommissioning and restoration costs needs to be capitalized (as per Ind AS 16) under the head “Exploration Assets” by discounting the provision amount to it’s current value by applying principles of Ind AS 37. For this purpose, E&P blocks can be categorized under the below categories: a. E&P blocks under exploration Phase In the case of exploration phase, the field life of particular well is unascertainable. Linking of well with license date is also not possible, as the block having hydrocarbon discovery, generally not relinquished after expiry of license date. Due to the aforesaid reasons, share of decommissioning liability provided by the Operator's Statement of Expenditure for a block, will be booked in IOC book without any adjustment/ discounting of decommissioning liability. b. E&P blocks under development Phase E&P wells falling under development phase, discounting of decommissioning liability shall be applied. Where decommissioning liability is not provided by Operator, IOCL will estimate the liability for its share and treatment will be given as per Activity phase mentioned above. For discount rate, corporate guidelines on discount rate to be used shall be considered. In the case of dry wells / no further use of hydrocarbon bearing well, the decommissioning cost is charged off to P&L. 22.26.8 Impairment Impairment testing in case of Development and producing assets In case of E&P related development and producing assets, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, production volumes, proved & probable reserves volumes and discount rate. The expected future cash flows are estimated on the basis of value in use concept. The value in use is based on the cash flows expected to be generated by the projected oil or gas production profiles up to the expected dates of cessation of production of each producing field, based on current Notes to Accounts Page 555

estimates of proved and probable reserves and on reasonable & supportable fiscal assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the asset. Management takes a long-term view of the range of economic conditions over the remaining useful life of the asset and, are not based on the relatively short term changes in the economic conditions. Impairment in case of exploration and evaluation assets Exploration and Evaluation assets are tested for impairment where an indicator for impairment exists. In such cases, while calculating recoverable amount, in addition to the factors mentioned in “Impairment testing in case of Development and Producing assets”, management’s best estimate of total current reserves and resources are considered (including possible and contingent reserve) after appropriately adjusting the associated inherent risks. Impairment loss is reversed subsequently, to the extent that conditions for impairment are no longer present. Cash generating unit In case of E&P assets, Company generally considers a project as cash generating unit. However, in case where the multiple fields are using common production/transportation facilities and are sufficiently economically interdependent the same are considered to constitute a single cash generating unit (CGU). 22.26.9 Disclosures In compliance of Ind-AS-106 on \"Exploration and evaluation of mineral resources\", the disclosure of financial information relating to activity associated with the exploration for and evaluation of mineral resources (crude oil, natural gas etc.) is as under: 31 March XX 31 March XX i) Assets Property, plant and equipment Intangible assets Intangible assets under development Capital Work in Progress ii) Other Assets Liabilities i) Trade Payables ii) Provisions ii) Other Liabilities Income i) Sale of Crude Oil Notes to Accounts Page 556

ii) Sale of natural gas iii) Condensate IV) Other income Expenses i) Exploration expenditure written off ii) Other exploration costs Impairment losses Cash flow i) Net cash from/ (used) in operating activities ii) Net cash from/ (used) in investing activities Disclosures under Guidance note on Oil & Gas Net proved reserves of Crude Oil, Condensate, Natural gas Liquids and Gas Current Year Previous Year Assets Crude Oil, Natural Crude Oil, Natural Condensate, Gas Condensate, Gas NGLs NGLs TMT Million TMT Million Cubic Cubic Beginning Meter Meter Addition A) Proved Reserves Deduction Production Balance B)Proved developed Reserves Beginning Addition Deduction Production Balance Net proved reserves & proved developed reserves of Crude Oil, Condensate, Natural gas Liquids and Gas on geographical Basis: Assets Current Year Previous Year Notes to Accounts Page 557

Crude Oil, Natural Crude Oil, Natural Condensate, Gas Condensate, Gas NGLs NGLs Million Million Cubic Cubic TMT Meter TMT Meter A) Proved Reserves B) Proved developed Reserves The company uses in house study as well as third party agency each year for Reserves certification who adopts latest industry practices for reserve evaluation. For the purpose of estimation of Proved and Proved developed reserves, Deterministic method is used by the company. The annual revision of estimates is based on the yearly exploratory and development activities and results thereof. 22.27 NOTE-37: “RELATED PARTY DISCLOSURES” IN COMPLIANCE WITH IND-AS 24 22.27.1 Details of Subsidiary Companies/ Entities and their Subsidiaries: • IOC Sweden AB • IOCL (USA) Inc. • IndOil Global B.V., Netherlands • IOCL Singapore Pte. Ltd. • IndOil Montney Limited • IOC Cyprus Limited • IOCL Exploration and Production Oman Limited The following transactions were carried out with Subsidiary Companies/Entities in the ordinary course of business: Transactions Amount Sales xxx xxx crore (PY: xxx crore)] xxx Consultancy Services/ Other Income xxx xxx crore (PY : xxx crore)] xxx Purchase of Products xxx xxx crore (PY: xxx crore)]. xxx Purchase of Chemicals/ Materials xxx xxx crore (PY : xxx crore)]. Handling / Other Expenses INDEX [xxx crore)] Reimbursement of Expenses [xxx crore (PY : xxx crore)] Purchase/ (Sale)/ Acquisition of Fixed Asset incl CWIP xxx crore (PY : xxx crore)] Notes to Accounts Page 558

Transactions Amount Provisions made/(written off) during the year xxx IndOil Global B.V., Netherlands - NIL (PY : xxx crore)] Outstanding Receivables / Loans & Advances xxx – xxx crore (PY: xxx crore)]. Outstanding Payables xxx xxx crore (PY: xxx crore) Investments made during the year xxx [Mainly includes investment in IOCL Singapore Pte. Ltd. – xxx crore (PY: Nil)]. Investments in Subsidiaries as on date xxx Note: Transactions in excess of 10% of the total related party transactions for each type has been disclosed above. 22.27.2 Details of Joint Ventures (JV) / Associate Entities to IOCL & its subsidiary • Suntera Nigeria 205 Limited • INDOIL Netherlands B.V., Netherland • Taas India PTE Limited • Vankor India PTE Limited • Falcon Oil and Gas BV • Urja Bharat Pte. Ltd. The following transactions were carried out with related parties in the ordinary course of business: Transactions Amount Sales xxx xxx crore (PY: xxx crore) ] xxx Interest received xxx xxx crore (PY: xxx crore)] xxx Consultancy Services/Other Income xxx xxx crore (PY: xxx crore)] xxx Interest paid xxx xxx crore (PY: xxx crore)] Reimbursement of Expenses xxx xxx crore (PY: xxx crore)] Investments made/ (disinvestments) during the year xxx crore (PY: xxx crore)] Purchase/Acquisition of Fixed Assets including CWIP [Includes Purchase/Acquisition of Fixed Assets incl. CWIP from xxx crore (PY: xxx crore), - xxx crore (PY: xxx crore) Provisions made/(written off) during the year Notes to Accounts Page 559

Transactions Amount [Mainly includes Provision for diminution in value of investment in AREA 95-96 xxx crore (PY: Nil )] xxx Outstanding Receivables / Loans & Advances xxx xxx crore (PY: xxx crore)] xxx Outstanding Payables xxx crore (PY: xxx crore)] Investments in JV/ Associates as on date Decommissioning liabilities • G- Sec rates to be used for discounting (Rates are provided in treasury guidelines). • Rates are given up to the tenure of 30 years. For items exceeding 30-year, rate given for the 30 year to be considered. • For this purpose, G.sec rates of various tenure are provided in treasury guidelines. Rates are required to be considered based on the tenure Cash flows needs to be adjusted for the associated risks • Decommissioning liability estimate and rates needs to be reviewed on each reporting date and adjustments are required to be made prospectively. 22.28 SAP PROCESS USED FOR EXPLORATION & PRODUCTION ACCOUNTING 22.28.1 Creation of new project code For every E&P Block, creation of project code and its phases of activity are required called as Work breakdown structure (WBS). SAP transaction code used is CJ01. CJ01 - Create Work Breakdown Structure Notes to Accounts INDEX Page 560

22.28.2 Budget Allocation Budget needs to be provided to be provided from IOCL plan scheme to Exploration and Production for further transfer to Project code. IM32 - Change Budget of Inv. Prog. Position Notes to Accounts Page 561

22.28.3 Distribution of budget to project code Budget to be provided to Project -WBS from Exploration and Production Plan Budget. IM52 - Process budget distribution 22.28.4 Distribution of budget to line items of project code Budget to be distributed to various phases of the project code as per requirement of phases of Exploration and Production activities. CJ30 - Change Project Original Budget Notes to Accounts Page 562

22.28.5 Expense booking and Cash Call Payment- (In case of Non- operated Block) In Case where IOCL is not an operator, cash call payment as an advance to be made and subsequently advance needs to be adjusted with the expenditure statement provided by the operator. SAP transaction code used is YFU9. YFU9 - Oil Exploration Accounting entry Notes to Accounts Page 563

22.28.6 Expense booking and making payments (In case of IOCL operated block) Normal payment process is carried out for E&P activities through MIRO/FB60/FB01 MIRO/FB60/FB01 – SAP vendor posting Notes to Accounts Page 564

22.28.7 Rule Settlement As the expenditure and Budget is captured through WBS, subsequently the E&P cost is also transferred to Block cost centre Step-1 CJ02 - Change Work Breakdown Structure Step-2 CJ88 - Settle Projects and Networks Notes to Accounts Page 565

22.28.8 Depletion of Producing Oil & Gas Assets Unit of Production (UOP) method is applied for the purpose of depletion of Producing Oil & Gas asset as per guidance note issued by ICAI The depreciation charge or the U n i t o f P r o d u c t i o n ( UOP) charge for the acquisition cost within a field is calculated as under: UOP charge for the period = UOP rate x Production for the period UOP rate = Acquisition cost of the field /Proved Oil and Gas Reserves The depreciation charge or the Unit of Production (UOP) charge for all capitalised costs excluding acquisition cost within a field is calculated as under: UOP charge for the period = UOP rate x Production for the period UOP rate = Depreciation base of the field /Proved Developed Oil and Gas Reserves Depreciation base of the field should include: • Gross block of the field (excluding acquisition costs) • Estimated, decommissioning and abandonment costs net of estimated salvage values pertaining to proven developed oil and gas reserves and should be reduced by the accumulated depreciation and any accumulated impairment charge of the field. In SAP, a separate depreciation key has to be created through for each producing assets . Production data and reserves are to be updated through T-Code: AO25 22.28.9 SAP T-code for maintaining Depreciation key for Producing properties: AO25 - Unit-of-prod. Depreciation Chart of Accounts for E&P Accounting 22.28.10Below mentioned GL codes are specifically used for E&P accounting G/L number G/L long-text Concode Concode description 3141309000 number 3141310000 UNALLOCATED CAPITAL EXP-E & P 429 F.6 WIP - Balance as at 3141312000 ACQUISITION COST beginning of the year UNALLOCATED CAPITAL EXP-E & P 429 F.6 WIP - Balance as at EXPLORATION COST beginning of the year UNALLOCATED CAPITAL EXP-FARM 429 F.6 WIP - Balance as at IN COSTS beginning of the year Notes to Accounts Page 566

3141313000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at 3141314000 DRILLING PR/WELL PL/ENG beginning of the year 3141315000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at 3141316000 DRILLING INT(FINDER WELL) beginning of the year 3141317000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at 3141318000 DRILLING INT (WELL TESTING) beginning of the year 3141319000 F.6 WIP - Balance as at 3141320000 UNALLOCATED CAPITAL EXP- 429 beginning of the year 3141321000 DRILLING INT (SAND CONTROL) 429 F.6 WIP - Balance as at 3141322000 UNALLOCATED CAPITAL EXP- 429 beginning of the year 3141323000 DRILLING INT(WELL COMP) 429 F.6 WIP - Balance as at 3141324000 UNALLOCATED CAPITAL EXP- 429 beginning of the year 3141325000 DRILLING INT(WELL CON INS) F.6 WIP - Balance as at 3141326000 UNALLOCATED CAPITAL EXP- beginning of the year 3141327000 DRILLING TN(FINDER WELL) F.6 WIP - Balance as at 3141328000 UNALLOCATED CAPITAL EXP- beginning of the year 3141329000 DRILLING TN(WELL TESTING) F.6 WIP - Balance as at 3141330000 beginning of the year 3141331000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at 3141332000 DRILLING TN(SAND CONTROL) 429 beginning of the year 3141333000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at 3141334000 DRILLING TN(WELL COMP) 429 beginning of the year UNALLOCATED CAPITAL EXP- F.6 WIP - Balance as at DRILLING COREHOLE/BOREHOLE beginning of the year UNALLOCATED CAPITAL EXP- F.6 WIP - Balance as at DRILLING PILOT WELL beginning of the year F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- 429 beginning of the year DRILLING WELL CONSTRUCTION 429 F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- 429 beginning of the year DRILLING PRD TESTING 429 F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- 429 beginning of the year DRILLING TESTING F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- beginning of the year DRILLING FACILITIES COST F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- beginning of the year DRILLING PRC FACILITIES F.6 WIP - Balance as at beginning of the year UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at DRILLING HZ & ML LTL WELLS beginning of the year F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- 429 beginning of the year DRILLING SML WELL-OFF/ONS 429 F.6 WIP - Balance as at UNALLOCATED CAPITAL EXP- 429 beginning of the year DRILLING RIG MOB/DEMOB/DIS UNALLOCATED CAPITAL EXP- DRILLING SITE PREPARATION UNALLOCATED CAPITAL EXP- 429 DRILLING RIG COST Notes to Accounts Page 567

3141335000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at beginning of the year 3141336000 DRILLING LEASE RENT 429 F.6 WIP - Balance as at beginning of the year 3141337000 UNALLOCATED CAPITAL EXP- 429 F.6 WIP - Balance as at beginning of the year 3141403000 DRILLING INSURANCE 130 F.7 Less: Provision for Loss 3141800050 UNALLOCATED CAPITAL EXP- 25 3141800060 DRILLING OTHERS 25 3141800070 PROVISION FOR LOSSES IN E&P 25 3141800080 25 3141800090 Assets 25 3143020100 15 E&P_JCO_Dev_General & CWIP-Plan Scheme 3143020200 15 Administration 3143020300 15 3143020400 E&P_JCO_Dev_Drilling of well 15 CWIP-Plan Scheme 3143030100 expenses 15 3143030200 E&P_JCO_Dev_G&G Expenses 15 CWIP-Plan Scheme CWIP-Plan Scheme 3441110021 E&P_JCO_Dev_Overheads 224 CWIP-Plan Scheme Capital Stores at site E&P_JCO_Dev_Facilities in Progress CAPITAL STORES AT SITE(AF) INDIGENOUS CAPITAL STORES AT SITE(AF) Capital Stores at site IMPORTED E&P_JCO_Capital Stores (Inventory) Capital Stores at site Capital Stores at site E&P_JCO_Capital Store_Development phase CAPITAL STORES AT SITE(PROJECT) Capital Stores at site INDIGENOUS CAPITAL STORES AT SITE(PROJECT) Capital Stores at site IMPORTED E&P_JCO_Other Advances- Revenue K.1.2 Unsecured Considered Good 3441310019 E&P_JCO_Prepaid Exp 747 K.1.5.222 Unsecured, Considered Good 3441310021 E&P_JCO_Other Advances- Capital 694 F.2.6 Unsecured, Considered Good 4101080005 E&P_JCO_SALE OF CONDENSATE 57 Sale of Products 4101080010 E&P_JCO_SALE OF GAS 57 5294910100 G & G EXP--E & P GENERAL & 453 Sale of Products ADMINISTRATIVE CHARGES 5294910110 G & G EXP--E & P PARENT COMPANY 453 O1.26 Exploration & OVERHEADS 5294910120 G & G EXP--E & P LIQUIDATED 453 Production Cost DAMAGES 5294910190 OTH EXP-E & P ACTIVITIES 451 O1.26 Exploration & Production Cost O1.26 Exploration & Production Cost O2.04 Legal Expenses / Payment To Consultants Notes to Accounts Page 568

5299900000 GEOLOGY & GEOPHYSICS EXP- 453 O1.26 Exploration & 5299900010 PEL/LICENSE FEES 453 5299900020 GEOLOGY & GEOPHYSICS EXP- EIA 453 Production Cost 5299900040 STUDY 453 5299900060 GEOLOGY & GEOPHYSICS EXP- 2D 453 O1.26 Exploration & 5299900070 SURVEY ACQUISITION 453 5299900170 GEOLOGY & GEOPHYSICS EXP- 2D 453 Production Cost 5299900220 SURVEY SPL PROCESSING 453 5299900350 GEOLOGY & GEOPHYSICS EXP- 3D 453 O1.26 Exploration & 5299900360 SURVEY ACQUISITION 453 3111000020 GEOLOGY & GEOPHYSICS EXP- 3D 140 Production Cost 3121000010 SURVEY PRCN/INTPRTN 141 GEOLOGY & GEOPHYSICS EXP- O1.26 Exploration & OTHERS GEOLOGY & GEOPHYSICS EXP- DATA Production Cost COP/STORAGE/PRO/REP GEOLOGY & GEOPHYSICS EXP- O1.26 Exploration & SPECIAL STUDIES GEOLOGY & GEOPHYSICS EXP- Production Cost SUPPORT FIXED ASSETS- OIL WELL O1.26 Exploration & ACC DEPRECIATION-OIL WELL Production Cost O1.26 Exploration & Production Cost O1.26 Exploration & Production Cost O1.26 Exploration & Production Cost O1.26 Exploration & Production Cost BS.2.1.1 Gross Block BS.2.1.2 Accumulated Depreciation 5410000011 DEPRECIATION- OIL WELL 103 PL.2.4 Tangible Assets 5299900185 E&P_JCO_Production G&A 453 O1.26 Exploration & Production Cost 5299900195 E&P_JCO_Production_Other 453 O1.26 Exploration & expenses 453 Production Cost 5299900175 E&P_JCO_Production Overheads O1.26 Exploration & Production Cost Notes to Accounts Page 569

CHAPTER 23 : INCOME TAXES 23.1 PROVISION OF IND-AS 12 (INCOME TAXES) IN BRIEF 23.1.1 Accounting Profit - Accounting profit is profit or loss for a period before deducting tax expense. 23.1.2 Taxable Profit (Tax Loss) - Taxable profit (tax loss) is the profit (loss) for a period, determined in accordance with the rules established by the taxation authorities, upon which income taxes are payable (recoverable). 23.1.3 Tax Expense (Tax Income) - Tax expense (tax income) is the aggregate amount included in the determination of profit or loss for the period in respect of current tax and deferred tax. 23.1.4 Current Tax - Current tax is the amount of income taxes payable (recoverable) in respect of the taxable profit (tax loss) for a period. 23.1.5 Deferred Tax Liabilities - Deferred tax liabilities are the amounts of income taxes payable in future periods in respect of taxable temporary differences. 23.1.6 Deferred Tax Assets - Deferred tax assets are the amounts of income taxes recoverable in future periods in respect of: • deductible temporary differences; • the carry forward of unused tax losses; and • the carry forward of unused tax credits. 23.1.7 Temporary Differences - Temporary differences are differences between the carrying amount of an asset or liability in the balance sheet and its tax base. Temporary differences may be either: • taxable temporary differences, which are temporary differences that will result in taxable amounts in determining taxable profit (tax loss) of future periods when the carrying amount of the asset or liability is recovered or settled; or • deductible temporary differences, which are temporary differences that will result in amounts that are deductible in determining taxable profit (tax loss) of future periods when the carrying amount of the asset or liability is recovered or settled. The tax base of an asset or liability is the amount attributed to that asset or liability for tax purposes. 23.1.8 Recognition of Current Tax Liabilities and Current Tax Assets– INDEX Income Taxes Page 570

Current tax for current and prior periods shall, to the extent unpaid, be recognised as a liability. If the amount already paid in respect of current and prior periods exceeds the amount due for those periods, the excess shall be recognised as an asset. 23.1.9 Recognition of Deferred Tax Liabilities and Deferred Tax Assets– 23.1.9.1 Taxable Temporary Differences: A deferred tax liability shall be recognised for all taxable temporary differences except to the extent that the deferred tax liability arises from the initial recognition of goodwill or at the time of the transaction, affects neither accounting profit nor taxable profit (tax loss). 23.1.9.2 Deductible Temporary Differences: A deferred tax asset shall be recognised for all deductible temporary differences to the extent that it is probable that taxable profit will be available against which the deductible temporary difference can be utilised, unless the deferred tax asset arises at the time of the transaction, affects neither accounting profit nor taxable profit (tax loss). 23.1.10 Measurement of Current Tax Liabilities and Current Tax Assets – Current tax liabilities (assets) for the current and prior periods shall be measured at the amount expected to be paid to (recovered from) the taxation authorities, using the tax rates that have been enacted or substantively enacted by the end of the reporting period. 23.1.11 Measurement of Deferred Tax Liabilities and Deferred Tax Assets– 23.1.11.1 Deferred tax assets and liabilities shall be measured at the tax rates that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates that have been enacted or substantively enacted by the end of the reporting period. 23.1.11.2 The carrying amount of a deferred tax asset shall be reviewed at the end of each reporting period. An entity shall reduce the carrying amount of a deferred tax asset to the extent that it is no longer probable that sufficient taxable profit will be available to allow the benefit of part or all of that deferred tax asset to be utilised. Any such reduction shall be reversed to the extent that it becomes probable that sufficient taxable profit will be available. 23.1.12 Offset of current tax assets and current tax liabilities: An entity shall offset current tax assets and current tax liabilities if, and only if, 23.1.12.1 there is a legally enforceable right to set off the recognised amounts; and 23.1.12.2 the entity intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously. 23.1.13 Offset of deferred tax assets and deferred tax liabilities: An entity shall offset deferred tax assets and deferred tax liabilities if, and only if: Income Taxes Page 571

23.1.13.1 the entity has a legally enforceable right to set off current tax assets against current tax liabilities; and 23.1.13.2 the deferred tax assets and the deferred tax liabilities relate to income taxes levied by the same taxation authority on either: (i) the same taxable entity; or (ii) different taxable entities which intend either to settle current tax liabilities and assets on a net basis, or to realise the assets and settle the liabilities simultaneously, in each future period in which significant amounts of deferred tax liabilities or assets are expected to be settled or recovered. 23.2 PROVISION OF IND-AS 34 (INTERIM FINANCIAL REPORTING) RELATED TO ACCOUNTING OF INCOME TAX Income tax expense is recognised in each interim period based on the best estimate of the weighted average annual income tax rate expected for the full financial year. Amounts accrued for income tax expense in one interim period may have to be adjusted in a subsequent interim period of that financial year if the estimate of the annual income tax rate changes. 23.3 PROCEDURES ADOPTED 23.3.1 Advance Tax: 23.3.1.1 Provisions of Income Tax Act: a. Payments of Advance Tax u/s 208 of Income Tax Act are to be made. For computation of Advance Tax as per section 209, the company estimates its current income and the income tax thereon shall be calculated at the rates in force in the financial year. b. As per section 211 of Income Tax Act, the Advance Tax on current income calculated are to be paid in four installments during each financial year and due date of each installments and the amount of such installment are stated below: Installment Due date of installment Amount payable 1st Installment On or before 15th June Not less than 15% of such advance tax 2nd Installment On or before 15th September Not less than 45% of such advance tax 3rd Installment On or before 15th December Not less than 75% of such advance tax Not less than 100% of such advance 4th Installment On or before 15th March tax Income Taxes INDEX Page 572

23.3.1.2 Computation of Advance Tax: For the purpose of computation of Taxable Income the following information is required to be sent to Registered office by Divisions/Regions for the year: • Profitability statement of each Division along with the major assumptions and workings. • Details of estimated additions to fixed assets under more than 180 days and less than 180 days categories under various Block of asset e.g. Buildings (Residential, Office buildings, temporary erections, Roads, culverts etc), Plant and Machinery (LPG Cylinders, Energy saving devices, Computers, pollution control equipment, Motor vehicles etc), Furniture and Fixtures, Intangible assets (Patents, Licenses, computer software etc). Plant and machinery eligible for 20% additional depreciation is to be separately given. • Estimated book depreciation for the year. • Estimated deduction u/s 80 IA for Wind Power/Solar Power, Section 80IB for industrial undertaking, 80 G for Donations etc. • Estimated capital expenditure and revenue expenditure on scientific research eligible for weighted deduction [u/s.35(2AB) and 35(1)(iv)]. • Estimated capital expenditure in respect of specified business (cross country pipeline) eligible for deduction u/s 35AD. • Exchange loss / gain on account of fixed assets acquired from country outside India and repayment of such loan (Section 43A of Income tax Act). • Estimated amount of cost of assets acquired and installed for the undertaking set up for manufacture or production or article or thing on or after the 1st day of April, 2015 2015 and ending before 1st day of April, 2020, in any backward area notified by the Central Government in this behalf. Investment allowance is 15% of actual cost of new asset and shall be available in the year in which such asset is installed u/s 32AD. • CSR (Corporate Social Responsibility) Expenditure during the year. • Estimated Disallowance u/s 43B and major allowance on account of payment out of pre-existed liability to be provided. • Adjustments arising out of Income computation and disclosure standards (ICDS) notified by Central Board of Direct Taxes. • Other allowances and disallowances as per provisions of Income Tax Act, if any. 23.3.1.3 Accounting of Advance Tax: Payment of advance tax for each installment shall be debited to SAP GL 3441310650- LOANS AND ADVANCES-UCG-ADVANCE INCOME TAX PAID in Registered office (co code 0005). Any deposit of tax made on self-assessment shall also be debited to above code. 23.3.1.4 Interest for default in payment of advance tax: As per section 234B of Income Tax Act, if the company has failed to pay such tax or where the advance tax paid is less than 90% of the assessed tax, the company is liable to pay simple interest at applicable rate for every month or part of a month comprised in the period from 1st April next following such financial year Income Taxes Page 573