Notes to the Standalone Financial Statement for the year ended March 31,2026

1. Corporate information

Oil and Natural Gas Corporation Limited ('ONGC' or 'the Company') is a public limited Company domiciled and incorporated in India [CIN: L74899DL1993GOI054155] and having its registered office at Plot No. 5A-5B, Nelson Mandela Road, Vasant Kunj, New Delhi, South West Delhi - 110070. The Company's shares are listed and traded on Bombay Stock Exchange and National Stock Exchange in India. The Company is engaged in exploration, development and production of crude oil, natural gas and value-added products.

2. Basis of preparation

(a) Statement of compliance

In accordance with the notification dated 16^th February 2015, issued by the Ministry of Corporate Affairs (MCA), the Company has adopted Ind AS issued under section 133 of the Companies Act, 2013 and notified under the Companies (Indian Accounting Standards) Rules, 2015 (as amended) with effect from April 1,2016.

The Financial Statements have been prepared in accordance with Ind AS notified under the Companies (Indian Accounting Standards) Rules, 2015 (as amended), the Companies Act, 2013 and Guidance Note on Accounting for Oil and Gas Producing Activities (Ind AS) issued by the Institute of Chartered Accountants of India.

(b) Basis of measurement

The Financial Statements have been prepared on going concern basis on the historical cost convention using accrual system of accounting except for certain assets and liabilities which are measured at fair value/amortised cost/ Net present value at the end of each reporting period, as explained in the accounting policies.

Accounting policies have been consistently applied except where a newly issued Ind AS is initially adopted or a revision to an existing accounting standard requires a change in the accounting policy hitherto in use. The methods used to measure fair values are disclosed in notes to the financial statements.

The Standalone Financial Statements are presented in Indian Rupees ("'") and all values are rounded off to the nearest two decimal million except otherwise stated.

(c) Current/Non-Current Classification:

As the operating cycle cannot be identified in normal course due to the special nature of industry, the same has been assumed to have duration of 12 months and all assets and liabilities have been classified as current or non-current accordingly.

5.1. The Company had elected to continue with the carrying value of its Property Plant & Equipment (including Oil & Gas Asset), Capital Work-in-Progress and Intangible Assets recognised as of April 1, 2015 (transition date) measured as per the Previous GAAP and used that carrying value as its deemed cost as on the transition date as per Para D7AA of Ind AS 101 ‘First -time Adoption of Indian Accounting Standards' except for decommissioning and restoration provision included in the cost of Property Plant & Equipment (including Oil & Gas Asset) and Capital Work-in-Progress which have been adjusted in terms of para D21 of Ind AS 101.

5.2. During FY 2016-17, Tapti A series facilities surrendered by the PMT Joint Operation (JO) to the Government of India (GoI) were transferred to the Company, as nominee of GoI, free of cost and recognized as a non-monetary government grant. Pursuant to amendment in Ind AS 20 notified through Companies (Indian Accounting Standards) Second Amendment Rules, 2018, the Company, during FY 2019-20, recognized such non-monetary government grant and related assets at nominal value. Assets pertaining to the Company's share in the JO were decapitalized/ retired accordingly.

Further, pursuant to Ministry of Petroleum and Natural Gas letter dated May 31, 2019, Panna-Mukta fields were assigned to the Company on nomination basis with effect from December 22, 2019, without consideration, upon expiry of the Production Sharing Contract (PSC). Accordingly, the related assets and corresponding government grant were recognized at nominal value as non-monetary government grant.

Consequent to such assignment, the Company also assumed decommissioning and site restoration obligations relating to Panna-Mukta fields and Tapti Part-A facilities, along with transfer of Site Restoration Fund balance amounting to USD 33.81 million (' 2,402.18 million) for Tapti A facilities and USD 598.24 million (' 42,506.87 million) for Panna Mukta fields from JV partners (including the Company share of 40% in the fields). The Company is required to maintain dedicated SRF accounts in accordance with the Site Restoration Fund Scheme, 1999 and utilise such funds only for specified decommissioning purposes.

The Company periodically reassesses decommissioning liabilities and contributes additional amounts to SRF, wherever required. Any shortfall in decommissioning cost will be borne by the Company, while surplus funds remaining after completion of decommissioning shall be transferred to GoI. The Company is

also required to pay nominal annual rental of ' 1 per annum to GoI for use of Tapti A facilities till abandonment.

5.3. In line with the Union Cabinet's directive dated February 19, 2019, to enhance domestic oil and gas production through reforms in the Exploration and Licensing Policy, nomination fields operated by National Oil Companies were identified for bidding under the oversight of the Directorate General of Hydrocarbons (DGH).

Under this initiative, in total 49 nos. of fields were awarded under various PEC Bid rounds over the FY 2021-22, FY 2022-23 & FY 2024-25. However, Notice of award (NOA) for 11 nos. of fields contract areas terminated due to non-submission of PBG and remaining 38 nos. of fields are currently being operated under Production Enhancement Contracts (PECs). The impact of same on the financial statements for the year ended March 31, 2026 is immaterial.

5.4. Cyclone Tauktae impacted the Company's offshore production installations and drilling rigs in the Arabian Sea in May 2021, resulting in damage to certain offshore facilities/ platforms. The loss was intimated under the Offshore Energy Package Insurance Policy and surveyors/ loss adjusters were appointed by the insurer.

Based on pre-engineering and post-engineering surveys, the loss adjuster, in its 4th Interim Survey Report issued in February 2023, recommended an estimated claim amount of ' 9,080.50 million (USD 110 million) towards expenditure incurred/ likely to be incurred for restoration of cyclone-related damages.

Based on the report, the Company received payment of ' 1,314.54 million (USD 16 million; gross USD 36 million less deductible of USD 20 million) in March, 2023 and ' 1,660.00 million (USD 20 million) in March 2024 pursuant to 5th Interim Report submitted in January 2024. Also, the payment of ' 1,283.72 million (USD 15 million) was received during FY 2024-25 based on further submissions and discussions with the insurer. The aforesaid receipts have been accounted for as miscellaneous receipts.

During the current year, the loss adjustor has submitted the final recommendation in respect of NH Asset, B&S Asset and Sagar Bhushan. Also, the claims related to MH Asset and certain rigs are at an advanced stage of review by the loss adjuster, and discussions with all stakeholders are ongoing for early settlement of the claims. (refer Note no 31 and Note no 6.2).

(d) New Accounting Standards

In May 2025, MCA notified amendments to Ind AS 21 - The Effects of Changes in Foreign Exchange Rates, applicable w.e.f. April 1, 2025. The company has evaluated the requirements of the amendment and there is no impact on its Financial Statements.

In August 2025, MCA notified the following amendments to:

i. Ind AS 1, Presentation of Financial Statements, applicable w.e.f April 1,2025 - The amendment relates to classification of liabilities as current or non -current and non-current liabilities with covenants. In the context of classifying a liability as current, it removes the requirement of existence of a right to defer settlement for at least 12 months after the reporting date, and instead requires that the said right should exist on the reporting date and have substance. The amendment also introduces guidance on classification of liabilities with covenants. The company has evaluated the requirements of the amendment and there is no impact on its financial statements.

ii. Ind AS 7, Statement of Cash Flows and Ind AS 107, Financial Instruments - Disclosures, applicable w.e.f April 1, 2025 - The amendment in Ind AS 7 requires to inform users of financial statements of the existence of supplier finance arrangements and explain the nature of the arrangements, the carrying amount of liabilities and the range of payment due dates. Ind AS 107 has been amended to add supplier finance arrangements as a factor that may cause concentration of liquidity risk. The company has evaluated the requirements of the amendment and there is no impact on its financial statements.

iii. Ind AS 12 - International Tax Reform- Pillar Two Model Rules applicable immediately- The amendments provide a temporary exception to the requirements of recognising and disclosing information about deferred tax assets and liabilities related to Pillar Two income taxes and requires an entity to disclose that it has applied the temporary exception. The company has evaluated the requirements of the amendment and there is no impact on its financial statements.

(e) Standards issued but not yet effective

MCA notifies new standards or amendments to the existing standards under Companies (Indian Accounting Standards) Rule, 2015 as issued from time to time. As on reporting date, the MCA has not notified any new standard or amendment which has been made applicable with effect from April 01, 2026, onwards.

3. Material Accounting Policies

3.1. Investments in subsidiaries, associates and joint ventures:

The Company records the investments in subsidiaries, associates and joint ventures at cost less impairment loss, if any.

When the Company issues financial guarantees on behalf of subsidiaries, associates and joint ventures, it records the initial fair value of financial guarantee as deemed investment with a corresponding liability recorded as deferred revenue under financial guarantee obligation. Such deemed investment is added to the carrying amount of investment in subsidiaries, associates and joint ventures. Subsequently, the liability is measured in accordance with Note no. 3.25 (iv). Deferred revenue is recognized in the Statement of Profit and Loss over the remaining period of financial guarantee issued as other income.

Interest free loans provided to subsidiaries are recognized at fair value on the date of disbursement and the difference on fair valuation is recognized as deemed investment in subsidiaries. Such deemed investment is added to the carrying amount of investment in subsidiaries. Loans are accounted at amortized cost method using effective interest rate. If there is an early repayment of loan made by the subsidiaries, the proportionate amount of the deemed investment recognized earlier is adjusted.

Where the Company is a sponsor in respect of Compulsory Convertible Debentures issued by subsidiaries & joint ventures and is mandatorily required to purchase such debentures, a financial liability is recognized at fair value with a corresponding debit to deemed investment. Financial liability is subsequently measured at amortized cost. The deemed investment is added to the carrying amount of investment in subsidiaries or joint ventures and carried at cost.

Disposal of investment in subsidiaries, associates and joint ventures

On disposal of investment in subsidiaries, associates and joint ventures, the difference between net disposal proceeds and the carrying amounts (including corresponding value of dilution in deemed investment) are recognized in the Statement of Profit and Loss.

3.2. Interests in joint operations

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement.

The Company has Joint Operations in the nature of Production Sharing Contracts (PSC) and Revenue Sharing Contracts (RSC) with the Government of India and various body corporates for exploration, development and production activities of hydrocarbons.

The Company's share in the assets and liabilities along with attributable income and expenditure of the Joint Operations is merged on line by line basis with the similar items in the Financial Statements of the Company and adjusted for depreciation, depletion, survey, exploratory well costs written off, decommissioning provision, impairment and sidetracking in accordance with the accounting policies of the Company.

The hydrocarbon reserves in such areas are taken in proportion to the participating interest of the Company.

With respect to use of leased assets in the joint operations, the Company recognizes lease liability and corresponding right-of-use asset in accordance with the terms of related joint operating agreement.

3.3. Government Grants

Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions attached to them and that the grants will be received.

Capital grant which relates to an asset and whose primary condition is that the Company should purchase, construct or otherwise acquire non-current assets is recognized and disclosed as 'deferred income' under non-current liability in the Balance Sheet. It is further recognized as income on a systematic basis over the expected useful lives of the related assets.

Non-monetary grants received by the Company are recognized at nominal value for grants and assets.

3.4. Property, Plant and Equipment (PPE) including Oil and Gas Assets

(i) Oil and Gas Assets

Oil and Gas Assets (tangible & intangible) acquired/ constructed are initially recognized at cost and then subsequently carried at cost less accumulated depletion and impairment losses. These are created in respect of an area / field having proved developed oil and gas reserves, when the well in the area / field is ready to commence commercial production.

Cost of temporary occupation of land, successful exploratory wells, all development wells (including service wells), allied facilities, depreciation on support equipment used for drilling and estimated future decommissioning costs are capitalized and classified as Oil and Gas Assets.

Oil and Gas Assets are depleted using the “Unit of Production Method". The rate of depletion is computed with reference to an area covered by individual lease/license/asset/ amortization base by considering the proved developed reserves and related capital costs incurred including estimated future decommissioning / abandonment costs net of salvage value. Acquisition cost of Oil and Gas Assets is depleted by considering the proved reserves. These reserves are estimated annually by the Reserve Estimates Committee of the Company, which follows the International Reservoir Engineering Procedures.

(ii) Other Property, Plant and Equipment

Property, Plant and Equipment (other than oil and gas assets) in the course of construction for production, supply or administrative purposes are carried at cost, less any recognised impairment loss. The cost of an asset comprises its purchase price or its construction cost (net of applicable

The estimated useful lives, residual values and depreciation method are reviewed on an annual basis and if necessary, changes in estimates are accounted for prospectively. Depreciation on subsequent expenditure on PPE (other than of Oil and Gas Assets) arising on account of capital improvement or other factors is provided for prospectively over the remaining useful life.

Depreciation on refurbished/revamped PPE (other than of Oil and Gas Assets) which are capitalized separately is provided for over the reassessed useful life.

Depreciation on expenditure on dry docking of rigs and vessels capitalized as component of relevant rig / vessels is charged over the dry dock period on straight line basis. Depreciation on PPE (other than Oil and Gas Assets) including support equipment and facilities used for exploratory/ development drilling is initially capitalised as part of drilling cost and expensed / depleted as per Note

no. 3.4 (i). Depreciation on equipment/ assets deployed for survey activities is charged to the Statement of Profit and Loss.

An item of PPE is de-recognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on the disposal or retirement of an item of PPE is determined as the difference between the net sates/disposat proceeds and the carrying amount of the asset and is recognised in the Statement of Profit and Loss.

3.5. Lease Liabilities and Right-of-use Assets

The Company assesses whether a contract contains a tease, at inception of the contract. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether:

(i) the contract involves use of an identified asset;

(ii) the Company obtains substantially att of the economic benefits from the use of the asset through the period of the tease and

(iii) t he Company has the right to direct the use of the asset.

The Company has exercised the option of not applying Ind AS 116 (Leases) to teases of intangible assets.

The Company as a 'lessee'

At the date of commencement of the tease, the Company recognises a right-of-use asset (ROU asset) and a corresponding tease tiabitity for att hiring contracts / arrangements in which it is a tessee, except for tease with a term of twetve months or tess (i.e. short term teases) and tease of tow vatue assets. For these short-term and tow vatue teases, the Company recognizes the tease payments on straight-tine basis over the term of the tease or any other systematic basis if that basis is more representative of the pattern of the tessee's benefit.

Certain tease arrangements inctude the options to extend or terminate the tease before the end of the tease term. ROU assets and tease tiabitities inctude these options when it is reasonabty certain that the option to extend the tease witt be exercised/option to terminate the tease witt not be exercised.

The tease tiabitity is initiatty measured at present vatue of the future tease payments over the reasonabty certain tease term. The tease payments are discounted using the interest rate impticit in the tease contract, and if not readity determinabte, using the incrementat borrowing rate. For teases with simitar characteristics, the Company, on a tease by tease basis, appties either the incrementat borrowing rate specific to the tease or the incrementat borrowing rate for the portfotio as a whote.

Lease tiabitities are remeasured with a corresponding adjustment to the retated right-of-use asset if the Company changes its assessment regarding extension or termination option.

The right-of-use assets are initially recognized at cost, which comprises the amount of the initial measurement of the lease liability adjusted for any lease payments made at or before the inception date of the lease along with any initial direct costs, restoration obligations and lease incentives received.

Subsequently, the right-of-use assets is measured at cost less any accumulated depreciation and accumulated impairment losses, if any. The right-of-use assets is depreciated using the straight-line method from the commencement date over the shorter of lease term or useful life of right-of-use assets.

The interest cost on lease liability (computed using effective interest method), is expensed in the statement of profit and loss, unless eligible for capitalization as per accounting policy below on Borrowing costs.

The Company accounts for each lease component within the contract as a lease separately from non-lease components of the contract in accordance with Ind AS 116 Leases and allocates the consideration in the contract to each lease component on the basis of the relative stand-alone price of the lease component and the aggregate stand-alone price of the non-lease components.

3.6. Intangible Assets

(i) Intangible assets acquired separately

Intangible assets with finite useful lives that are acquired separately are carried at cost less accumulated amortisation and impairment losses. Amortisation is recognised on a straight-line basis over their estimated useful lives not exceeding five years from the date of capitalisation. The estimated useful life is reviewed at the end of each reporting period and the effect of any changes in estimate is accounted for prospectively.

Intangible assets are derecognised on disposal, or when no future economic benefits are expected from use or disposal. Gains or losses arising from derecognition of an intangible asset are determined as the difference between the net disposal proceeds and the carrying amount of the asset, and recognised in the Statement of Profit and Loss when the asset is derecognised.

Research expenditure is recognized as an expense when it is incurred. Development expenditure is recognised as an intangible asset subject to fulfilment of specified conditions.

(ii) Intangible assets under development - Exploratory Wells in Progress

All exploration and evaluation costs incurred in drilling and equipping exploratory and appraisal wells, are initially capitalized as Intangible assets under development -Exploratory Wells in Progress till the time these are either transferred to Oil and Gas Assets on completion as per Note no.3.4 (i) or expensed as exploration and evaluation cost

(including allocated depreciation) as and when determined to be dry or of no further use, as the case may be.

In case of Exploratory stratigraphic test well which is a drilling effort, geologically directed to obtain information pertaining to a specific geologic condition, drilled without the intention of being completed for hydrocarbon production, the cost of drilling are initially capitalized as Intangible assets under development - Exploratory Wells in Progress till the time these are either transferred to Oil and Gas Assets when area / field is ready to commence commercial production as per Note no.3.4 (i) or expensed as exploration and evaluation cost (including allocated depreciation) as and when determined to be dry or the License is surrendered. Costs of exploratory wells are not carried over unless it could be reasonably demonstrated that there are indications of sufficient quantity of reserves and sufficient progress has been made in assessing the reserves and the economic and operating viability of the project. All such carried over costs are subject to review for impairment as per the policy of the Company.

(iii) Intangible oil & gas asset in progress

Cost of survey conducted in the development area with the objective of production enhancement and better reservoir management are initially capitalized as 'Intangible oil & gas asset in progress' and transferred to 'Oil and Gas Assets' on conclusion of survey [Acqusition Processing and Interpretation (API)] activity as per Note no 3.8 (iii).

3.7. Impairment of tangible, intangible assets and right-of-use assets

The Company reviews the carrying amount of its tangible (Oil and Gas Assets, Development Wells in Progress (DWIP), Property, Plant and Equipment including Capital Works-inProgress) and intangible assets of a “Cash Generating Unit" (CGU) and right of use assets at the end of each reporting period to determine whether there is any significant indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). When it is not possible to estimate the recoverable amount of an individual asset, the Company estimates the recoverable amount of the cash-generating unit to which the asset belongs.

Recoverable amount is the higher of fair value less costs of disposal and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or cash-generating unit) is reduced to its recoverable amount and impairment loss is recognised in the Statement of Profit and Loss.

An assessment is made at the end of each reporting period to see if there are any indications that impairment losses recognized earlier, may no longer exist or may have come down. The impairment loss is reversed, if there has been a change in the estimates used to determine the asset's recoverable amount since the previous impairment loss was recognized. If it is so, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Reversals of Impairment loss are recognized in the Statement of Profit and Loss.

Exploration and Evaluation assets are tested for Impairment when further exploration activities are not planned in near future or when sufficient data exists to indicate that although a development is Likely to proceed, the carrying amount of the exploration asset is unlikely to be recovered in full from successful development or by sale. Impairment loss is reversed subsequently, to the extent that conditions for impairment are no longer present.

3.8. Exploration & Evaluation, Development and Production Costs

(i) Pre-acquisition cost

Expenditure incurred before obtaining the right(s) to explore, develop and produce oil and gas are expensed as and when incurred.

(ii) Acquisition cost

Acquisition costs of Oil and Gas Assets are costs related to right to acquire mineral interest and are accounted as follows: -

(a) Exploration and development stage

Acquisition cost relating to projects under exploration or development are initially accounted as Intangible Assets under development - exploratory wells in progress or Oil & Gas Assets under development -development wells in progress respectively. Such costs are capitalized by transferring to Oil and Gas Assets when a well is ready to commence commercial production. In case of abandonment / relinquishment of Intangible Assets under development - exploratory wells in progress, such costs are written off.

(b) Production stage

Acquisition costs of producing Oil and Gas Assets are capitalized as proved property acquisition cost under Oil and Gas Assets and amortized using the unit of production method over proved reserves of underlying assets.

(iii) Survey cost

Cost of Survey and prospecting activities conducted in the search of oil and gas in exploratory area are expensed as exploration cost in the year in which these are incurred.

Cost of survey conducted in the development area with the objective of production enhancement and better reservoir management are initially capitalized as 'Intangible oil & gas asset in progress' and transferred to 'Oil and Gas Assets' on conclusion of survey (API) activity.

(iv) Oil & Gas asset under development - Development Wells in Progress

All costs relating to Development Wells are initially capitalized as 'Development Wells in Progress' and transferred to 'Oil and Gas Assets' on “completion".

(v) Production costs

Production costs include pre-well head and post-well head expenses including depreciation and applicable operating costs of support equipment and facilities.

3.9. Side tracking costs

In the case of an exploratory well, cost of side-tracking is treated in the same manner as the cost incurred on a new exploratory well. The cost of abandoned portion of side tracked exploratory wells is expensed as 'Exploration cost written off'.

In the case of development wells, the entire cost of abandoned portion and side tracking is capitalized.

In case of side tracking of producing wells and service wells which form part of the development schemes are treated as development wells and the cost incurred on the side tracking is capitalized.

In the case of side tracking of producing wells and service wells which do not form part of the development schemes and the side-tracking results in additional proved developed oil and gas reserves or increases the future economic benefits therefrom beyond previously assessed standard of performance, the cost incurred on side tracking is capitalised, whereas the cost of abandoned portion of the well is depleted in the normal way. Otherwise, the cost of side tracking is expensed as 'Work over Expenditure'.

3.10. Decommissioning costs

Decommissioning costs is recognized when the Company has a legal or constructive obligation to plug and abandon a well, dismantle and remove a facility or an item of Property, Plant and Equipment and to restore the site on which it is located. The full eventual estimated provision towards costs relating to dismantling, abandoning and restoring well sites and allied facilities are recognized in respective assets when the well is complete / facilities or Property, Plant and Equipment are installed.

The amount recognized is the present value of the estimated future expenditure determined using existing technology at current prices and escalated using appropriate inflation rate till the expected date of decommissioning and discounted up to the reporting date using the appropriate risk-free discount rate.

An amount equivalent to the decommissioning provision is recognized along with the cost of exploratory well or Property, Plant and Equipment. The decommissioning cost in respect of dry well is expensed as exploratory well cost.

Any change in the present value of the estimated decommissioning provision other than the periodic unwinding of discount is adjusted to the decommissioning provision and the carrying value of the related asset. In case reversal of decommissioning provision exceeds the carrying amount of the related asset including WDV of the capitalised portion of decommissioning provision in the carrying amount of the related asset, the excess amount is recognized in the Statement of Profit and Loss. The unwinding of discount on provision is charged in the Statement of Profit and Loss as finance cost.

Provision for decommissioning cost in respect of assets under Joint Operations is considered as per participating interest of the Company on the basis of estimates approved by the respective operating committee. Wherever the same are not approved by the respective operating committee, decommissioning cost estimates of the Company are considered.

3.11. Inventories

Finished goods (other than Sulphur and carbon credits) including inventories in pipelines / tanks are valued at cost or net realisable value whichever is lower. Cost of finished goods is determined on absorption costing method. It also includes systematic allocation of directly attributable fixed and variable production overheads. The value of inventories includes amortization cost of relevant assets, production related costs, excise duty and royalty (wherever applicable) but excludes recoverable taxes.

Crude oil in semi-finished condition at Group Gathering Stations (GGS) is valued at cost on absorption costing method or net realisable value, whichever is lower.

Crude oil in unfinished condition in flow lines up to GGS / platform is not valued as the same is not measurable. Natural Gas is not valued as it is not stored except where the same is parked as per the provision of relevant Gas Sale Agreement (GSA).

Cost of finished goods and semi-finished goods are determined on weighted average basis.

Inventory of stores and spare parts is valued at weighted average cost or net realisable value, whichever is lower. Provisions are made for obsolete and non-moving inventories. Sulphur (being residual in nature) and carbon credits are valued at net realisable value.

3.12. Revenue recognition

The Company derives revenues primarily from sale of products and services, such as crude oil, natural gas, value added products, pipeline transportation and processing services.

Revenue from contracts with customers is recognized at the point in time when the Company satisfies a performance obligation by transferring control of a promised product or service to a customer at an amount that reflects the consideration to which the Company expects to be entitled in exchange for the sale of products and service, net of discount, taxes. The transfer of control on sale of crude oil, natural gas and value-added products occurs at the point of delivery, where usually the title is passed and the customer takes physical possession, depending upon the contractual conditions. Any retrospective revision in prices is accounted for in the year of such revision.

Sale of crude oil and natural gas (net of levies) produced from Exploratory/ Development Wells in Progress is deducted from expenditure on such wells.

Any payment received in respect of contractual short lifted gas/ VAPs quantity for which an obligation exists to make-up such gas in subsequent periods is recognised as Contract Liabilities in the year of receipt. Revenue in respect of such contractual short lifted quantity of gas is recognized when such gas is actually supplied or when the customer's right to make-up is expired, whichever is earlier.

Revenue in respect of contractual short lifted quantity of gas/ VAPs with no obligation for make-up is recognized when collectability of the receivable is reasonably assured.

As per the Production Sharing Contracts for extracting the Oil and Gas Reserves with Government of India, out of the earnings from the exploitation of reserves after recovery of cost, a part of the revenue is paid to Government of India which is called Profit Petroleum. It is reduced from the revenue from Sale of Products as Government of India's Share in Profit Petroleum.

3.13. Other income

(i) Dividend income from investments is recognised when the shareholder's right to receive the payment is established.

(ii) Income in respect of the following is recognized when collectability of the receivable is reasonably assured:

(a) Interest on delayed realization from customers and cash calls from JV partners;

(b) Liquidated damages from contractors/suppliers;

(iii) Interest income on deposit with banks is recognised at effective interest rate applicable, interest income from other financial assets is recognised at the effective interest rate method on initial recognition.

3.14. Foreign Exchange Transactions

The functional currency of the Company is Indian Rupees ("?") which represents the currency of the primary economic environment in which it operates.

Transactions in currencies other than the Company's functional currency (foreign currencies) are recognised at the rates of exchange prevailing at the dates of the transactions. At the end of each reporting period, monetary items denominated in foreign currencies are translated using mean exchange rate prevailing on the last day of the reporting period.

Exchange differences on monetary items are recognised in the Statement of Profit and Loss in the period in which they arise.

Non-monetary items denominated in foreign currency which are measured in terms of historical cost are recorded using the exchange rate at the date of the transaction.

3.15. Employee Benefits

Employee benefits include salaries, wages, contributory provident fund, gratuity, leave encashment towards unavailed leave, compensated absences, post-retirement medical benefits and other terminal benefits.

All short term employee benefits are recognized at their undiscounted amount in the accounting period in which they are incurred.

(i) Defined contribution plans

Employee Benefit under defined contribution plans comprising Post Retirement Benefit Scheme, Employee pension scheme-1995, composite social security scheme etc. is recognized based on the undiscounted amount of obligations of the Company to contribute to the plan. The same is paid to a fund administered through a separate trust.

(ii) Defined benefit plans

Defined employee benefit plans comprising of gratuity, postretirement medical benefits and other terminal benefits, are recognized based on the present value of defined benefit obligation which is computed using the projected unit credit method, with actuarial valuations being carried out at the end of each annual reporting period. These are accounted either as current employee cost or included in cost of assets as permitted. Contributory Provident Fund scheme is treated as defined benefit to the extent of interest liability on provident fund contribution. The Contribution made by Company based on fixed percentage of eligible employee's salary and shortfall of interest , if any , on the basis of actuarial valuation are recognised as an expense in the statement of profit and loss under employee benefit expenses.

Net interest on the net defined liability is calculated by applying the discount rate at the beginning of the period to

(i) Current tax

The tax currently payable is based on taxable profit for the year. Taxable profit differs from 'profit before tax' as reported in the Statement of Profit and Loss because of items of income or expense that are taxable or deductible in other years and items that are never taxable or deductible. The Company's current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the end of the reporting period and any adjustment to tax payable in respect of previous year.

(ii) Deferred tax

Deferred tax is recognised using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities in the Financial Statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences. Deferred tax assets are generally recognised for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilised.

The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the deferred tax asset to be utilized.

Deferred tax liabilities and assets are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset realised, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority.

The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which the Company expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets are recognised for all deductible temporary differences, and any unused tax losses to the extent that it is probable that taxable profit will be available in future against which the deductible temporary differences, and unused tax losses can be utilised, except when the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects (i) neither the accounting profit or loss nor taxable profit or loss and (ii) does not give rise to equal taxable and deductible temporary difference.

(iii) Current and deferred tax expense for the year

Current and deferred tax expense is recognised in the Statement of Profit and Loss, except when they relate to items that are recognised in other comprehensive income or directly in equity, in which case, the current and deferred tax are also recognised in other comprehensive income or directly in equity respectively.

3.19. Borrowing or Finance Costs

Borrowing costs including finance cost on lease liability specifically identified to the acquisition or construction of qualifying assets or development wells or exploratory wells is capitalized as part of such assets till the date of cessation of activities related to qualifying assets. A qualifying asset is one that necessarily takes substantial period of time to get ready for intended use. All other borrowing costs are charged to the Statement of Profit and Loss.

Borrowing cost also includes exchange differences arising from foreign currency borrowings to the extent that they are regarded as an adjustment to interest costs that is equivalent to the extent to which the exchange loss does not exceed the difference between the cost of borrowing in functional currency (?) when compared to the cost of borrowing in a foreign currency.

When there is an unrealised exchange loss which is treated as an adjustment to interest and subsequently there is a realised or unrealised gain in respect of the settlement or translation of the same borrowing, the gain to the extent of the loss previously recognised as an adjustment is recognised as an adjustment to interest.

3.20. Rig Days Costs

Rig movement costs are booked to the next location drilled/ planned for drilling. Abnormal Rig days costs are considered as un-allocable and charged to the Statement of Profit and Loss.

3.21. Provisions, Contingent Liabilities and Contingent Assets

Provisions are recognised when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that the Company will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material).

The Company discloses the part of the obligation as a contingent liability that is expected to be met by other parties, where it is jointly and severally liable for an obligation.

Contingent Liabilities are disclosed in the Financial Statements by way of notes to accounts, unless possibility of an outflow of resources embodying economic benefit is remote. Contingent liabilities are disclosed on the basis of judgment of the management/independent experts. These are reviewed at each balance sheet date and are adjusted to reflect the current management estimate.

A contingent asset is a possible asset that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the company. These assets are disclosed in the Financial Statements when an inflow of economic benefits is probable.

3.22. Financial instruments

Financial instruments are recognised when Company becomes a party to the contractual provisions of the instruments.

A financial instrument is initially recognised at fair value and is adjusted (in the case of instruments not classified at FVTPL) for transaction costs that are incremental and directly attributable to the acquisition or issuance of the financial instrument, and fees that are an integral part of the effective interest rate. Transaction costs and fees paid or received relating to financial instruments carried at FVTPL are recorded in the Statement of Profit and Loss.

3.23. Equity instruments

Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs.

3.24. Financial assets

(i) Initial recognition and measurement

All financial assets are recognized at fair value on initial recognition, except for trade receivables which are initially measured at transaction price. Transaction costs that are directly attributable to the acquisition or issue of financial assets (other than financial assets at fair value through profit or loss) are added to the fair value measured on initial recognition of financial asset.

(ii) Classification and subsequent measurement

Financial assets are classified based on the business model within which the asset is held and on the basis of the financial asset's contractual cash flow characteristics.

- Financial Assets at amortized cost

Financial assets are subsequently measured at amortised cost if these financial assets are held within a business model whose objective is to hold these assets in order to collect contractual cash flows and the contractual terms of the financial assets give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Such financial assets are measured at amortized cost using the Effective Interest Rate (EIR) method.

- Financial Assets at Fair value through other comprehensive income (FVTOCI)

Financial assets are measured at fair value through other comprehensive income if these financial assets are held within a business model whose objective is achieved by both collecting contractual cash flows on specified dates that are solely payments of principal and interest on the principal amount outstanding and selling financial assets.

Fair value movements are recognized in Other Comprehensive Income (OCI). However, the Company recognizes interest income, impairment losses & reversals and foreign exchange gain or loss in the statement of profit and loss. On de-recognition of the asset, cumulative gain or loss previously recognized in OCI is recycled from OCI to the statement of profit and loss.

- Financial Assets at Fair value through profit or loss (FVTPL)

Financial assets are measured at fair value through profit or loss unless they are measured at amortised cost or at fair value through other comprehensive income on initial recognition. The transaction costs directly attributable to the acquisition of financial assets at fair value through profit or loss are immediately recognised in statement of profit and loss.

- Investment in Equity instruments

All equity investments in entities other than subsidiaries, associates and joint venture companies are measured at fair value. Equity instruments which are held for trading are classified as at FVTPL. For all other such equity instruments, the Company decides to classify the same either as at FVTOCI or FVTPL. The election made on an instrument-by-instrument basis. The classification is made on initial recognition and is irrevocable.

Equity instruments included within the FVTPL category are measured at fair value with all changes recognized in the Statement of Profit and Loss.

For equity instrument classified as FVTOCI, all fair value changes on the instrument, excluding dividends, are recognized in the OCI. Dividends on such equity instruments are recognized in the Statement of Profit and Loss. There is no recycling of the amounts from OCI to Statement of Profit and Loss, even on sale/ disposal of such investments. However, the Company may transfer the cumulative gain or loss within equity on sale / disposal of the investments.

(iii) Impairment of financial assets

In accordance with Ind AS 109 Financial Instruments, the Company applies the expected credit loss (ECL) model for measurement and recognition of impairment loss on financial assets measured at amortised costs or debt instruments measured at FVTOCI, and trade receivables/ amounts receivable from contract with customers.

Loss allowance for trade receivables/ amounts receivable from contract with customers are always measured at an amount equal to lifetime ECL's (simplified approach).

Lifetime expected credit losses are the expected credit losses that result from all possible default events over the expected life of a financial instrument.

12-month expected credit losses are the portion of expected credit losses that result from default events that are possible within 12 months after the reporting date (or a shorter period if the expected life of the instrument is less than 12 months).

For recognition of impairment loss on other financial assets including Cash Call receivables from JO partners, the Company follows general approach wherein it is required to determine whether there has been a Significant Increase in the Credit Risk (SICR) since initial recognition. If credit risk has not increased significantly, 12-months ECL is used to provide for impairment loss. However, if credit risk has increased significantly, lifetime ECL is used.

When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating ECLs, the Company considers reasonable and supportable information that is relevant and available without undue cost or effort. This includes both quantitative and qualitative information and analysis, based on the Company's historical experience and informed credit assessment, that includes forward-looking information.

If, in a subsequent period, credit quality of the instrument improves such that there is no longer a significant increase in credit risk since initial recognition, then the company reverts to recognizing impairment loss allowance based on 12-months ECL.

(iv) De-recognition

The Company derecognizes a financial asset when the contractual rights to the cash flows from the financial asset expire or it transfers the financial asset and the transfer qualifies for derecognition under Ind AS 109.

On derecognition of a financial asset in its entirety (except for equity instruments designated as FVTOCI), the difference between the asset's carrying amount and the sum of the consideration received and receivable is recognised in the Statement of Profit and Loss.

3.25. Financial liabilities

(i) Initial recognition and measurement

All financial liabilities are recognized initially at fair value and, in case where such financial liabilities are subsequently measured at amortized cost, directly attributable transaction cost are netted from its fair value.

(ii) Subsequent measurement

Financial liabilities are measured at amortized cost using the effective interest method.

(iii) Derecognition

A financial liability is derecognized when the obligation specified in the contract is discharged or cancelled or expires.

(iv) Financial Guarantee Contracts

Financial guarantee contracts issued by the Company are those contracts that require a payment to be made to reimburse the holder for a loss it incurs because the specified debtor fails to make a payment when due in accordance with the terms of a debt instrument.

Financial guarantee contracts are recognized initially as a liability at fair value, adjusted for transaction costs that are directly attributable to the issuance of the guarantee. Subsequently, the liability is measured at the higher of:-

(a) the amount of loss allowance determined as per impairment requirements of Ind AS 109 'Financial Instruments' and

(b) the amount recognized less the cumulative amount of income recognized in accordance with the principles of Ind AS 115 'Revenue from Contracts with Customers'.

[refer Note no. 3.1 for Financial guarantee issued to subsidiaries, associates and joint venture]

(v) Offsetting of financial assets and financial liabilities

Financial assets and financial liabilities are offset, and the net amount is presented in the balance sheet if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, to realize the assets and settle the liabilities simultaneously.

3.26. Cash and cash equivalents

The Company considers all highly liquid financial instruments, which are readily convertible into known amounts of cash that are subject to an insignificant risk of change in value and having original maturities of three months or less from the date of purchase, to be cash equivalents. Cash and cash equivalents consist of balances with banks which are unrestricted for withdrawal and usage.

3.27. Earnings per share

Basic earnings per share are computed by dividing the net profit after tax by the weighted average number of equity shares outstanding during the period. Diluted earnings per share is computed by dividing the profit after tax by the weighted average number of equity shares considered for deriving basic earnings per share and also the weighted average number of equity shares that could have been issued upon conversion of all dilutive potential equity shares.

3.28. Statement of Cash Flow

Cash flows are reported using the indirect method, whereby profit after tax is adjusted for the effects of transactions of a non-cash nature, any deferrals or accruals of future or past

operating cash receipts or payments and item of income or expenses associated with investing or financing cash flows.

3.29. Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the Chief Operating Decision Maker (CODM). The Board of Directors has been considered as CODM of the company.

Segment results that are reported to the CODM include items directly attributable to a segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly corporate expenses, finance costs, income tax expenses and corporate income that are not directly attributable to segments. Revenue directly attributable to the segments is considered as segment revenue. Expenses directly attributable to the segments and common expenses allocated on a reasonable basis are considered as segment expenses.

3.30. Events after Reporting Date

The Company evaluates events and transactions that occur subsequent to the balance sheet date but prior to approval of the financial statements to determine the necessity for recognition and/or reporting of any of these events and transactions in the financial statements.

4. Critical Accounting Judgments, Assumptions and Key Sources of Estimation Uncertainty

Inherent in the application of many of the accounting policies used in preparing the Financial Statements is the need for Management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimates are revised and future periods are affected.

Key source of judgments, assumptions and estimation uncertainty in the preparation of the Financial Statements which may cause a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are in respect of Oil and Gas reserves, long term production profile, impairment, useful lives of Property, Plant and Equipment, depletion of oil and gas assets, decommissioning provision, employee benefit obligations, impairment, provision for income tax, measurement of deferred tax assets, litigation and contingent assets and liabilities.

4.1. Critical judgments in applying accounting policies

The following are the critical judgements, apart from those involving estimations (refer Note no. 4.2), that

the Management have made in the process of applying the Company's accounting policies and that have the significant effect on the amounts recognized in the Financial Statements.

(a) Determination of functional currency

Currency of the primary economic environment in which the Company operates (“the functional currency") is Indian Rupee (?) in which the Company primarily generates and expends cash. Accordingly, the Management has assessed its functional currency to be Indian Rupee (').

(b) Classification of investment

Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending upon the facts and circumstances in each case, the Company may obtain control, joint control or significant influence over the entity or arrangement. Transactions which give the Company control of a business are business combinations. If the Company obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If the Company has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then classified as an associate.

(c) Identifying whether a contract includes a lease

The Company enters into hiring/service arrangements for various assets/services. The Company evaluates whether a contract contains a lease or not, in accordance with the principles of Ind AS 116. This requires significant judgements including but not limited to, whether asset is implicitly identified, substantive substitution rights available with the supplier, decision making rights with respect to how the underlying asset will be used, economic substance of the arrangement, etc.

(d) Determining lease term (including extension and termination options)

The Company considers the lease term as the noncancellable period of a lease adjusted with any option to extend or terminate the lease, if the use of such option is reasonably certain. Assessment of extension/ termination options is made on lease by lease basis, on the basis of relevant facts and circumstances. The lease term is reassessed if an option is actually exercised. In case of contracts, where the Company has the option to hire and de-hire the underlying asset on some circumstances (such as operational requirements), the lease term is considered to be initial contract period.

(e) Identifying lease payments for computation of lease liability

To identify fixed (including in-substance fixed) tease payments, the Company consider the non-operating day rate/standby as minimum fixed lease payments for the purpose of computation of lease liability and corresponding right of use asset.

(f) Low value leases

Ind AS 116 requires assessment of whether an underlying asset is of low value, if lessee opts for the option of not to apply the recognition and measurement requirements of Ind AS 116 to leases where the underlying asset is of low value. For the purpose of determining low value, the Company has considered nature of assets and concept of materiality as defined in Ind AS 1 and the conceptual framework of Ind AS which involve significant judgement.

(g) Evaluation of indicators for impairment of Oil and Gas Assets

The evaluation of applicability of indicators of impairment of assets requires assessment of external factors (significant decline in asset's value, significant changes in the technological, market, economic or legal environment, market interest rates etc.) and internal factors (obsolescence or physical damage of an asset, poor economic performance of the asset etc.) which could result in significant change in recoverable amount of the Oil and Gas Assets.

(h) Oil & Gas Accounting

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration or appraisal work is under way or firmly planned.

It is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the

continued intent to develop, or otherwise extract value from the discovery. Where this is no longer the case, the costs are immediately expensed.

4.2. Assumptions and key sources of estimation uncertainty

Information about estimates and assumptions that have the significant effect on recognition and measurement of assets, liabilities, income and expenses is provided below. Actual results may differ from these estimates.

(a) Estimation of provision for decommissioning

The Company estimates provision for decommissioning as per the principles of Ind AS 37 'Provisions, Contingent Liabilities and Contingent Assets' for the future decommissioning of Oil and Gas assets at the end of their economic lives. Most of these decommissioning activities would be in the future, the exact requirements that may have to be met when the removal events occur are uncertain. Technologies and costs for decommissioning are constantly changing. The timing and amounts of future cash flows are subject to significant uncertainty.

The timing and amount of future expenditures are reviewed annually or when there is a material change, together with rate of inflation for escalation of current cost estimates and the interest rate used in discounting the cash flows. The economic life of the Oil and Gas assets is estimated on the basis of long term production profile of the relevant Oil and Gas asset and the management expects that the Mining Lease(s) expired will be extended before the end of the economic life of the related assets.

The long term average General Consumer Price Index (CPI) for inflation has been used for escalation of the current cost estimates and pre-tax discounting rate used to determine the balance sheet obligation as at the end of the year is long term average risk free government bond rate with 10 year yield.

(b) Determining discount rate for computation of lease liability

For computation of lease liability, Ind AS 116 requires lessee to use their incremental borrowing rate as discount rate if the rate implicit in the lease contract cannot be readily determined.

For leases denominated in Company's functional currency, the Company considers the incremental borrowing rate to be risk free rate of government bond as adjusted with applicable credit risk spread and other lease specific adjustments like relevant lease term. For leases denominated in foreign currency, the Company considers the incremental borrowing rate as risk free rate based on US treasury bills as adjusted with applicable credit risk spread and other lease specific adjustments like relevant lease term and currency of the obligation.

(c) Determination of Cash Generating Unit (CGU)

The Company is engaged mainly in the business of oil and gas exploration and production in Onshore and Offshore. In case

of onshore assets, the fields are using common production/ transportation facilities and are sufficiently economically interdependent to constitute a single Cash Generating Unit (CGU). Accordingly, impairment test of all onshore fields is performed in aggregate of all those fields at the Asset Level. In case of Offshore Assets, a field is generally considered as CGU except for fields which are developed as a Cluster or group of Clusters, for which common facilities are used, in which case the impairment testing is performed in aggregate for all the fields included in the Cluster or group of Clusters.

(d) Impairment of Assets

Determination as to whether, and by how much, a CGU is impaired involves Management estimates on uncertain matters such as future crude oil, natural gas and value added product (VAP) prices, the effects of inflation on operating expenses, discount rates, production profiles for crude oil, natural gas and value added products. For Oil and Gas assets, the expected future cash flows are estimated using Management's best estimate of future crude oil and natural gas prices, production and reserves volumes.

The present values of cash flows are determined by applying pre tax-discount rates which are based upon the cost of capital from an estabilished model. Future cash inflows from sale of crude oil, natural gas and value added products are estimated using Management's best estimate of future prices and its co-relations with benchmark crudes and other petroleum products.

The value in use of the producing/developing CGUs is determined under a multi-stage approach, wherein future cash flows are initially estimated based on Proved Developed Reserves. Under circumstances where the further development of the fields in the CGUs is under progress and where the carrying value of the CGUs is not likely to be recovered through exploitation of proved developed reserves alone, the Proved and probable reserves (2P) of the CGUs are also taken for the purpose of estimating future cash flows. In such cases, full estimate of the expected cost of evaluation/ development is also considered while determining the value in use.

The discount rates applied in the assessment of impairment calculation are re-assessed each year.

(e) Estimation of reserves

Management estimates reserves in relation to all the Oil and Gas Assets based on the policies and procedures determined by the Reserves Estimation Committee (REC) of the Company. The estimates so determined are used for the computation of depletion and impairment testing.

The year-end reserves of the Company are estimated by the REC which follows international reservoir engineering procedures consistently. For reporting its petroleum resources, company follows universally accepted Petroleum Resources Management System-PRMS (2018) sponsored

by Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), Society of Petroleum Evaluation Engineers (SPEE), Society of Exploration Geophysicists (SEG), Society of Petrophysicists and Well Log Analysts (SPWLA) and European Association of Geoscientists and Engineers (EAGE).

PRMS (2018) defines Proved Reserves under Reserves category as those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from a given date forward from known reservoirs and under defined economic conditions, operating methods, and government regulations. Further it defines Developed Reserves as expected quantities to be recovered from existing wells and facilities and Undeveloped Reserves as the Quantities expected to be recovered through future significant investments.

Volumetric estimation is the main procedure in estimation which uses reservoir rock and fluid properties to calculate hydrocarbons in-place and then estimate that portion which will be recovered from it. As the field gets matured and reasonably good production history is available, then performance methods such as material balance, simulation, decline curve analysis are applied to get more accurate assessments.

The annual revision of estimates is based on the yearly exploratory and development activities and results thereof. New In-place Volume and Estimated Ultimate Recovery (EUR) are estimated for new discoveries. Revision of estimates is also due to Field growth which includes delineation/ appraisal activities and field reassessment. Delineation/ appraisal activities lead to revision in estimates due to new sub-surface data. Similarly, reassessment is also carried out for existing fields due to necessity of revision in petrophysical parameters, new seismic input, updating of static and dynamic models and performance analysis leading to change in Reserves. Intervention of new technology, change in classifications and contractual provisions also necessitate revision in estimation of Reserves.

As per Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019), approved by the SPE Board on June 25, 2019:

“The reliability of Reserves information is considerably affected by several factors. Initially, it should be noted that Reserves information is imprecise as a result of the inherent uncertainties in, and the limited nature of, the accumulation and interpretation of data upon which the estimating and auditing of Reserves information is predicated. Moreover, the methods and data used in estimating Reserves information are often necessarily indirect or analogical in character rather than direct or deductive..."

“The estimation of Reserves and other Reserves information is an imprecise science because of the many unknown

of the loss can be reasonably estimated. Significant judgment is made when evaluating, among other factors, the probability of unfavourable outcome and the liability to make a reasonable estimate of the amount of potential loss. Provision for litigations are reviewed at the end of each accounting period and revisions made for the changes in facts and circumstances.

(h) Impairment of Financial Assets

In accordance with Ind AS 109 - Financial Instruments, the Company applies ECL model for measurement and recognition of impairment loss on the trade receivables and other financial assets. For trade receivables, the Company follows simplified approach to compute default rates based on external Credit ratings of the borrowers and forward-looking estimates are incorporated using relevant macroeconomic indicator (GDP growth rate).

For other financial assets, the Company applies general approach for recognition of impairment losses wherein the Company uses judgment in considering the probability of default upon initial recognition and whether there has been a significant increase in credit risk on an ongoing basis throughout each reporting period.