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Company Information

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OIL AND NATURAL GAS CORPORATION LTD.

07 October 2022 | 03:59

Industry >> Oil Drilling And Exploration

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ISIN No INE213A01029 BSE Code / NSE Code 500312 / ONGC Book Value (Rs.) 143.96 Face Value 5.00
Bookclosure 19/08/2022 52Week High 195 EPS 35.47 P/E 3.78
Market Cap. 172029.52 Cr. 52Week Low 120 P/BV / Div Yield (%) 0.93 / 7.83 Market Lot 1.00
Security Type Other

ACCOUNTING POLICY

You can view the entire text of Accounting Policy of the company for the latest year.
Year End :2022-03 

1. Corporate information

Oil and Natural Gas Corporation Limited (‘ONGC’ or ‘the Company’) is a public limited Company domiciled and incorporated in India 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. Application of new Indian Accounting Standards

All the Indian Accounting Standards issued under section 133 of the Companies Act, 2013 and notified by the Ministry of Corporate Affairs (MCA) under the Companies (Indian Accounting Standards) Rules, 2015 (as amended) till the financial statements are approved have been considered in preparation of these Financial Statements.

2.1. Standards issued but not yet effective

The MCA has notified the Companies (Indian Accounting Standards / Ind AS) Amendment Rules, 2022 on March 23, 2022, whereby the amendments to various Indian Accounting Standards has been made applicable with effect from April 1,2022 onwards.

The amendments made vide aforesaid notification dated March 23, 2022 has brought few additions and substitutions in Indian Accounting Standards (Ind AS) particularly in Ind AS 101- First-time Adoption of Indian Accounting Standards, Ind AS 103- Business Combinations, Ind AS 109- Financial Instruments, Ind AS 16-Property, plant and Equipment, Ind AS 37- Provisions, Contingent Liabilities and Contingent Assets and Ind AS 41- Agriculture, the Company is evaluating the requirements of the same and its effect on the Financial Statements is not likely to be material.

3. Significant accounting policies3.1. Statement of compliance

In accordance with the notification dated 16th February, 2015, issued by the Ministry of Corporate Affairs, the Company has adopted Indian Accounting Standards (referred to as "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.

3.2. Basis of preparation

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 below.

Historical cost is generally based on the fair value of the consideration given in exchange for goods and services.

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. Accordingly, all assets and liabilities have been classified as current or non-current as per the Company’s operating cycle and other criteria set out in Ind AS-1 ‘Presentation of Financial Statements’ and Schedule III to the Companies Act, 2013.

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

Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions.

The Company categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement which are described as follows:

(a) Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

(b) Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability.

(c) Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or Company’s assumptions about pricing by market participants.

3.3. 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, initially it measures the financial guarantees at their fair values and subsequently measures at the higher of:

i. the amount of loss allowance determined in accordance with impairment requirements of Ind AS 109 ‘Financial Instruments’ and

ii. the amount initially recognized less, when appropriate, the cumulative amount of income recognised in accordance with the principles of Ind AS 115 ‘Revenue from Contracts with Customers’.

The Company 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. Deferred revenue is recognized in the Statement of Profit and Loss over the remaining period of financial guarantee issued as other income.

On disposal of investment in subsidiary, associate and joint venture, 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.

Interest free loans provided to subsidiary are recognized at fair value on the date of disbursement and the difference on fair valuation is recognized as deemed investment in subsidiary. 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 subsidiary, 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.

3.4. 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.

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, dry wells, 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/production sharing contracts.

Gain or loss on sale of interest in a block, is recognized in the Statement of Profit and Loss, except that no gain is recognized at the time of such sale if substantial uncertainty exists about the recovery of the costs applicable to the retained interest or if the Company has substantial obligation for future performance. The gain in such situation is treated as recovery of cost related to that block.

3.5. Non-current assets held for sale

Non-current assets or disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.

Non-current assets or disposal groups are classified as held for sale if their carrying amounts will be recovered principally through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sale of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

Property, Plant and Equipment and intangible assets are not depreciated or amortized once classified as held for sale.

3.6. Government Grants

Government grants are not recognized until there is reasonable

assurance that the Company will comply with the conditions attached to them and that the grants will be received.

Monetary Government grants, whose primary condition is that the Company should purchase, construct or otherwise acquire noncurrent assets and are recognized and disclosed as ‘deferred income’ under non-current liability in the Balance Sheet and transferred to the Statement of Profit and Loss on a systematic and rational basis over the useful lives of the related assets.

All Non-monetary grants received are recognized for both asset and grant at nominal value.

3.7. Property, Plant and Equipment (other than Oil and Gas Assets) and Right-of-use assets

The Company had elected to continue with the carrying value of all of its Property, Plant and Equipment recognised as of April 1,2015 (transition date) measured as per the Previous GAAP and used that carrying value as its deemed cost as of the transition date except adjustment related to decommissioning provisions.

Land and buildings held for use in the production or supply of goods or services, or for administrative purposes, are stated in the Balance Sheet at cost less accumulated depreciation and impairment losses, if any. Freehold land and land under perpetual lease are not depreciated.

Property, Plant and Equipment (PPE) 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 tax credits), any cost directly attributable to bring the asset into the location and condition necessary for it to be capable of operating in the manner intended by the Management and decommissioning cost as per Note no 3.13. It includes professional fees and, for qualifying assets, borrowing costs capitalised in accordance with the Company’s accounting policy. Such properties are classified to the appropriate categories of PPE when completed and ready for intended use. Parts of an item of PPE having different useful lives and significant value and subsequent expenditure on Property, Plant and Equipment arising on account of capital improvement or other factors are accounted for as separate components. Expenditure on dry docking of rigs and vessels are accounted for as component of relevant assets.

Depreciation of PPE commences when the assets are ready for their intended use.

Depreciation is provided on the cost of PPE (other than freehold land, Oil and Gas Assets and properties under construction) less their residual values, using the written down value method (except for components of dry docking capitalised) over the useful life of PPE as stated in the Schedule II to the Companies Act, 2013 or based on technical assessment by the Company. Estimated useful lives of these assets are as under:

Description

Years

Building & Bunk Houses

3 to 60

Plant & Machinery

2 to 40

Furniture & Fixtures

3 to 25

Vehicles, Ships & Boats

3 to 20

Office Equipment

2 to 20

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 additions/deletions to PPE (other than of Oil and Gas Assets) during the year is provided for on a pro-rata basis with reference to the date of additions/deletions except low value items not exceeding ' 5,000/- which are fully depreciated at the time of addition.

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. 3.11. Depreciation on equipment/ assets deployed for survey activities is charged to the Statement of Profit and Loss.

Right-of-use assets are depreciated on a straight-line basis over the lease term or useful life of the underlying asset, whichever is less.

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 sales/disposal proceeds and the carrying amount of the asset and is recognised in the Statement of Profit and Loss.

3.8. Intangible Assets

(i) Intangible assets acquired separately

The Company had elected to continue with the carrying value of all of its 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 of the transition date.

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.

(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.3.11 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.

Cost of drilling exploratory type stratigraphic test 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 as per Note No. 3.11 or expensed as exploration and evaluation cost (including allocated depreciation) as when determined to be dry or the Petroleum Exploration 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.

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

The Company reviews the carrying amount of its tangible and intangible assets (Oil and Gas Assets, Development Wells in Progress (DWIP), Property, Plant and Equipment (including Capital Works-in-Progress) and right-of use assets of a "Cash Generating Unit" (CGU) 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.

3.10. 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: -

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.

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 are expensed as exploration cost in the year in which these are incurred.

(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.

3.11. Oil and Gas Assets

The Company had elected to continue with the carrying value of all of its Oil and Gas 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 of the transition date except adjustment related to decommissioning provisions.

Oil and Gas Assets are stated at historical 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 capitalised 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.

3.12. Side tracking

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 sidetracking 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’.

3.13. Decommissioning costs

Decommissioning cost includes cost of restoration. Provision for 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.

3.14. 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. Sulphur and carbon credits are valued at net realisable value. The value of inventories includes excise duty and royalty (wherever applicable) but excludes cess.

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.

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.

Unserviceable and scrap items, when determined, are valued at estimated net realisable value.

3.15. 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 or duties. 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 Intangible assets under development - Exploratory Wells in Progress / Oil and Gas assets under development - Development Wells in Progress is deducted from expenditure on such wells.

Any payment received in respect of contractual short lifted gas 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.

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.

Revenue in respect of the following is recognized when collectability of the receivable is reasonably assured:

(i) Contractual short lifted quantity of gas with no obligation for make-up

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

(iii) Liquidated damages from contractors/suppliers

Dividend and interest income

Dividend income from investments is recognised when the shareholder’s right to receive payment is established and it became probable that the economic benefits associated with the dividend will flow to the company, and the amount of the dividend can be measured reliably.

Interest income from financial assets is recognised at the effective interest rate method applicable on initial recognition.

3.16. Leases

Effective April 01,2019, the Company adopted Ind AS 116 "Leases" using the modified prospective approach. The new standard defines a lease as a contract that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company has exercised the option not to apply this standard to leases of intangible assets.

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 all of the economic benefits from the use of the asset through the period of the lease and

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

The Company as a ‘lessee’

At the date of commencement of the lease, the Company recognises a right-of-use asset (ROU asset) and a corresponding lease liability for all hiring contracts / arrangements in which it is a lessee, except for lease with a term of twelve months or less (i.e. short term leases) and lease of low value assets. For these short-term and low value leases, the Company recognizes the lease payments on straightline basis over the term of the lease.

Certain lease arrangements include the options to extend or terminate the lease before the end of the lease term. ROU assets and lease liabilities includes these options when it is reasonably certain that they will be exercised.

The lease liability is initially measured at present value of the future lease payments over the reasonably certain lease term. The lease payments are discounted using the interest rate implicit in the lease, if it not readily determinable, using the incremental borrowing rate. For leases with similar characteristics, the Company, on a lease by lease basis, applies either the incremental borrowing rate specific to the lease or the incremental borrowing rate for the portfolio as a whole.

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 Company applies Ind AS 36 to determine whether a ROU asset is impaired and accounts for any identified impairment loss as described in the accounting policy below on "Impairment of tangible, intangible assets and 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 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.

Lease liability and ROU asset have been separately presented in the Balance Sheet and lease payments have been classified as financing cash flows.

3.17. 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.

3.18. Employee Benefits

Employee benefits include salaries, wages, Contributory provident fund, gratuity, leave encashment towards un-availed 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 Contributory provident fund, 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.

Net interest on the net defined liability is calculated by applying the discount rate at the beginning of the period to the net defined benefit liability or asset and is recognised the Statement of Profit and Loss except those included in cost of assets as permitted.

Remeasurement of defined retirement benefit plans except for leave encashment towards un-availed leave and compensated

absences, comprising actuarial gains and losses, the effect of the changes to the asset ceiling (if applicable) and the return on plan assets (excluding net interest as defined above), are recognised in other comprehensive income except those included in cost of assets as permitted in the period in which they occur and are not subsequently reclassified to profit or loss.

The Company contributes all ascertained liabilities with respect to gratuity and un-availed leave to the ONGC’s Gratuity Fund Trust (OGFT) and Life Insurance Corporation of India (LIC), respectively. Liability towards post-retirement medical benefits is being funded and contributed to LIC. Other defined benefit schemes are unfunded.

The retirement benefit obligation recognised in the Financial Statements represents the actual deficit or surplus in the Company’s defined benefit plans. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of reductions in future contributions to the plans.

(iii) Other long term employee benefits

Other long term employee benefit comprises of leave encashment towards un-availed leave and compensated absences. These are recognized based on the present value of defined 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.

Re-measurements of leave encashment towards un-availed leave and compensated absences are recognized in the Statement of profit and loss except those included in cost of assets as permitted in the period in which they occur.

3.19. Voluntary Retirement Scheme

Expenditure on Voluntary Retirement Scheme (VRS) is charged to the Statement of Profit and Loss when incurred.

3.20. General Administrative Expenses

General administrative expenses which are directly attributable are allocated to activities and the balance is charged to Statement of Profit and Loss.

3.21. Insurance claims

Insurance claims are accounted for on the basis of claims admitted/ expected to be admitted to the extent that the amount recoverable can be measured reliably and it is virtually certain to expect ultimate collection.

3.22. Research and Development Expenditure

Expenditure of capital nature are capitalised and expenses of revenue nature are charged to the Statement of Profit and Loss, as and when incurred.

3.23. Income Taxes

Income tax expense represents the sum of the current tax and deferred tax.

(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 neither the accounting profit or loss nor taxable profit or loss.

(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.

3.24. 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. 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 i.e. 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.

3.25. 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.

3.26. 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).

Contingent assets are disclosed in the Financial Statements by way of notes to accounts when an inflow of economic benefits is probable.

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.

3.27. Financial instruments

Financial assets and financial liabilities are recognised when Company becomes a party to the contractual provisions of the instruments.

Financial assets and financial liabilities are initially measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognised immediately in the Statement of Profit and Loss.

3.28. Equity instruments

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

3.29. Financial assets(i) 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.

(ii) Financial assets at amortised cost

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

(iii) Financial assets at fair value through other comprehensive income

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

The Company has made an irrevocable election to present in other comprehensive income subsequent changes in the fair value of equity investments not held for trading.

(iv) Financial assets at fair value through profit or loss

Financial assets are measured at fair value through profit or loss unless it is measured at amortised cost or at fair value through other comprehensive income on initial recognition.

(v) Impairment of financial assets

The Company assesses at each balance sheet date whether a financial asset or a group of financial assets is impaired. Ind AS 109 requires expected credit losses to be measured through a loss allowance. The Company recognises lifetime expected losses for trade receivables that do not constitute a financing transaction. For all other financial assets, expected credit losses are measured at an amount equal to 12 month expected credit losses or at an amount equal to lifetime expected losses, if the credit risk on the financial asset has increased significantly since initial recognition.

(vi) Derecognition of financial assets

The Company derecognises a financial asset when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another party.

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.

3.30. Financial liabilities(a) Financial guarantee contracts

A financial guarantee contract is a contract that requires the issuer to make specified payments to reimburse the holder for a loss it incurs because a specified debtor fails to make payments when due in accordance with the terms of a debt instrument.

Financial guarantee contracts issued by the Company are initially measured at their fair values and, if not designated as at FVTPL, are subsequently measured at the higher of:

i. the amount of loss allowance determined in accordance with impairment requirements of Ind AS 109; and

ii. the amount initially recognised less, when appropriate, the cumulative amount of income recognised in accordance with the principles of Ind AS 115. [refer Note No.. 3.3 for Financial guarantee issued to subsidiaries]

(b) Financial liabilities

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

(c) Derecognition of financial liabilities

The Company derecognises financial liabilities when, and only when, the Company’s obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in the Statement of Profit and Loss.

When an existing financial liability is exchanged with another financial liability, from the existing lender of the debt instrument on substantially different terms, or the terms of an existing financial liability are substantially modified, such an exchange or modification is treated as the derecognition of the original financial liability and the recognition of a new financial liability. The difference in the respective carrying amount is recognised in the Statement of Profit and Loss.

3.31. 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.

3.32. 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. The cash flows are segregated into operating, investing and financing activities.

3.33. Segment reporting

Operating segments are identified and reported taking into account the different risks and returns, the organization structure and the internal reporting systems.

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.

The Company has 49.36% equity interest in ONGC Petro additions Limited (OPaL). The Company has subscribed for 3,451.24 million (Previous year 3,451.24 million) share warrants as at March 31, 2022, entitling the Company to exchange each warrant with an equity share of face value of ' 10 each against which ' 9.75 each has been paid.

Further the Company has entered into an arrangement for backstopping support towards repayment of principal and coupon of Compulsory Convertible Debentures (CCDs) amounting to ' 77,780.00 million (Previous year ' 77,780.00 million) issued by ONGC Petro additions Limited in three tranches. The outstanding interest accrued as at March 31,2022 is ' 1,699.28 million (Previous year ' 1,926.75 million).

The Company has evaluated the interest in OPaL to be in the nature of joint venture as the shareholder agreement between OPaL and the joint Venture partners, Gas Authority of India Limited (GAIL) and the company provides for sharing of control on the decisions relating to specific activities of OPaL by both the Joint Venture partners.

(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 non-cancellable

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) lease 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 i.e. 4.67% (Previous year 4.47%) 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 i.e. 6.92% (Previous year 7.05%).

(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 of 14.74% (Previous year 14.29%) for Rupee transactions and 10.10% (Previous year 9.60%) for crude oil, natural gas and value added products revenue, which are measured in US$. 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 discount rate used is based upon the cost of capital from an established model.

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 are 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 petro-physical 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 25 June 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 geological and reservoir factors that can only be estimated through sampling techniques. Reserves are therefore only estimates, and they cannot be audited for the purpose of verifying exactness..

The Company uses the services of third-party agencies for due diligence and it gets the reserves of its major fields audited by third party periodically by internationally reputed consultants who adopt latest industry practices for their evaluation.

(f) Defined benefit obligation (DBO)

Management’s estimate of the DBO is based on a number of critical underlying assumptions such as standard rates of inflation, medical cost trends, mortality, discount rate and anticipation of future salary increases. Variation in these assumptions may significantly impact the DBO amount and the annual defined benefit expenses.

(g) Litigations

From time to time, the Company is subject to legal proceedings and the ultimate outcome of each being always subject to many uncertainties inherent in litigation. A provision for litigation is made when it is considered probable that a payment will be made and the amount 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.