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]

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 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 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

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 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.

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 rating-based approach to compute default rates
based on Credit ratings of the borrowers and forward-looking
estimates are incorporated using relevant macroeconomic

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.

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 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
'First -time Adoption of Indian Accounting Standards'.

5.2. During the year 2016-17, Tapti A series facilities which
were part of the assets of PMT Joint Operation (JO) and
surrendered by the JO to the Government of India (Gol) as
per the terms of JO agreement were transferred by GoI to
the Company free of cost as its nominee and recorded as a
non-monetary grant. During the year 2019-20, the Company
opted to recognize the non-monetary government grant at
nominal value and recorded the said facilities at nominal
value, in line with amendment in Ind AS 20 'Accounting
for Government Grants and Disclosure of Government
Assistance' vide Companies (Indian Accounting Standards)
Second Amendment Rules, 2018 (the 'Rules'). These assets
were decapitalised / retired to the extent of the Company's
share in the Joint Operation.

Ministry of Petroleum and Natural Gas, Government of India
(GoI) vide letter dated May 31, 2019 assigned the Panna-
Mukta fields w.e.f. December 22, 2019 on nomination basis
to the Company on expiry of present PSC without any cost
to ensure continuity of operation. Being a non-monetary
grant, the Company has recorded these assets and grant at
a nominal value.

Subsequent to assignment of Panna-Mukta field to the
Company GoI has directed JV partners of the PMT (Panna
Mukta & Tapti) field to transfer the existing SRF fund
maintained for decommissioning obligation for Tapti Part
A facility and Panna Mukta fields to the Company along
with full financial and physical liability of site restoration
and decommissioning of Panna Mukta fields and Tapti Part
A facilities. Accordingly, in the year 2019-20 the Company
received SRF fund of USD 33.81 million (' 2,402.18 million)
for Tapti Part-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) and acquired
the corresponding decommissioning obligation with the
conditions that Company will maintain separate dedicated
SRF accounts under Site Restoration Fund scheme, 1999
and extent guidelines of SRF, the Company will not utilise
the fund of dedicated SRF fund of Panna- Mukta Fields
and Tapti Part-A facilities for any other purpose, other
than one defined under SRF scheme/guidelines. Company
shall periodically carry out the re-estimation of cost of
decommissioning of Panna- Mukta Fields and Tapti Part-A
facilities as per existing Company policy and contribute to
SRF account as per Company policy in nomination fields.

In case, final actual cost of decommissioning of facilities of
Panna-Mukta fields at the time of physical decommissioning
is higher than approved decommissioning cost plus
the accumulated amount, Company will contribute the
additional amount required for decommissioning. However,
in case the actual cost at the time of decommissioning is
less than the accumulated amount, the balance amount will
be transferred to the Government of India. The Company is
mandated to pay Rupee one per annum as rental charges
to Government of India for use of Tapti A facilities till its
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, 64 marginal
nomination fields operated by National Oil Companies were
identified for bidding under the oversight of the Directorate
General of Hydrocarbons (DGH). These were grouped into 17
Contract Areas.

Under this initiative, 25 fields were awarded under PEC Bid
Rounds I (2021-22) and II (2022-23) and are currently being
operated under Production Enhancement Contracts (PECs).
In PEC Bid Round III, 24 fields across 5 Contract Areas were
awarded on September 6, 2024, and are currently in the
process of being handed over. Operations on these fields
have not yet commenced. The impact of same on the financial
statements for the year ended March 31, 2025 is immaterial.

5.4. Cyclone Tauktae hit Arabian Sea off the coast of Mumbai
in the early hours of May 17, 2021 where the company's
major production installations and drilling rigs are located/
operating. The cyclone has caused damage to offshore
facilities/platforms. The occurrence of incident was
intimated to the Insurance Company under Offshore Energy
Package Insurance Policy and surveyors / Loss adjustors
were appointed by them for the incident. Pre-Engineering
and post engineering surveys had been done by the loss
adjuster on various occasions and they had recommended
the estimated claim amount of ' 9,080.50 million (USD 110
million) in their 4^th Interim survey report in February 2023
towards the expenditure incurred / likely to be incurred on
restoration of damages caused by the cyclone. Based on the
report the Company had received 1^st on account payment
of ' 1,314.54 million (USD 16 million; Gross USD 36 million
less policy deductible of USD 20 million) on 27.03.2023.
Further additional documents were submitted and various
meetings were held with loss adjustor, based on which 5^th
Interim Report was submitted in January 2024. The same
was confirmed by the Insurance Company for 2^nd on account
payment of ' 1,660.00 million (USD 20 million) in March
2024. The same was accounted as miscellaneous receipts
in year 2023-24. Thereafter, based on additional documents
submitted and various meetings, Insurance Company
has confirmed that loss adjuster has recommended 3^rd on
account payment of ' 1,283.72 million (USD 15 Million ) and
the same has been accounted as miscellaneous receipt
during the year, (refer Note no 31 and Note no 6.2).

10.3. The identification of suspended projects and the projects
with cost overrun/time overrun with the estimated period
of completion is done on the basis of estimates made
by technical executives of the Company involved in the
implementation of the projects.

10.4. During the year 2004-05, the Company had acquired,
90% Participating Interest in Exploration Block KG-
DWN-98/2 from Cairn Energy India Limited for a lump sum
consideration of ' 3,711.22 million which, together with
subsequent exploratory drilling costs of wells had been
capitalized under exploratory wells in progress. During
2012-13, the Company had acquired the remaining 10%
participating interest in the block from Cairn Energy India
Limited on actual past cost basis for a consideration of
' 2,124.44 million. Initial in-place reserves were established
in this block and adhering to original PSC time lines, a

declaration of commercially (DOC) with a conceptual cluster
development plan was submitted on December 21, 2009 for
Southern Discovery Area and on July 15, 2010 for Northern
Discovery Area. Thereafter, revised DOC was submitted in
December, 2013, Cluster-wise development of the Block had
been envisaged by division of entire development area into
three clusters.

The DOC in respect of Cluster II had been reviewed by the
Management Committee (MC) of the block on September
25, 2014. Field Development Plan (FDP) for CLuster-II was
submitted on September 8, 2015, which included cost of
aLL expLoratory weLLs driLLed in the Contract Area and the
same had been approved by the Company Board on March
28, 2016 and by MC on March 31,2016. Investment decision
has been approved by the Company. Contracts for Subsea
umbilical risers, flow lines, Subsea production system,

Central processing platform - living quarter utility platform
and Onshore Terminal have been awarded during 2018-19.
Sixteen (16) Oil wells, seven (7) Gas wells and Six (6) Water
injector wells were drilled up to March 31, 2021. Towards
early monetization, it was planned to produce Gas from
U-field utilizing Vasishta and S1 Project facilities. One Gas
well-U3B was completed in the month of March 2020 and
test production commenced on March 5, 2020. In line with
the Accounting Policy of the Company, Oil and Gas assets
were created for the well U3B on establishment of proved
developed reserves during the year 2019-20. Commercial
production from the well commenced on May 25, 2020.
Well, U1B and Well U1_A_Shft were completed and put to
production on August 26, 2021 and April 28, 2022 respectively.
On 07^th January 2024, Oil production commenced from M
field of Cluster II. All the remaining oil system facilities were
completed and production of Oil along with Associated Gas
commenced from A field & P Field on 30^th October 2024 and
16^th December 2024 respectively. The cost of development
wells in progress, Capital work in progress and Oil & gas
assets as of March 31, 2025 is ' 9,227.33 million (Previous
year ' 45,563.32 million), ' 137,451.85 million (Previous year
' 169,552.16 million) and ' 183,092.08 million (Previous
year ' 80,614 .38 million) respectively under Cluster II.
Considering the changes with respect to approved FDP,
preparation the Revised FDP is under progress for Cluster-
II development.

All the subsea installation works and pipe laying works
related to Gas System except dependency on CPP topsides
has been completed. The CPP topsides were installed using
float over method on March 24, 2024. The LQUP Topside
modules could not be installed after jacket installation due
to unfavorable offshore weather conditions. Installation
of balance topside structures of LQUP is expected to be
completed during FY 25-26. Subsequently the remaining gas
wells of R & A fields will be hooked up to start production.

Further, MC has approved the 4C-3D OBN seismic data
acquisition, processing & interpretation in Cluster-II (for
500SKM) in Mining Lease area after expiry of Exploration
period. The acquisition of data has been completed, and data
processing is under progress.

FDP in respect of Cluster-I was approved for development
of Gas discoveries in E1 and integrated development of Oil
discoveries in F1 field along with nominated fields of GS-
29 area by the Management Committee in FY 2019-20.
Considering the proximity of E-1 well with F-1, there will be
cost saving for marine surveys, mobilization of vessels, hiring
of consultancy services and optimization in subsea facilities
by combining both the projects i.e. (i) GS-29, DWN-F1 and (ii)
DWN-E1. In view of above, it was decided to integrate both
the projects to have time and cost advantage. The same was
appraised to MC vide letter dated 06^th May 2022. Drilling of an
Appraisal cum Development Well GS29_8_A was completed
on April 30, 2021. Integrated development of DWN-E1
and DWN-F1 & GS-29 was appraised to ONGC Executive
committee (EC). EC accorded in principle approval in its
meeting held on 13.04.2022 for hiring of pre-project activities
like Integrated Consultancy Services (i.e. Pre-FEED, FEED
& PMC) ,Marine Surveys (Geophysical, Geotechnical and
Met-ocean surveys),Consultancy services & TPI for Marine
Surveys and EIARA Study .Hiring of Met Ocean Survey, Geo
technical Survey and Integrated Consultancy services have
been awarded and work is under progress. The cost of
development wells in progress and Capital work in progress
as of March 31, 2025 is ' 890.92 million (Previous year '
885.56 million), and ' 554.91 million (Previous year Nil)
respectively under Cluster I.

In respect of Cluster III, the Company has submitted the
FDP for UD-1 discovery of Cluster-III on August 1, 2022.
The FDP, after examination, has been returned by DGH
for re-submitting a robust FDP. The Company proposes
to formulate a robust FDP by incorporating the results of
the proposed 4C-3D OBN seismic study (for 150SKM) for
which approval from MC has been received and the data
acquisition has been completed during current FY. Further,
the Company has requested the Ministry of Petroleum
& Natural Gas to extend the PEL timelines by 41 months,
i.e. up to January 1, 2026, in order to carry out 4C-3D OBN
seismic data acquisition, processing & interpretation in the
UD-1 discovery area. The extension has been approved vide
letter dated 26.12.2023.

In view of the definite plan for development of all the clusters,
the cost of exploratory wells in the block i.e. ' 25,769.43
million (Previous year ' 25,969.21 million) has been carried
over.

10.5. During the year, certain fields of the Company under its
Contract Areas were identified by the Directorate General
of Hydrocarbon (DGH), Ministry of Petroleum & Natural
Gas, Government of India, for bidding under the Discovered
Small Field (DSF) Round IV. The Company will be required
to transfer these fields to the successful bidders upon
completion of the bidding process.

Pending finalization of the recovery mechanism for the
accumulated carrying costs, the Company has recorded
an additional impairment provision of ' 5,786.67 million
during the year. This is in addition to the earlier impairment
provision of ' 8,017.86 million (already accounted for in prior
years) related to the exploratory wells in these fields.

11.1.1. The Company has elected to continue with the carrying
value of its investments in subsidiaries, joint ventures
and associates, measured as per the Previous GAAP and
used that carrying value on the transition date April 1,
2015 in terms of Para D15 (b) (ii) of Ind AS 101 'First -time
Adoption of Indian Accounting Standards'.

11.1.2. The Company is restrained from diluting the investment
as per the covenants in loan agreement till the sponsored
loan is fully repaid.

11.1.3. During the year, the Company has purchased additional
NIL (Previous year 19,960 nos.) equity shares of Petronet
MHB Ltd. (PMHBL), a subsidiary company having face
value of '10 per share.Total investment in PMHBL as
at March 31, 2025 is ' 3,693.31 million (Previous year
' 3,693.31 million).

11.1.4. On ONGC Start-up Fund Trust (controlled entity) had been
categorized as other investments fair valued through profit
and loss (FVTPL) till the FY 2022-23. The same has been
classified as investments in subsidiary as per Ind AS 110
from FY 2023-24 considering significant increase in the fair
value of the underlying investments in start-up companies.

During the year, the Company has subscribed an additional
NIL (previous year 10,000,000 nos.) units of ONGC Start¬
up Fund Trust (registered with SEBI as an Alternative
Investment Fund category I) for the total consideration of
' NIL (previous year ' 100 million).

11.1.5. During the year, the Company has subscribed additional
8,200,000 nos. (Previous year 24,360,000 nos.) equity
shares of Indradhanush Gas Grid Limited (IGGL), a Joint
Venture Company having face value of ' 10 per share at
par value. Total investment in IGGL as at March 31,2025
is ' 2,305.60 million (Previous year ' 2,223.60 million).

11.1.6. On 27.02.2024, a wholly owned subsidiary ONGC Green
Limited (OGL) was incorporated with authorized capital
of ' 1,000 million divided into 100 million equity shares of
' 10 each. OGL shall engage in the value chains of energy
business including Renewable Energy (Solar, Wind,
Hybrid, Hydel, Tidal and Geothermal etc.), Bio-fuels,
Bio-Gas business, Green Hydrogen and its derivatives
like Green Ammonia, Green Methanol, Carbon Capture
Utilisation and Storage and LNG business.

During the year, the authorized capital of OGL was
increased to ' 50,000 million divided into 5,000 million
equity shares of ' 10 each and the company has
subscribed to 4,600 million nos. (Previous year NIL nos.)
equity shares of ONGC Green Limited (OGL), a wholly
owned subsidiary company having face value of ' 10
per share.Accordingly, the total investment in OGL as at
March 31, 2025 is ' 46,000.00 million (Previous year NIL).

11.1.7. During the FY 2024-25, the Company has received
389,422,687 nos. of equity shares from Hindustan
Petroleum Corporation Limited as bonus shares in the
ratio of 1:2.

11.1.8. Pursuant to the approval granted by the Ministry of
Petroleum and Natural Gas (MoP&NG) vide its letter dated
August 9, 2024, the Company, on September 12, 2024,
increased its equity shareholding in ONGC Petro additions
Limited ("OPaL") by 41.80%, via conversion of a portion
of Compulsorily Convertible Debentures amounting to
' 61,070 million into equity shares of face value ' 10
each and conversion of share warrants upon payment of
the balance amount of ' 862.81 million. Consequently,
the Company's shareholding in OPaL increased from
49.36% to 91.16%, and thereby Company gaining control
over OPaL.

There has been further increase in Company's equity
shareholding in OPaL by 4.53% through the settlement
and conversion of the remaining portion of the
Compulsorily Convertible Debentures amounting to
' 16,710.00 million into equity shares and allotment of
' 105,010.00 million fully paid-up equity shares of face
value ' 10 each through subscription to right issue
offered by OPaL. Pursuant to the aforementioned
transactions, the Company's shareholding in OPaL
has further increased from 91.16% to 95.69% as on
March 31,2025.

As at March 31, 2024, OPaL was considered as a Joint
Venture. However, by virtue of the aforesaid investment,
OPaL has become a subsidiary of the Company as ONGC
has attained the power to direct the relevant activities
of OPaL by virtue of being party to the Shareholder's
Agreement and holding majority equity shareholding
in OPaL.

11.6.1. The amount of ' 76.76 mittion (Previous year

' 63.75 million) denotes the fair value of fees towards
financial guarantee given for Mangalore Refinery and
Petrochemicats Limited without any consideration.

11.6.2. The amount of ' 6,373.12 million (Previous year ' 6,038.48
million) includes, (i) ' 4,768.81 million (Previous year
' 4,434.17 million) towards the fair value of guarantee fee
on financial guarantee given without any consideration for
ONGC Videsh Limited and (ii) ' 1,604.31 million (Previous
year ' 1,604.31 million) towards fair value of interest free
loan to ONGC Videsh Limited till January 31,2018.

11.6.3. The amount of ' 16.59 million (Previous year ' 16.59
million) is towards the fair value of guarantee fee on
financial guarantee given without any consideration
for the Company's stepdown subsidiary ONGC Videsh
Rovuma Limited.

11.6.4. The Company had subscribed 3,451,240,000 nos. Share
Warrants of ONGC Petro additions Limited 9.75 per
share warrant, entitling the Company to exchange each
warrant with a Equity Share of Face Value of ' 10 after a
balance payment of ' 0.25 for each share warrant. The
Company on August 23, 2024 has by made the balance
payment of ' 862.81 million and completed the conversion
of the 3,451,240,000 share warrants into equity shares at
par.

11.6.5. The Company had entered into an agreement for
backstopping support towards repayment of principal and
coupon of Compulsory Convertible Debentures (CCDs)
amounting to ' 77,780 million (Previous year balance
' 77,780.00 million) issued by the subsidiary ONGC Petro
additions Limited (OPaL) (erstwhile joint venture) in three
tranches.

The Company, pursuant to approval from Ministry of
Petroleum & Natural Gas (MoP&NG) vide its letter dated
August 9, 2024, has made the principal repayment of
CCDs amounting to ' 77,780.00 million (Previous year
balance ' 77,780.00 million). Consequently, the Company
has converted first and third tranche of CCD amounting
to ' 56,150 million and ' 4,920 million into equity shares
on September 12, 2024, and second tranche of CCD
amounting to ' 16,710 million on October 25, 2024.

Accordingly, the commitment for back stopping support
has settled and the outstanding interest accrued as at
March 31,2025 is ' nil (Previous year ' 2,212.45 million).

Upon settlement and conversion of CCDs into equity
shares of OPaL, the carrying amount of the deemed equity
investment (As at March 31, 2024'62,308.05 million) in
OPaL in relation to the said CCDs have been derecognized
and adjusted with recognition of corresponding equity
investment in OPaL.

The Deemed Investment amount of ' 97.06 million [as
at March 31,2024'94.61 million included in above Note
no. 11.6.(ii)(a)] is recognized towards the fair value of
guarantee fee on financial guarantee given without any
consideration for OPaL.

11.6.6. Company's Joint Venture Indradhanush Gas Grid Limited
(IGGL) had taken a loan sanction of ' 25,940 million from
Oil Industry Development Board (OIDB) on August, 25
2021 for the purpose of implementation of North East
Gas Grid Project guaranteed by the promoters of IGGL in
proportion of these shareholdings. During the year loan
of ' 4,600 million (previous year ' 5,600 million) has been
taken by IGGL out of the sanctioned amount ' 25,940
million. As at March 31,2025 IGGL has availed total loan
of ' 11,200 million (As at March 31, 2024'6,600 million).
The Company has recognized a financial guarantee
obligation in respect of its shareholding in IGGL with a
corresponding recognition of Deemed Investment in IGGL
of ' 85.31 million (As at March 31, 2024 ' 50.50 million)
for the above financial guarantee.

11.6.7. The amount of ' 410.71 million (Previous year NIL) is
towards the fair value of guarantee fee on financial
guarantee given without any consideration for the
Company's stepdown subsidiary OVL Overses IFSC Ltd.

11.6.8. The Board of Directors has accorded its approval,
subject to concurrence of the Govt. of India, if any, for
acquisition of 1,15,20,000 Equity Shares of Mangalore
SEZ Limited (MSEZ), a joint venture of the Company,
from Infrastructure Leasing & Financial Services Limited
(IL&FS) at ' 561.14 million under its right of first refusal.
Subsequent to the acquisition of shares the holding of
ONGC will be increased from 26% to 49%.

12.2. Generally, the Company enters into crude oil and natural gas
sales arrangement with its customers. The normal credit
period on sales of crude, gas and value added products is
7 - 30 days. No interest is charged during this credit period.
Thereafter, interest on delayed payments is charged as per
sales arrangements which provide for interest on delayed
payments at SBI Base rate / SBI MCLR plus 4% - 6.50%
per annum compounded each quarter on the outstanding
balance.

Out of the gross trade receivables as at March 31, 2025
an amount of ' 92,479.02 million (as at March 31, 2024
' 107,771.68 million) is due from Public sector Oil and Gas
Marketing companies, the Company's largest customers.
There are no other customers who represent more than 5%
of total balance of trade receivables.

12.3. I ncludes an amount of ' 3,764.43 million (Previous year
' 3,764.43 million) due towards Pipeline Transportation
Charges for the period from November 20, 2008 to July 6,
2021 from GAIL India Limited (GAIL) on account of revised
pipeline transportation tariff charges.

In terms of Gas Sales Agreement (GSA) signed between GAIL
and the Company, GAIL is to pay transportation charges in
addition to the price of gas in case of Uran Trombay Natural
Gas Pipe Line (UTNGPL) and were being paid by GAIL.
Subsequent to the replacement of pipeline in 2008, the
revised pipeline transportation tariff in respect of UTNGPL
was approved by Petroleum and Natural Gas Regulatory
Board (PNGRB) for which debit notes / invoices was raised
to GAIL with effect from November 20, 2008.

The revised pipeline transportation tariff were to be
ultimately borne by the end consumers of GAIL. Mahanagar
Gas Limited (MGL), one of the customers of GAIL, filed a
complaint with PNGRB on February 12, 2015 regarding
applicability of tariff on supply of gas to GAIL. After hearing all
parties, PNGRB vide order dated October 15, 2015 dismissed
the complaint and gave a verdict in favour of the Company.
Pursuant to appeal by MGL to the Appellate Tribunal for
Electricity (APTEL), the case was remanded back to PNGRB.
Once again, PNGRB vide order dated March 18, 2020 had
dismissed the complaint, authorized the pipeline as a
Common Carrier Pipeline and directed both GAIL and MGL
to pay the transportation tariff fixed by PNGRB from time
to time for UTNGPL. MGL again filed an appeal with APTEL
on April 04, 2020 against the order of PNGRB. APTEL vide
order dated July 16, 2021 remanded the matter to PNGRB
for fresh adjudication and passing final order. PNGRB vide
order dated September 30, 2022, directed MGL to pay the
transportation charges as per the transportation tariff fixed
by PNGRB for UTNGPL vide Tariff Order dated December 30,
2013 for the period from January 1, 2014 onwards, within a
period of 2 months of passing the order. However, PNGRB
rejected the transportation charges from November 20,
2008 to December 31,2013. MGL filed a writ petition before
the Hon'ble High Court of Delhi challenging the PNGRB's
order dated September 30, 2022. The Company has also

filed appeal against the order of PNGRB before APTEL,
however, as on date, due to non-appointment of Technical
member in the P & NG bench of APTEL, pending cases are
not being heard. Accordingly, the Company has brought on
record its appeal as filed before APTEL in the writ petition
filed by MGL since the appeal is not being heard by APTEL
due to unavailability of proper qurom of bench. In the case
filed by MGL, the Hon'ble High Court of Delhi, vide order
dated December 13, 2022, stayed the recovery against the
PNGRB order and directed MGL to deposit a sum of ' 500
million with GAIL. Pending final decision in the matter the
Company has made a provision of ' 745.50 million during FY
2022-23 towards the transportation charges receivable for
the period from November 20, 2008 to December 31,2013.

Rashtriya Chemicals and Fertilisers Ltd (RCF), another
customer of GAIL, was paying revised tariff since February
2016 and the tariff from November 20, 2008 till January
31, 2016, was under dispute. The matter was referred to
Committee of Secretaries under Administrative Mechanism
for Resolution of CPSEs Disputes (AMRCD) that met on
June 17, 2021 and concluded that RCF would pay the
transportation charges with effect from the date of order
(December 30, 2013) of revised tariff rates of PNGRB.
Accordingly, during the year 2021-22 an amount of ' 196.52
million was received pertaining to the period December
30, 2013 to January 31, 2016. The Company has requested
clarification from the MoP&NG regarding the impact of
AMRCD order on its receivable from GAIL. However, in view
of the conclusion of AMRCD, a provision of ' 446.43 million
has been provided against dues from GAIL on account of
Pipeline Transportation Charges in respect of RCF for the
period prior to December 30, 2013.

In view of the above, the balance receivable (excluding
provision) of ' 2,572.50 million as at March 31,2025 (Previous
year ' 2,572.50 million) is considered good.

12.4. I ncludes an amount of ' 1,364.61 million receivable from
IOCL towards sale of crude oil from western offshore during
the month of Mar'23 to Oct'23. Sale of crude oil from Western
offshore to IOCL has been effected on provisional basis
pending finalisation of Crude Oil Sales Agreements (COSA)
with the IOCL. The Company has raised invoices for sale of
crude oil at benchmark prices as applicable for the period
from October' 2022 to February'2023. Pending finalisation
of COSA's, IOCL has released payments for the period from
March'2023 to Oct'23, as per pricing formula benchmark
applicable till September'2022, resulting into an amount of
' 1,364.61 million receivable from IOCL as on March 31,
2025. However a provision of ' 36.98 million has been
provided on account of Basic Excise Duty (BED) and National
Calamity Contingent Duty (NCCD) charges for the month
of Mar' 23 to Oct'23. In the meeting dated 28.03.2025 IOCL
has agreed for the repayment of outstanding amount in
the financial year 2025-26. In view of this, the amount of
' 1,327.63 million receivable towards sale of crude oil from
western offshore region for the month of March'2023 to
Oct'23 is considered good. (Refer note no. 30.1)

15.1. During the year 2010-11, the Oil Marketing Companies,
nominees of the Government of India (GoI) recovered USD
80.18 million (Share of the Company USD 32.07 million
(equivalent to ' 2,747.97 million) as per directives of GoI in
respect of Joint Operation - Panna Mukta and Tapti Production
Sharing Contracts (PSCs). Pending finality by Arbitration
Tribunal, the Company's share of USD 32.07 million equivalent
to ' 2,747.97 million (March 31,2024: ' 2,673.36 million) has
been disclosed under the head 'Advance/ claim recoverable in
Cash' (refer Note No. 49.1.1 (d)).

15.2. I n Ravva Joint Operation, the demand towards additional
profit petroleum raised by Government of India (GoI),
due to differences in interpretation of the provisions
of the Production Sharing Contract (PSC) in respect of
computation of Post Tax Rate of Return (PTRR), based on
the decision of the Malaysian High Court setting aside an
earlier arbitral tribunal award in favor of operator, was
disputed by the operator Vedanta Limited (erstwhile Cairn
India Limited). The Company is not a party to the dispute
but has agreed to abide by the decision applicable to the
operator. The Company is carrying an amount of USD 167.84
million (equivalent to ' 14,380.93 million) after adjustments
for interest and exchange rate fluctuations which has been
recovered by GoI, this includes interest amounting to USD

54.88 million (equivalent to ' 4,702.12 million). The Company
has made impairment provision towards this recovery made
by the GoI.

In subsequent legal proceedings, the Appellate Authority of
the Honorable Malaysian High Court of Kuala Lumpur had
set aside the decision of the Malaysian High Court and the
earlier decision of arbitral tribunal in favour of operator was
restored, against which the GoI has preferred an appeal
before the Federal Court of Malaysia. The Federal Court
of Malaysia, vide its order dated October 11, 2011, has
dismissed the said appeal of the GoI.

The Company has taken up the matter regarding refund of
the recoveries made in view of the favorable judgment of
the Federal Court of Malaysia with Ministry of Petroleum
and Natural Gas (MoP&NG), GoI. However, according to a
communication dated January 13, 2012, MoP&NG expressed
the view that the Company's proposal would be examined
when the issue of carry in Ravva PSC is decided in its entirety
by the Government along with other partners.

In view of the perceived uncertainties in obtaining the refund
at this stage, the impairment made in the books as above
has been retained against the amount recoverable.

17.1. The value of 649,041 nos. Carbon Credits (CER) (Previous year 3,30,484 nos.) has been treated as Nil (as at March 31,2024 Nil) as
the same do not have any quoted price and seems to be insignificant with respect to net realisable value. There are no CERs under
certification. During the year ' 339.46 million (' 284.43 million for 2023-24) and ' 187.51 million (' 227.67 million for 2023-24) have
been expensed towards Operating & maintenance cost and depreciation respectively for emission reduction equipment.

17.2. I nventory amounting to ' 1,187.35 million (as at March 31, 2024 ' 9,065.75 million) has been valued at net realisable
value of ' 198.63 million (as at March 31, 2024 ' 4,032.64 million). Consequently, an amount of ' 988.72 million (as
at March 31, 2024 ' 5,033.11 million) has been recognised as an expense in the Statement of Profit and Loss under
note 33.

21.1. I ncLudes forfeited shares of ' 0.15 million and assessed
value of assets received as gift.

21.2. Capital Redemption Reserve created as per Companies Act'
2013 against buy back of its own shares during FY 2018-19.

21.3. The Company has elected to recognise changes in the fair
value of certain investments in equity securities through
other comprehensive income. This reserve represents
the cumulative gains and losses arising on revaluation of
equity instruments measured at fair value through other
comprehensive income. The Company transfers amounts
from this reserve to retained earnings when the relevant
equity securities are disposed off.

21.4. General Reserve is used from time to time to transfer profits
from retained earnings for appropriation purposes, as the same
is created by transfer from one component of equity to another.

21.5. The amount that can be distributed by the Company
as dividends to its equity shareholders is determined
considering the requirements of the Companies Act, 2013
and the dividend distribution policy of the Company.

On November 11, 2024 and January 31, 2025, the Company
had declared an interim dividend of ' 6 per share (120%) and
' 5.00 per share (100%) respectively which has since been
paid.

In respect of the year ended March 31, 2025, the Board of
Directors has proposed a final dividend of ' 1.25 per share
(25%) be paid on fully paid-up equity shares. This final
dividend shall be subject to approval by shareholders at the
ensuing Annual General Meeting and has not been included
as a liability in these financial statements. The proposed
equity dividend is payable to all holders of fully paid equity
shares. The total estimated equity dividend to be paid is
' 15,725 million.

21.6. During the 2020-21, 18,972 equity shares of ' 10 each
(equivalent to 37,944 equity shares of ' 5 each) which were
forfeited in the year 2006-07 were cancelled w.e.f. November
13, 2020 and accordingly the partly paid up amount of ' 0.15
million against these shares were transferred to the Capital
Reserve in 2020-21.

24.2. 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, wells in progress
etc. at the end of their economic lives. Most of these
decommissioning activities would be in the future for which
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 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. The timing and amount of future
expenditures are reviewed annually, together with rate of
inflation for escalation of current cost estimates and the
interest rate used in discounting the cash flows.

24.3. The PMT Joint Venture partners—Shefl (through BGEPIL),
RIL and ONGC have issued a joint statement on 5 May
2025 to share the information on successful completion of
country's first offshore facilities decommissioning project
with the safe removal of Mid and South Tapti Part B field
facilities. The safe disposal of the offshore facilities at
onshore yard is in progress. The disposal obligation will be
met by the Contractors from the decommissioning liability
and SRF deposits maintained in this regard. The Company

do not foresee any additional obligation in this regard.

24.4. Includes ' 37,375.17 million (Previous year ' 33,216.05
million) accounted as provision for contingency to the
extent of excess of accumulated balance in the SRF fund
after estimating the decommissioning provision of Panna-
Mukta fields and Tapti Part A facilities as per the Company's
accounting policy. (refer note no. 5.2, 6.1 & 14.2)

24.5. The Company has made provision in the books to the
extent of ' 171,191.09 million towards disputed ST/GST on
Royalty (together with interest thereon) for the period from
April 1,2016, to Mach 31,2025 (' 146,535.16 million till March
31, 2024). The provision pertaining to the FY 2024-2025 is
' 24,655.93 million. (refer Note 49.1.1.b)

24.6. A suspected fraud was noticed by the Company, wherein
some of its regular / contractual employees in collusion
with some vendors have made certain fictitious medical
payments involving misappropriation of funds, the matter
is being investigated by internal and external agencies and
the final amount of the alleged fraud shall be known after
the outcome of the investigation. Pending investigations
an interim amount of ' 2.88 million (previous year ' 2.88
million) has been affirmed as a fraud on the Company and
accordingly provision for the said amount has been made
towards doubtful claims receivable from vendors.

30.1. Sales revenue from crude oil produced across the Western
Offshore, Western Onshore, and Southern regions is
recognized based on the pricing formula prescribed under
the respective Crude Oil Sales Agreements (COSA) entered
into with the designated buyer refineries.

Western Offshore Region: COSAs have been executed with
Hindustan Petroleum Corporation Limited (HPCL), Bharat
Petroleum Corporation Limited (BPCL), Mangalore Refinery
and Petrochemicals Limited (MRPL), and Chennai Petroleum
Corporation Limited (CPCL), and are valid up to March 31,
2025. The execution of a COSA with Indian Oil Corporation
Limited (IOCL) is currently in progress and is expected to be
finalized shortly.

Western Onshore Region: The COSA with IOCL was valid
until March 31,2024. The process of executing a new COSA
with IOCL is underway and is expected to be completed in
due course.

Southern Region: The COSA with CPCL for crude oil supplied
from Rajahmundry and Eastern offshore asset (EOA) is valid
till March 31,2025. Additionally, the COSA with IOCL & HPCL
for crude oil supplies from the Rajahmundry and EOA asset
are currently under process. Further, the COSA with CPCL
for Cauvery asset is under finalization.

North East Region: Sales revenue from crude oil produced
is supplied to IOCL & Numalgrah Refinery Limited (NRL)
and is recognized based on the pricing formula prescribed
by Ministry of Petroleum and Natural gas (MoP&NG). COSA
with IOCL is valid upto March 31,2026 and with NRL is under
the process of finalization.

30.2. Majority of sales revenue of Natural Gas is based on
Domestic Natural Gas Price which is fixed by Government
of India (Gol) from time to time in terms of New Domestic
Natural Gas Pricing Guidelines, 2014 dated Oct 25, 2014 as
amended vide the MoP&NG Notification dated April 7, 2023.

As per the amended Guidelines, w.e.f. 08.04.2023, Domestic
Natural Gas Price (or APM Price) shall be 10% of Indian Crude

Basket (ICB) price published by PPAC on monthly basis. For
the gas produced by ONGC from their nomination fields, the
APM price shall be subject to a floor and a ceiling. The initial
floor and ceiling prices shall be US$4/MMBTU and US$6.5/
MMBTU respectively. The ceiling would be maintained for
FY 2023-24 and FY 2024-25 and then increased by US$0.25/
MMBTU each year.

New Well Gas: The said notification of 07.04.2023 also
provides Gas produced from new well or well intervention in
the nomination fields of ONGC would be allowed a premium
of 20% on these APM prices. Therefore, price applicable to
such New Well gas is 12% of ICB). MoP&NG, vide letters
dated 08.08.2024, allocated New Well Gas of ONGC to GAIL
for supply to CNG-Transport and PNG-Domestic segments of
City Gas Distribution (CGD) sector and to C2-C3 Dahej Plant of
ONGC for production and supply of feed stock to OPaL.

Government of India subsidizes gas sales to consumers in
North East. The consumer price charged by the company
from the gas customers for subsidized gas upto the quantity
allocated by the GoI is 60% of the aforesaid Domestic Natural
Gas Price (with ceiling of of US$ 6.50 / mmbtu). The balance
40% of the price is paid to the company through Gol Budget
shown as 'North-East Gas Subsidy'.

30.3. LPG produced by the Company is presently being sold as
per guideline issued by MoP&NG to PSU Oil Marketing
Companies (OMCs), as per provision of Memorandum of
Understanding (MOU) dated March 31, 2002 signed by the
Company with OMCs which was valid for a period of 2 years
or till the same is replaced by a bilateral agreement or on
its termination. The terms of bilateral agreement for sale
of LPG between ONGC and OMCs have been finalized and
the agreement is under the process of necessary internal
approvals and signing.

30.4. Value Added Products other than LPG are sold to different
customers at prices agreed in respective Term sheets /
Agreements entered into between the parties.

(iii) Fixation of rate of interest to be credited to members'
accounts.

43.2.3 Gratuity

Gratuity is payable for 15 days salary for each completed
year of service. Vesting period is 5 years and the payment
is restricted to ' 2 million on superannuation, resignation,
termination, disablement or on death.

Scheme is funded through own Gratuity Trust. The
liability for gratuity is recognized on the basis of actuarial
valuation.

43.2.4 Post-Retirement Medical Benefits

The Company has Post-Retirement Medical benefit
(PRMB), under which the retired employees, their spouses
and dependent parents are provided medical facilities in
the Company hospitals / empaneled hospitals. They can
also avail treatment as out-patient. The liability for the
same is recognized annually on the basis of actuarial
valuation. Full medical benefits on voluntary retirement
are available subject to the completion of minimum 20
years of service and 55 years of age.

An employee should have put in a minimum of 15 years
of service rendered in continuity in the Company at the
time of superannuation to be eligible for availing post¬
retirement medical facilities. However, as per DPE
guidelines dated August 03, 2017, the Post-Retirement
Medical Benefits is allowed to Board Level executives
(without any linkage to 15 years of service) upon
completion of their tenure or upon attaining the age of
retirement, whichever is earlier.

Scheme is funded through own PRMB Trust. The liability
for PRMB is recognized on the basis of actuarial valuation.

43.2.5 Terminal Benefits

At the time of superannuation, employees are entitled to
settle at a place of their choice and they are eligible for
Settlement Allowance. The liability for Terminal Benefits
is recognized on the basis of actuarial valuation.

43.2.6 These defined benefit plans typically expose the Company
to actuarial risks such as: investment risk, interest rate
risk, longevity risk and salary / cost risk.

43.2.7 No other post - retirement benefits are provided to these
employees.

In respect of the above plans, the most recent actuarial
valuation of the plan assets and the present value of the
defined benefit obligation were carried out as at March
31,2025 by a member firm of the Institute of Actuaries of
India. The present value of the defined benefit obligation,
and the related current service cost and past service cost,
were measured using the projected unit credit method.

43.2.8 Other long term employee benefits

(i) Earned Leave (EL) Benefit

Accrual - 30 days per year

Encashment while in service - 75% of Earned Leave
balance subject to a maximum of 90 days per calendar
year

Encashment on retirement - Maximum 300 days

Scheme is 100% managed by an insurance company (Life
Insurance Corporation of India (LIC)) through a separate
trust.

The liability for the same is recognized annually on the
basis of actuarial valuation.

Each employee is entitled to get 15 earned leaves for each
completed half year of service. All regular employees of
the Company while in service are allowed encashment of
Earned Leave once in a calendar year, to the extent of 75%
of the Earned Leave at their credit, subject to maximum
of 90 days.

In addition, each employee is entitled to get 10 HPL(Half
Pay Leave) at the end of every six months. The entire
accumulation is permitted for encashment only at the
time of retirement. Department of Public Enterprise
had clarified earlier that sick leave cannot be encashed,
though Earned Leave (EL) and Half Pay Leave (HPL)
could be considered for encashment on retirement
subject to the overall limit of 300 days. Consequently,
Ministry of Petroleum and Natural Gas (MoP&NG),
GOI had advised the Company to comply with the DPE
Guidelines. Subsequently, the matter has been dealt in
3^rd Pay Revision Committee recommendations, which
is effective January 1, 2017 and Central Public Sector

The discount rate is based upon the market yield available on Indian Government securities at the accounting date with a term that
matches the weighted average duration of present benefit obligations. The salary growth takes account inflation, seniority, promotion
and other relevant factors on long term basis. In case of funded schemes, expected return on plan assets is same as that of respective
discount rate. Interest cost on Defined benefit Obligation and expected return on Plan Asset has been calculated based on previous year
discount rate/expected rate of return.

The mortality rate for Male insured lives before retirement have been assumed for Actuarial Valuation as on March 31, 2025 as per
100% of Indian Assured Life Mortality (2012-14) issued by Institute of Actuaries of India on August 2, 2018. As separate rates applicable
for female lives has not been notified by The Institute of Actuaries of India, uniform rates of mortality for Male have been used for both
Male and Female employees for computation of Employee Benefit Liability. The mortality rate after retirement is assumed as per Indian
Individual Annuitant's Mortality Table (2012-15) effective from April 01, 2021.

45.3. Disclosure in respect of Government related Entities

The Company is a Central Public Sector Enterprise (CPSE) under the administrative control of the Ministry of Petroleum & Natural
Gas (MoP&NG), in which the Government of India holds 58.89%of paid-up equity share capital. The Company has transactions with
other Government related entities, which significantly include but are not limited to sale of crude oil and natural gas, purchase of
stores and spares, purchase of capital items, maintenance and other services etc. Transactions with these parties are carried out
in the ordinary course of business on arm's length basis and at terms comparable with those offered to other entities that are not
Government-related.

46. Financial instruments Disclosure

46.1. Capital Management

The Company's objective when managing capital is to:

• Safeguard its ability to continue as going concern so that the Company is able to provide maximum return to stakeholders and
benefits for other stakeholders; and

• Maintain an optimal capital structure to reduce the cost of capital.

The Company maintains its financial framework to support the pursuit of value growth for shareholders, while ensuring a secure
financial base. In order to maintain or adjust the capital structure, the Company may adjust the amount of dividends to shareholders,
return capital to shareholders, issue new shares or sell assets to reduce debt.

The capital structure of the Company consists of total equity (refer Note No. 20 & 21). The Company is not subject to any externally
imposed capital requirements.

The management of the Company reviews the capital structure on a regular basis. As part of this review, the committee considers the
cost of capital, risks associated with each class of capital requirements and maintenance of adequate liquidity.

46.1.1. Gearing Ratio

The Company has outstanding current and non-current borrowings / debt. Accordingly, the gearing ratio is worked out as
followed:

46.3. Financial risk management objectives

While ensuring liquidity is sufficient to meet Company's
operational requirements, the Company also monitors and
manages key financial risks relating to the operations of the
Company by analyzing exposures by degree and magnitude of
risks. These risks include credit risk, liquidity risk and market
risk (including currency risk and price risk).

During the year, the liquidity position of the Company was
comfortable. The lines of Credit/short term loan available
with various banks for meeting the short term working
capital/ deficit requirements were sufficient for meeting the
fund requirements. The Company has also an overall limit of
' 100,000 million for raising funds through Commercial Paper.
Cash flow/ liquidity position is reviewed on continuous basis.

46.4. Credit risk management

Credit risk arises from cash and cash equivalents,
investments carried at amortized cost and deposits
with banks as well as customers including receivables.
Credit risk management considers available reasonable
and supportive forward-looking information including
indicators like external credit rating (as far as available),
macro-economic information (such as regulatory changes,
government directives, market interest rate).

Major customers, being public sector oil marketing
companies (OMCs) and gas companies having highest
credit ratings, carry negligible credit risk. Concentration of
credit risk to any other counterparty did not exceed 2.72%
(Previous year 2.35%) of total monetary assets at any time
during the year.

Credit exposure is managed by counterparty limits for
investment of surplus funds which is reviewed by the
Management. Investments in liquid plan/schemes are with
public sector Asset Management Companies having highest
rating. For banks, only high rated banks are considered for
placement of deposits. Bank balances are held with reputed
and creditworthy banking institutions.

The Company is exposed to default risk in relation to
financial guarantees given to banks / vendors on behalf of
subsidiaries / joint venture companies for the estimated
amount that would be payable to the third party for assuming
the obligation. The Company's maximum exposure in this
regard on as at March 31,2025 is ' 437,210.35 million (As at
March 31, 2024'426,266.10 million).

In accordance with Ind AS 109- Financial Instruments, the
Company uses the expected credit loss (“ECL") model for
measurement and recognition of impairment loss on its
trade receivables and other financial assets.

For the purpose of computing expected credit loss, the
Company follows rating-based approach to compute
default rates based on Credit ratings of the borrowers and
forward-looking estimates are incorporated using relevant
macroeconomic indicators. A default occurs when in the
view of management there is no significant possibility
of recovery of receivables after considering all available
options for recovery.

The movement in the loss allowance for impairment of
financial assets at amortized cost during the year was as
follows:

The Company along with its wholly owned subsidiary ONGC Videsh
Limited, had set up Euro Medium Term Note (EMTN) Program for
USD 2 billion on August 27, 2019 which was listed on Singapore
Stock Exchange and subsequently on India International
Exchange (India INX) and will mature in December 05, 2029. The
EMTN program was updated by the Company along with its wholly
owned subsidiaries ONGC Videsh Limited and ONGC Videsh
Vankorneft Ltd. on April 19, 2021 for drawdown. However, further
update in EMTN program would be carried out depending upon
the visibility on the requirement of funds.

The domestic debt capital market was tapped by the Company
during FY 2020-21 by issuance of four series of Non-Convertible
Debentures (NCD) aggregating to ' 41,400 million on private
placement basis. Details of NCDs outstanding as on March
31,2025 are given under Note no 27.2.

The Company has access to committed credit facilities and the
details of facilities used are given below. The Company expects
to meet its other obligations from operating cash flows and
proceeds of maturing financial assets.

# At the year-end, the cash credit limit was ' 75,000 million (Previous
year ' 45,000 million] considering business requirement of the Company.
The cash credit limit of ' NIL (Previous year ' NIL million] was utilized as
working capital loan.

Besides the above, the Company had arrangement for unutilized
short term loan facilities of ' 55,000 million as on March 31, 2025
(Previous year ' 57,500 million] with other banks.

The Company also had an unutilized limit of ' 100,000 million
(Previous year ' 100,000 million] for raising funds through
Commercial Paper.

46.6. Market Risk

Market risk is the risk or uncertainty arising from possible
market price movements and their impact on the future
performance of a business. The major components of
market risk are price risk, currency risk and interest rate
risk.

The primary commodity price risks that the Company is
exposed to international crude oil and gas prices that could
adversely affect the value of the Company's financial assets
or expected future cash flows. Substantial or extended
decline in international prices of crude oil and natural gas
may have an adverse effect on the Company's reported
results. The management has assessed the possible impact
of continuing Ukraine - Russia conflict on the basis of
internal and external sources of information and expects no

significant impact on the continuity of operations, useful life
of Property Plant and Equipment, recoverability of assets,
trade receivables etc., and the financial position of the Company
on a long term basis. The Company is constantly carrying out
macro level analysis and keeping a vigilant eye on global reports
& analysis being done by global analyst & firms.

46.6.1.1. Currency risk

Sale price of crude oil is denominated in United States
dollar (USD] though billed and received in Indian Rupees
(']. The Company is, therefore, exposed to foreign
currency risk principally out of ' appreciating against
USD. Foreign currency risks on account of receipts /
revenue and payments / expenses are managed by
netting off naturally-occurring opposite exposures
through export earnings, wherever possible and carry
unhedged exposures for the residual considering the
natural hedge available to it from domestic sales.

The Company undertakes transactions denominated in
different foreign currencies and consequently exposed
to exchange rate fluctuations. Exchange rate exposures
are managed within approved policy parameters.

The Company has a Foreign exchange and Interest Risk
Management Policy (RMP] with objective to ensure
that foreign exchange exposures on both revenue
and balance sheet accounts are properly computed,
recorded and monitored, risks are limited to tolerable
levels and an efficient process is created for reporting
of risk and evaluation of risk management operations.

The primary objective of the RMP is limitation / reduction
of risk and a Forex Risk Management Committee
(FRMC] with appropriate authority and structured
responsibility are in place for the management of
foreign exchange risk. The FRMC identifies, assesses,
monitor and manage / mitigate appropriately within
the legal and regulatory framework.

The Company has a Hedging policy so that exposures
are identified and measured across the Company,
accordingly, appropriate hedging can be done on net
exposure basis. The Company has a structured risk
management policy to hedge foreign exchange risk
within acceptable risk limit. Hedging instrument
includes plain vanilla forward (including plain vanilla
swaps] and option contract. FRMC decides and take
necessary decisions regarding selection of hedging
instruments based on market volatility, market
conditions, legal framework, global events and other
macro-economic situations. All the decisions and
strategies are taken in line and within the approved
Foreign exchange and Interest Risk Management
Policy. Since the Company is naturally hedged, hedging
decisions are triggered in case of a Net Exposure
exceeds USD 500 million. During the year, no hedging
decision was necessitated as net exposure of USD 500
million was not breached.

46.6.1.2. Interest rate risk management

The Company is exposed to interest rate risk because
the Company has borrowed funds benchmarked to
overnight MCLR, Treasury Bills, debt (capital) market,
RBI Repo. The Company's exposure to interest rates are
detailed in Note No. 27.

The Company invests the surplus fund generated from
operations in term deposits with banks and mutual
funds. Bank deposits are generally made for a period of
upto 12 months and carry interest rate as per prevailing
market interest rate. Considering these bank deposits
are short term in nature, there is no significant interest
rate risk. Average interest earned on term deposit and
a mutual fund for the year ended March 31, 2025 was
7.85% p.a. (Previous year 7.67% p.a.).

The Company's fixed rate instruments are carried
at amortized cost. They are therefore not subject to
interest rate risk, since neither the carrying amount nor
the future cash flows will fluctuate because of a change
in market interest rates.

Cash flow sensitivity analysis for variable-rate
instruments

The Sensitivity of finance cost to change in ( /-) 50 basis
point in average interest rate is presented as under:

46.6.1.3. Price risks

The Company's price risk arises from investments
in equity shares (other than investment in group
companies) held and classified in the balance sheet
either at fair value through other comprehensive income
(FVTOCI) or at fair value through profit or loss (FVTPL).

Investment of short-term surplus funds of the Company
in liquid schemes of mutual funds provides high level of
liquidity from a portfolio of money market securities and
high quality debt and categorized as 'low risk' product
from liquidity and interest rate risk perspectives.

The revenue from operations of the Company are also
subject to price risk on account of change in prices of
Crude Oil, Natural Gas & Value Added Products.

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.

46.7.1.2. There has been no change in the valuation methodology
for Level 3 inputs during the year. The Company has
not classified any material financial instruments under
Level 3 of the fair value hierarchy. The sensitivity of
change in the unobservable inputs used in fair valuation
of Level 3 financial assets and liabilities does not have a
significant impact on their value.

46.7.1.3. There have been no transfers in either direction (i.e.
between level 1,2 and 3) for the years ended 31 March
2025 and 31 March 2024.

46.7.1.4. Some of the Company's financial assets and financial
liabilities are measured at fair value at the end of the
financial year. The following table gives information
about how the fair values of these financial assets/ and
financial liabilities are determined.

47.1.5. During the previous year, in respect of 1 NELP block
and 2 OALP blocks, the Company's share of Unfinished
Minimum Work Programme (MWP) amounting to
' 6,710.47 million was not provided for since the Company
had already applied for further extension of period in
these blocks as 'excusable delay'/ special dispensations
citing technical complexities, within the extension
policy of NELP/OALP Blocks, which were under active
consideration of Gol. The delays had occurred generally
on account of pending statutory clearances from various
Govt. authorities like Ministry of Defence, Ministry of
Commerce & Industry, environmental clearances, State
Govt. permissions etc. The MWP amount of ' 6,710.47
million was included in MWP commitment under note no.
49.3.2 (i). During the financial year 2024-25, there is no
such case.

In respect of 3 NELP blocks (As at March 31, 2024 - 5
NELP blocks), the Company had provided liability for
principal amount against Cost of Unfinished Minimum
Work Programme (CoUMWP) based on own estimates/
recent communication from DGH/ MoP&NG. The balance
liability as at March 31, 2025 is ' 6,981.50 million (As at
March 31, 2024 ' 6,925.35 million). However, no liability
has been provided towards the interest component
as the Company is pursuing the said matters with the
concerned authorities for waiver as the said liabilities are
on account of delays due to environmental clearances,
other regulatory permissions etc. and the Company is
confident that the said matters shall be amicably settled
in its favour.

As per the Production/Revenue Sharing Contracts signed
by the Company with the Gol, the Company is required to
complete Minimum Work Programme (MWP)/ Committed
Work Programme (CWP) within stipulated time. In case
of delay in completion of the MWP/ CWP, Liquidated
Damages (LD)/Fees are payable for extension of time
to complete MWP/ CWP. Further, in case the Company
does not complete MWP/ CWP or surrenders the block
without completing the MWP/ CWP, the estimated cost
of completing balance work programme is required to be
paid to the Gol. LD/ Fees amounting to ' 105.96 million
(Previous year ' 124.13 million) and cost of unfinished
MWP/ CWP amounting to ' 473.07 million (Previous year
' 1,034.40 million), paid/payable to the Gol is included in
survey and wells written off expenditure respectively.

47.1.6. Government of India vide its letter dated June 01, 2017
has approved the relinquishment of 30% Participating
Interest (PI) of the Company in block RJ-ON/6 and
assignment of its future rights and obligations to acquire
30% PI in any of the discoveries in the block in favour of
operator Focus Energy Limited(FEL) and other JV partners
in proportion to their respective PIs on the condition that
Focus Energy Limited (Operator) will reimburse all past
cost incurred by the Company towards royalty, PEL/ML
fees, other statutory levies and bear the unpaid liability of
the Company in development and production cost in SGL
Field of the block. Pending the recovery of outstanding
dues towards royalty, PEL/ML fees, other statutory
levies, no adjustment in the accounts has been made
post relinquishment from the block RJ-ON/6. During the

FY 2022-23, the Company has invoked arbitration against
FEL and other JV partners to recover its outstanding
dues and the Arbitral hearing in this regard is underway.
Total outstanding dues recoverable towards royalty, PEL/
ML fees, other statutory levies as on March 31, 2025 is
' 2,592.38 million (previous year ' 2,569.80 million).

47.1.7. The Company is having 30% Participating interest in
Block RJ-ON-90/1 along with Vedanta Limited (erstwhile
Cairn India Limited) (Operator) and Cairn Energy
Hydrocarbons Limited. The Company, as Government
nominee under Article 13.2 is Liable to contribute its share
as per the PI, only for the development & production
operations, and is not LiabLe to share ExpLoration Cost
which was upheld in Arbitral Award in PCA case 2019-30.

However, Operator has recovered exploration cost (beyond
exploration phase of PSC) which was subject matter of
Arbitration between Vedanta and GOI in PCA case 2020¬
39. Pending finality of Quantification of claims and cost
recovery amounts an amount of USD 233.54 million
(equivalent to ' 20,009.71 million) Liability (Previous
year USD 233.54 million and equivalent ' 19,467.89
million) being 30% of USD 778.46 million (equivalent to
' 66,689.07 million) ( previous year USD 778.46 million
and equivalent to ' 64,892.05 million) ) has been disclosed
under Contingent Liabilities.

Further, pursuant to final award dated 31.07.2023 in PCA
case 2019-30 between ONGC and Vedanta, a sum of USD
166.37 million awarded to claimants M/s. Vedanta has
been adjusted against a sum of USD 190.302 million
awarded to respondents M/s. ONGC towards outstanding
royalty receivable and a net receivable of USD 34.656
million (equivalent to ' 2,969.33 million, including
Interest and Costs awarded to the tune of USD 10.724
million) ,has been shown as receivable from JV Partners
in books of Accounts.

47.1.8. The primary period of twenty five years of the Production
Sharing Contract (PSC) of the Block RJ-ON-90/1 expired
on May 14, 2020. During the FY 2022-23, an addendum
No. 2 to PSC was executed on October 27, 2022 extending
the term of the PSC of the block for a period of 10 years
retrospectively w.e.f. May 15, 2020.

Government of India demanded payment of Additional
Profit Petroleum of USD 1,660.06 million (' 1,42,233.83
million) (previous year USD 1,660.06 million and
equivalent ' 1,38,382.50 million) in respect of the Block
RJ-ON-90/1 against the audit exceptions as per the PSC
provisions as per the latest demand letter in this regard
dated 06.09.2022. The said demand is under Arbitration
proceedings between Vedanta and GOI in PCA case 2020¬
39 wherein the Company (ONGC) is not a party to the
Arbitration against Government of India. The said demand
has been dismissed by Arbitral Tribunal vide their Award
dated 22.08.2023 and 08.12.2023 however the quantum of
the same is pending before the Delhi High Court.

Pending Finality of outcome and quantifications in Award
in PCA case 2020-39 between M/s. Vedanta and GOI,
the Company share of USD 498.02 million (' 42,670.14
million) (previous year USD 498.02 million (' 41,514.75
million)) being 30% of USD 1,660.06 million (' 142,233.80
million) (previous year USD 1,660.06 million (' 138,382.50
million)) of the demand for additional profit petroleum
on account of Audit Exceptions has been disclosed under
Contingent liabilities.

47.1.9. In respect of Jharia CBM Block, revised Feasibility Report
(FR) has been approved in the meeting of Steering
Committee (SC) held on September 9, 2019. In the light of
overlap issue with Bharat Coking Coal Limited Companies
and in view of better techno-economics, the Company
has decided to implement the revised FR in phases for
early implementation and monetization. The Parbatpur
and adjoining areas was taken up in Phase-I under the
approved FR and accordingly, implementation strategy
for Stage-I for Jharia CBM Block has been approved by
the Company on November 21, 2019 and the Operating
Committee (OC) in its meeting held on December 10,
2019. The same was communicated to the JO Partner,
Coal India Limited (CIL) and was approved by the Board of
Directors of CIL in its meeting held on January 10, 2020.

As per Performa provided by DGH, all the formalities
for enhancement of participating interest (PI) from 10%
of CIL to 26% were completed by both the Company
(Assignor) and CIL (Assignee) and the signed documents
were submitted to DGH for the approval of GoI on January
27, 2020. However, GoI, on the basis of the application
and supporting documents granted enhancement of PI of
CIL from 10% to 26% w.e.f. January 25, 2021. This was
contested by the Company as the provision and timing of
exercising the option of enhancing PI from 10% to 26%
is very clearly defined in the Joint Operating Agreement
(JOA) i.e. the option shall be exercised by CIL before
the start of Development Phase. Accordingly, DGH and
MoPNG were requested to consider April 23, 2013 which
is the start date of development phase activity and the
date of commencement of PI enhancement as per JOA,
as delay in PI enhancement is primarily due to late
submission of requisite documents by CIL.

On the basis of our representation DGH vide its letter
dated 16.04.2024 has clarified that development
phase commencement date for Jharia CBM Block is
April 23,2013. Considering the clarification from DGH,
provisions of JOA and approval of Steering Committee,
the cash calls amounting to ' 707.95 million from CIL
have been continued to be recognized at 26% w.e.f. April
23, 2013 upto January 24, 2021 as against ' 272.29 million
of cash calls at the rate of 10% PI up to January 24, 2021.

ONGC has received ' 818.90 million on 22.01.2025
towards the long outstanding cash call from CIL and
in continuation to follow-up with CIL for the balance
amount.

47.1.10. I n respect of Raniganj (N) CBM Block, the Feasibility
Report (FR) exploring different variants to optimize the
cost has been worked out for early implementation
and monetization, in light of overlap issue with Bengal
Aerotropolis Project Limited, CM (SP) Blocks and the
Company has decided to implement the Revised FR
in stages. The area excluding all overlap issue was
taken up in current phase under the approved FR and
accordingly, implementation strategy has been approved
by the Company on December 8, 2022 and the Operating
Committee (OC) on February 13, 2023. Revised Feasibility
Report (FR) has been approved in-principal in the
Steering Committee (SC) held on March 3, 2023. Pending
final decision on the Block, an impairment provision of
' 617.75 million has been provided in the books.

ONGC has received ' 44.61 million on 22.01.2025 towards
the long outstanding cash call from CIL. In line with
treatment given in case of Jharia Block.

47.1.11. During the year 2017-18 the Company had acquired
the entire 80% Participating Interest (PI) of Gujarat
State Petroleum Corporation Limited (GSPC) along with
operatorship rights, at a purchase consideration of USD
995.26 million (equivalent to ' 62,950.20 million) for Deen
Dayal West (DDW) Field in the Block KG-OSN-2001/3.
The revised PI in the block after above acquisition stands
for the Company 80%, GSPC 10% and Jubilant Offshore
Drilling Private Limited (JODPL) 10%.A farm-in Farm-out
agreement (FIFO) was signed with GSPC on March 10,
2017 and the said consideration has been paid on August
04, 2017 being the closing date. During the FY 2022-23,
accounting for the final closing adjustment (i.e. working
capital and other adjustments) to sale consideration viz.
transactions from the economic date up to the closing
date has been provisionally carried out and a sum of
' 993.92 million is net payable to GSPC as final settlement
and the same is under deliberation. As per FIFO, the
Company is entitled to receive sums as adjustments
to the consideration already paid based on the actual
gas production and the differential in agreed gas price.
Pending executing mother wells and estimating future
production, the contingent adjustment to consideration
remains to be quantified. The Company has also paid
part consideration of USD 200 million (equivalent to
' 12,650.00 million) for six discoveries other than DDW
Field in the Block KG-OSN-2001/3 to GSPC towards
acquisition rights for these discoveries in the Block KG-
OSN-2001/3 to be adjusted against the valuation of such
fields based on valuation parameters agreed between
GSPC and the Company. During the year the EWIP
acquisition cost amounting to ' 12,650.00 million has
been written off as the economic indicators of the Six
discoveries area are unviable for further development to
have commercial exploitation of Gas.

The JO partner JODPL is under liquidation since
December 2017 and has defaulted all the cash calls since

acquisition of the block by the Company. The amount of
outstanding cash call from JODPL as at March 31, 2025
is ' 2,432.62 million (Previous year: ' 2,145.69 million).
The assignment of JODPL's 10% PI in accordance with
provisions of Production sharing Contract (PSC) is
pending with Management Committee (MC). As per
provision of the Joint Operating Agreement (JOA), the
receivable amount of ' 2,432.62 million (Previous year:
' 2,145.69 million) after the acquisition of block is
required to be contributed by the non-defaulting JV
Partner in their ratio of participating interest. Pending
decision of assignment of JODPL's PI by MC a provision
for an amount of ' 2,162.32 million (Previous year:
' 1,907.28 million) has been made against the said cash
call receivables from JODPL, being the Company's share
as per PI ratios.

47.1.12. In case of Block CB-ONN-2004/3, the discovery well
Uber#2 ceased to flow from June 23, 2020. The Company
in consultation with JV partner Gujarat State Petroleum
Corporation Limited has initiated a proposal for
examination / surrendering the block CB-ONN-2004/3
and relinquishment of the development area of 10.78
sq. km. During Management Committee (MC) meeting
in May 2022, Government nominee advised to submit
firm future plans within 60 days from receipt of the MC
approval or else relinquish the field for future bidding
round. The proposal for surrender of the block has been
initiated by the Company being the operator and pending
with DGH, an impairment loss of ' 373 million has been
provided in the books.

47.1.13. The designated currency, for the purpose of cost recovery
under the Production Sharing Contracts (PSC) is USD.
Thus, the expenditure incurred in Indian Rupees (?)
needs to be converted in USD for the preparation of
cost recovery statements. The Company has already
submitted the draft Management Committee agendas
for the corresponding blocks for adoption of State Bank
of India (SBI) reference rate in place of Reserve Bank of
India (RBI) reference rate for preparation of cost recovery
statements.

The management committee (MC) of the block named
VN-ONN-2009/3 has recommended to the Government
for approval of SBI reference rate in lieu of RBI reference
rate for the conversion purpose between USD and ' in
modification of provision laid down under the PSC. The
MC also recommended that the same may be extended
to other similarly placed PSCs of the operator. MC further
recommended that the above dispensation to opt for
SBI exchange rate may be made available as one time
measure also to other operators, should they opt to do
so, provided they have adopted SBI exchange rate at the
corporate level.

Subsequently, Directorate General of Hydrocarbons
(DGH) which is PSC monitoring arm of the Ministry of

Petroleum and Natural Gas (MoPNG), Government of
India, submitted the proposal for the approval of MoPNG
for adoption of SBI reference rate in lieu of RBI reference
rate for the block VN-ONN-2009/3 in May 2020 which is at
present pending with MoPNG.

The Company is following the SBI reference exchange
rates on consistent basis for maintenance of accounts as
the main banker of the Company is State Bank of India, and
there is no impact on the Company financial statements
due to adoption of SBI exchange rate, as the transactions
of foreign currency in the Company are recorded at actual
cost basis and foreign currency liabilities & assets at
period end are also recognised as per SBI reference rate.
The financial implication for adoption of SBI reference
rate preparation of cost recovery statements with DGH,
as against the RBI reference rate is immaterial.