Oil and Gas Reserve Estimation and Disclosures (unaudited)

The following tables provide supplementary information in respect of the Group’s oil and gas activities. In the absence of detailed disclosure rules in this area under IFRS, the Group has elected to voluntarily disclose the data that would have been required under the ASC 932 as if it was reporting under US GAAP.

To the extent that information refers to financial statements data, the information is based on the primary financial statements (IFRS financial statements).

Disclosed financial data refers to operating business segment Exploration & Production (E&P) excluding gas supply, marketing, trading and logistics in Western Europe. Further information on OMV’s operating segments is included in Note 4 – Segment Reporting.

The regional structure is presented below*Regions listed in the Director’s Report ‘Central and Eastern Europe’ (includes Romania and Black Sea as well as Austria) and ‘Asia-Pacific’ (includes New Zealand and Australia as well as Malaysia) are split further in this disclosure to provide the information in a more detailed manner.:

Acquisitions

There were no major acquisitions during 2022, 2021 and 2020.

Disposals & Deconsolidation

Starting with March 1, 2022 OMV ceased to fully consolidate JSC GAZPROM YRGM Development, due to the loss of control, following the Russia-Ukraine crisis. For further details refer to Note 2 – Accounting policies, judgements and estimates, section ‘Impact of Russia’s invasion of Ukraine and related significant estimates and assumptions’.

On August 1, 2021, SapuraOMV Upstream Sdn. Bhd. sold its share in SapuraOMV Upstream (PM) Inc., which held interests in various producing assets located offshore Peninsular Malaysia.

As per May 14, 2021, OMV Petrom finalized the sale of its 100% share in Kom-Munai LLP and Tasbulat Oil Corporation LLP (both based in Aktau, Kazakhstan).

There were no major disposals during 2020.

Non-controlling interest

As OMV holds 51% of OMV Petrom, which is fully consolidated; figures therefore include 100% of OMV Petrom assets and results.

OMV has a share of 50% in SapuraOMV and it is fully consolidated; figures therefore include 100% of SapuraOMV assets and results.

Equity-accounted investments

OMV holds a 10% interest in Pearl Petroleum Company Limited (Middle East and Africa region).

Starting with March 1, 2022 OMV ceased to equity account its 24.99% interest in OJSC Severneftegazprom (Russia region) due to loss of significant influence. For further details refer to Note 2 – Accounting policies, judgements and estimates, section ‘Impact of Russia’s invasion of Ukraine and related significant estimates and assumptions’.

The disclosures of equity-accounted investments in below tables represent the interest of OMV in the companies.

The subsequent tables may contain rounding differences.

Tables

a) Capitalized costs

Capitalized costs represent the sum of capitalized oil and gas assets, including other intangible assets and property, plant and equipment such as land, plant and machinery, concessions, licenses and rights.

b) Costs incurred

Costs incurred include all costs, capitalized or expensed, during the year in the Group’s oil and gas property acquisition, exploration and development activities.

c) Results of operations of oil and gas producing activities

The following tables represent only those revenues and expenses which occur directly in connection with OMV´s oil and gas producing operations. The results of oil and gas activities should not be equated to Exploration & Production net income since interest costs, general corporate overhead costs, other costs and gas supply, marketing, trading and logistics in Western Europe are not allocated. Further information on OMV’s operating segments is included in Note 4 – Segment Reporting. Income taxes are hypothetically calculated, based on the statutory tax rates and the effect of tax credits on investments and loss carryforwards.

d) Oil and gas reserve quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved oil and gas reserves were estimated based on a 12-month average price, unless prices are defined by contractual arrangements.

Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the costs of the required equipment are relatively minor compared with the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate. It should be reasonably certain that the required future expenditure will be made to safeguard existing equipment within the current budget.

Proved undeveloped reserves are those proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion or substantial new investment is required in order to safeguard or replace ageing facilities.

e) Standardized measure of discounted future net cash flows

The future net cash flow information is based on the assumption that the prevailing economic and operating conditions will persist throughout the time during which proved reserves will be produced. Neither the effects of future pricing changes nor expected changes in technology and operating practices are considered.

Future cash inflows represent the revenues received from production volumes, including cushion gas held in storage reservoirs, assuming that the future production is sold at prices used in estimating year-end quantities of proved reserves (12 months average price). Future production costs include the estimated expenditures for production of the proved reserves plus any production taxes without consideration of future inflation. Future decommissioning costs comprise the net costs associated with decommissioning wells and facilities. Future development costs include the estimated costs of development drilling and installation of production facilities. For all three categories year-end costs without consideration of inflation are assumed. Future income tax payments are calculated on the basis of the income tax rate applicable in each of the countries in which the Group operates. The present cash value results from the discounting of the future net cash flow at a discount rate of 10% per year. The standardized measure does not purport to be an estimate of the fair value of the Group’s proven reserves. An estimate of fair value would also take into account, amongst many other factors, the expected recovery of reserves in excess of proved reserves, anticipated changes in future prices and costs as well as a discount factor representative of the risks inherent in the production of oil and gas.

f) Changes in the standardized measure of discounted future net cash flows