6 July 2018 ECU Tax Bulletin Introduction of AIT: The State Duma Has Passed the Bill in its Third Reading EY s Russian Tax & Law practice was named a leading Tax firm in Russia in World Tax 2017, an annual guide published by the International Tax Review. On 5 July a draft federal law on the introduction of a tax on additional income from mineral extraction (additional income tax or AIT ) was passed by the State Duma in the third reading. 1 The draft law contains provisions setting out the procedure for the application of the new oil industry tax on oil, natural fuel gas, gas condensate and associated gas, as well as adjustments to the rules for the calculation of mineral extraction tax (MET) on oil. It also reduces excise duty rates for certain oil products and amends other tax law. After being submitted to the State Duma on 28 November 2017 (see EY s Tax Messenger dated 1 December 2017), the draft law was passed in the first reading on 3 April and in the second reading on 3 July. 1 http://sozd.parlament.gov.ru/bill/325651-7
In this bulletin we will highlight the major changes to the AIT provisions and examine the other tax amendments included in the draft law. The main changes were made at the second reading stage, with only drafting corrections being made between the second and third readings. The AIT Regime The provisions regarding AIT payers, the calculation of depletion level, the tax period, the tax base, the tax rate, as well as regarding the tax declaration and the time limits for the payment of tax have not changed. The special procedure for calculating the rate of MET on oil under the AIT regime also remained unchanged in the second reading, but it is now provided that if the coefficient C gr has a value of less than 1, the oil export duty value applied in the computation of the rate of MET on oil for Group 4 sites should be taken as the actual value (i.e. not zero as in the case of subsurface sites of Groups 1 and 2). The procedure for carrying forward current losses has not changed, but a modification made for the second reading reflected a request by certain companies to allow users of Group 4 subsurface sites to take account of historical losses made in retrospective periods before the transition to the AIT (in line with the procedure for subsurface sites of Groups 1 and 2). Object of Taxation As before, the object of taxation is additional income earned by companies from hydrocarbon extraction at four groups of subsurface sites. There have been no major changes to the main characteristics of the four groups of subsurface sites. Since, however, an understanding of these characteristics is crucial to the application of the new regime, we present below a detailed description of all four groups (with changes highlighted in red). Group 1. New subsurface sites situated wholly or partially in the Russian section of the seabed of the Caspian Sea and in the Republic of Sakha (Yakutia), the Irkutsk Province, the Krasnoyarsk Region, the Yamal-Nenets Autonomous District north of 65 degrees of northern latitude and the Nenets Autonomous District with an oil reserve depletion level of less than or equal to 0.05 as at 1 January 2017 (excluding subsurface sites specified in Group 2). The group also includes subsurface sites situated in those regions for which reserves were first entered on the state balance sheet of mineral reserves after 1 January 2017. Group 2. New subsurface sites which include hydrocarbon reserves of deposits specified in Note 8 to the unified Goods Nomenclature for Foreign Economic Activities of the Eurasian Economic Union as at 1 January 2018. Group 3. Subsurface sites under development (brownfields) which are situated wholly or partially in the Khanty-Mansiisk and Yamal- Nenets Autonomous Districts, the Republic of Komi and the Tyumen Province with an oil reserve depletion level: greater than or equal to 0.2, but less than or equal to 0.8 as at 1 January 2017 greater than or equal to 0.1 but less than or equal to 0.8 as at 1 January 2017 if the depletion level of the subsurface site as at 1 January 2011 is greater than 0.01 and if the site has been under development for at least six years as at 1 January 2017 Group 4. New subsurface sites situated wholly or partially in the Khanty-Mansiisk and Yamal- Nenets Autonomous Districts, the Republic of Komi and the Tyumen Province with an oil reserve depletion level of less than or equal to 0.05 and initial recoverable oil reserves of less than 10 million tonnes as at 1 January 2017. In the case of subsurface sites of Groups 3 and 4 the draft law establishes precise geographical co-ordinates subject to: a limit on aggregate oil and gas condensate production for 2016 for all Group 3 subsurface sites of not more than 15 million tonnes a limit on aggregate initial recoverable oil and gas condensate reserves as at 1 January 2017 for all Group 4 subsurface sites of not more than 51 million tonnes In the event that the geographical co-ordinates of subsurface sites of Groups 3 and 4 have changed as a result of changes in site boundaries, provided that the aggregate initial recoverable reserves of oil and gas condensate of each such subsurface site have not increased by more than 20%, those subsurface sites will be 2
treated as an object of taxation within the boundaries of the changed geographical coordinates. The wording of the definition of additional income has also been modified. It is now defined as the sequential difference between theoretical revenue from sales of hydrocarbons, as determined in the manner described in the Theoretical Revenue from Sales of Hydrocarbons section of this article, and the amount of actual hydrocarbon extraction expenses and the amount of theoretical hydrocarbon extraction expenses at a subsurface site, the procedure for determining which is described in the Actual Hydrocarbon Extraction Expenses and Theoretical Hydrocarbon Extraction Expenses sections below. Transition to AIT Companies which are users of Group 1 subsurface sites have the right to opt out of transition to AIT by sending a notification to the tax authority in the prescribed form and manner by: 31 March 2019 (if reserves were placed on the state balance sheet of mineral reserves before 1 January 2018) 31 March of the second year following the year in which oil reserves were first placed on the state balance sheet of mineral reserves (if there are no reserves on the state balance sheet as at 1 January 2018) Under revisions made for the second reading, this right also applies to users of subsurface sites for which the proportion of all categories of recoverable gas reserves relative to the total hydrocarbon reserves of a subsurface site (Ch g) exceeds 50% according to data in the state balance sheet of mineral reserves. Ch g is calculated using the following formula: Ch g = R g x 35 (R g + R ag) x 35 + (R o + R gc) x 42, where R g is total recoverable gas reserves at a subsurface site expressed in thousands of cubic metres R ag is total recoverable associated gas reserves at a subsurface site expressed in thousands of cubic metres R n is total recoverable oil reserves at a subsurface site expressed in tonnes R gc is total recoverable gas condensate reserves at a subsurface site expressed in tonnes In this case, companies must send a notification to the tax authority by 31 December of the year preceding the year commencing from which the company is to cease acting as a taxpayer in relation to the subsurface site in question. Where subsurface sites of this kind are concerned, the decision to opt out of the AIT regime is made on a one-time basis. Companies which are users of Group 2 subsurface sites will be able to transfer to AIT by submitting a notification of the exercise of the right to apply AIT in any form by 1 January 2020. A company would not in this case be considered to be applying the AIT regime during 2019. Companies which are users of subsurface sites of Groups 3 and 4 are obliged to transfer to the AIT regime without the right to opt out. Theoretical Revenue from Hydrocarbon Sales For the most part, the procedure for determining theoretical revenue was unchanged in the draft law presented for the second reading. Since, however, certain definitions have been modified, we present below a full, updated version of the description of this section. Theoretical revenue from hydrocarbon sales is the sum of amounts of revenue from sales of hydrocarbons extracted from subsurface sites of Groups 1 to 4 for each month of the tax (accounting) period, determined cumulatively using the following formula: R c-month=p oil х V oc х R х C n + P gas х V gas + 0.95 х P ag х V ag where: R c-month is theoretical revenue from the sale of extracted hydrocarbons for the month P oil is the average global market price of Urals oil for the month in US dollars per barrel V oc is the volume of oil and gas condensate extracted from a subsurface site during the month, expressed in tonnes 3
R is the average US dollar-russian rouble exchange rate for the month C n is the coefficient for converting metric tonnes into barrels, equal to 7.3 P gas is the natural gas price for the extraction region concerned in a calendar month in roubles per thousand cubic metres, set by the authorized body. The revised text provides that where extracted gas is sold by a taxpayer to a non-related entity under a sale contract, the taxpayer may use the contract price per thousand cubic metres of gas, minus costs for the transportation of the gas by third parties to the place at which ownership of the gas passes to the buyer (provided that those costs were not included in the contract price), as P gas for the volume of gas concerned. A gas sale contract concluded by a taxpayer with Gazprom companies during the 12 months preceding the date of conclusion of a contract is considered to have been concluded with a non-related entity V gas is the quantity of natural gas extracted from a subsurface site in the month in thousands of cubic metres, excluding natural gas injected into the formation to maintain pressure during extraction in accordance with the technical plan for deposit development P ag is the price of associated gas determined as the arithmetic mean of actual prices of sales of associated gas for the month to non-related entities in roubles per thousand cubic metres, less the arithmetic mean of costs for the transportation of the gas by third parties to the place at which ownership of the gas passes to the buyer (provided that those costs were not included in the contract price). If there were no sales of associated gas to such entities, P gas determined for the relevant month is used as P ag V ag is the quantity of associated gas extracted at a subsurface site, excluding natural gas injected into the formation to maintain pressure during extraction or for storage on the basis of a relevant licence issued under Russian subsoil law in accordance with the technical plan for deposit development, in thousands of cubic metres The draft law specifies that the quantity of hydrocarbons extracted at a subsurface site is to be determined exclusive of normative losses. Actual Hydrocarbon Extraction Expenses As before, the draft law defines actual expenses relating to the development of a subsurface site for the purpose of hydrocarbon extraction as costs directly associated with activities involved in developing a subsurface site. The list of activities involved in developing a subsurface site has been extended to include the leasing of property to a person who renders services to (performs work for) a taxpayer in connection with the carrying on of one or more activities for the purposes of hydrocarbon extraction (exploration, extraction, transportation of hydrocarbons and other activities specified in Article 333.43 of the Tax Code). Actual expenses for a subsurface site are divided into actual expenses incurred for the acquisition, erection, manufacture and delivery of depreciable assets and in rendering them fit for use (excluding VAT and excise duties) and actual production and sale expenses: 1) Actual expenses incurred for the acquisition, erection, manufacture and delivery of assets and in rendering them fit for use are to be recognised in the period in which payment (partial payment) was made in the amount of actual expenditure making up the historical cost of the assets and expenditure on the extension, reconstruction and modernization of the assets, including where, at the time when the expenses are recognised, some or all of the amount of the expenses has not been included in the historical cost of a particular fixed asset (fixed assets). If the taxpayer incurred these expenses internally, they should be recognised in the period in which they occurred. The text of the draft law prepared for the second reading provides that where, on the date on which costs are recognised, a company is unable to class them as costs associated with activities involved in developing a subsurface site, the costs in question should be recognised in the tax (accounting) period in which the company decided to class those costs as actual expenses associated with activities involved in developing a subsurface site or in which there falls the date on which a depreciable asset was brought into use (or 4
the date on which its historical cost changed). The selected approach to the recognition of such costs must be established in the accounting policies. Actual expenses for the acquisition of depreciable assets which were previously deducted for taxation purposes must be restored in the following cases: Where a depreciable asset is sold (or otherwise disposed of), temporarily removed from service or placed under modernization or reconstruction (except where the assets continue to be used in the company s activities in the process of reconstruction of modernization) for more than three months less than three years after the expenses in question were deducted Where a depreciable asset is not brought into use within three years after the expenses in question were deducted (seven years in the case of the application of the reduced coefficient C gr (in the formula for MET on oil) and (or) in a retrospective period in calculating historical losses for subsurface sites of Groups 1, 2 and 4) The expenses in question must be restored by increasing the tax base for the tax period in which the assets were disposed of, temporarily removed from service or placed under modernization or reconstruction or in which three years (seven years) have elapsed since the assets were brought into use, and should be recognised for taxation purposes in an amount equal to the product of amounts of previously recognised expenses for the acquisition of depreciable assets and the loss indexation coefficient of 1.163 raised to a power corresponding to the number of tax periods which have passed from the tax period in which the expenses in question were previously deducted. When an asset is brought back into operation as a result of reactivation and (or) the completion of modernization, amounts of expenses which were restored (added to the tax base for the relevant tax period included in income) should be included in actual expenses from the month following the month in which the asset was brought back into operation 2) Actual expenses associated with production and sale are understood to mean the following types of costs which are classed as production and sale expenses (excluding depreciation charges) and non-sale expenses: Material expenses Labour payment expenses Expenses for the repair, maintenance and servicing of fixed assets and other assets Expenses for the development of natural resources, including onetime, regular and other payments for subsurface use R&D expenses Expenses for compulsory and voluntary insurance Expenses for the storage and transportation of oil and gas condensate to the commercial metering station at which the transfer of extracted hydrocarbons to third parties takes place Expenses associated with well interventions and geological and geophysical services Expenses referred to in a number of subsections of clause 1 of Article 264 of the Tax Code Expenses referred to in subsections 8 (excluding amounts of depreciation), 9, 12 and 17 of clause 1 and subsection 6 of clause 2 of Article 265 of the Tax Code Costs incurred for services involving the transportation of hydrocarbons after the metering station at which the transfer of extracted hydrocarbons to third parties takes place and amounts of profits tax and AIT are not included in actual production and sale expenses. 5
Actual production and sale expenses are recognised in the manner prescribed by Articles 261 (insofar as expenses for the development of natural resources are concerned), 262 and 272 of the Tax Code. Expenses incurred by a company in a tax (accounting) period may be taken into account for AIT purposes in full without being divided into direct and indirect expenses or allocated to balances of work in progress and (or) balances of unsold finished products. Companies which have transferred to AIT are obliged to maintain separate records of actual expenses for each subsurface site in relation to which the tax base for AIT is determined. The procedure for maintaining separate records must be established in a company s accounting policies. The draft law also introduces a requirement for separate records to be maintained of actual expenses which cannot be directly attributed to a particular subsurface site based on the proportion stated in the company s accounting policies. The procedure for maintaining separate records must be established by a company for a period of five years. This is half the length of time stated in the draft law at the first reading stage. A company may change the procedure before the lapse of five tax periods only if approval is obtained from the tax authorities. Amounts included in actual expenses for one subsurface site cannot be included in expenses for that or another site a second time. A company is also granted the right to submit an application to a tax authority for approval of its expense allocation procedure, including in relation to expenses which cannot be directly attributed to a specific subsurface site. Theoretical Hydrocarbon Extraction Expenses As before, theoretical expenses are defined as the sum of theoretical transportation costs and theoretical export customs duty. The formulae for the calculation of these values have remained the same. The text of the draft law in the second reading differs solely in providing that only the established value of the indicative tariff may be used in determining theoretical transportation costs. Determination of Minimum Tax Under the AIT regime, the amount of AIT may not be less than the amount of minimum tax, the base for which is determined as the difference between theoretical income from hydrocarbon extraction and the following amounts: 1) theoretical expenses for a subsurface site for the tax (accounting) period 2) actual expenses for a subsurface site for the tax (accounting) period insofar as amounts of taxes are concerned 3) the amount of maximum hydrocarbon extraction expenses, equal to the product of the quantity of oil extracted from a subsurface site in the tax (accounting) period and a unit cost coefficient equal to 9,520 roubles (7,140 roubles for 2019-2020 ). The draft law as revised for the third reading states that, as from 2021, the unit cost coefficient will be subject to annual indexation by the amount of the cumulative consumer price index change If the minimum tax base has a negative value, the minimum tax will be zero. In addition, in the case of subsurface sites of Groups 1, 2 and 4, the minimum tax base is taken to be zero in those periods in which the coefficient C gr in the formula for MET on oil is less than 1 for subsurface sites of the relevant group during the entire tax period. Other Changes Excise Duties on Oil Products In view of the situation in the domestic motor fuel market and rising prices, a decision has been made to reduce the rates of excise duty on petrol and diesel from 1 June to 31 December 2018 (see table below). 6
Roubles per tonne from 1 January to 30 June 2018 (current tax system) from 1 July to 31 December 2018 (current tax system) from 1 January to 31 May 2018 (draft) from 1 June to 30 June 2018 (draft) from 1 July to 31 December 2018 (draft) Petrol: Not class 5 Class 5 13,100 11,213 13,100 11,892 13,100 11,213 13,100 8,213 13,100 8,213 Diesel 7,665 8,258 7,665 5,665 5,665 Motor oils 5,400 5,400 5,400 5,400 5,400 Straight-run petrol 13,100 13,100 13,100 13,100 13,100 Benzene, paraxylene, orthoxylene 2,800 2,800 2,800 2,800 2,800 Jet fuel 2,800 2,800 2,800 2,800 2,800 Medium distillates 8,662 8,662 8,662 6,665 6,665 Thin Capitalization Rules New content in the draft law presented for the second reading includes an amendment to the rules governing the recognition of interest on loans (Article 269 of the Tax Code) whereby a debt obligation will not be considered controlled for a taxpayer if the following conditions are met: 1) the funds comprising that indebtedness are used exclusively for the financing of an investment project carried out in Russia 2) the terms of the agreement under which the indebtedness arose provide for settlement of the debt to start no earlier than five years after it arose 3) the aggregate direct and indirect participating interest of the related foreign person in the Russian company is not greater than 35% 4) the place of registration (place of tax residence) of the person to whom the debt obligation has arisen is a foreign state with which a double taxation agreement has been concluded An investment project is defined as the creation in Russia of a new production complex for the manufacture of goods and (or) the provision of services. A production complex is considered to be new if it was brought into operation after 1 January 2019 and was not previously in operation. Taxation of Loans for the Financing of Foreign Geological Exploration Projects The draft law prepared for the second reading amends Articles 105.3, 261, 271 and 325 of the Tax Code to add provisions concerning the taxation of loans for the financing of foreign geological exploration projects abroad ( foreign exploration projects ). The draft law defines a foreign exploration project to mean activities of a foreign company outside Russia and Russia s continental shelf and within the boundaries of a spatial feature with defined geographical co-ordinates which involve the geological study of subsurface resources, prospecting for and appraisal of mineral deposits and mineral exploration where the following conditions are met: 1) the foreign company in question, as its main activity, participates in mineral extraction projects carried out in accordance with production sharing agreements, concession agreements, licence agreements or other similar agreements on a risk basis 2) the foreign company in question is a party to one or more such agreements or the establishment of the foreign company in question is provided for in one or more such agreements, and it carries on mineral extraction activities on the basis of and in accordance with the terms of those agreements 7
3) the above-mentioned agreements clearly establish the geographical co-ordinates of the spatial features within whose boundaries activities involving the geological study of subsurface resources, prospecting for and appraisal of mineral deposits and mineral exploration are carried on A loan for the financing of a foreign exploration project means the provision of property under a loan agreement which simultaneously meets the following conditions: 1) the loan agreement has been concluded between a Russian company as the lender and a foreign company which actually carries on activities associated with the implementation of the foreign exploration project as the borrower, and the latter is a related party of that Russian company in accordance with clause 2 of Article 105.1 of the Tax Code during the entire term of the loan agreement 2) the loan agreement was originally concluded after 1 January 2018 3) the loan agreement requires property received under the loan agreement to be used by the borrower only for activities associated with the implementation of the foreign exploration project 4) the Russian taxpayer company has made a decision to treat the amount of the loan granted under the relevant agreement as a loan for the financing of a foreign exploration project for taxation purposes It follows from point 4 above that the application of the special taxation rules for loans for the financing of foreign exploration projects is voluntary. A taxpayer must notify its local tax authority of its decision to treat a loan meeting the above-mentioned conditions as a loan for the financing of a foreign exploration project not later than the first day of the tax (accounting) period following the tax (accounting) period in which the relevant loan agreement was concluded. This decision is made once and cannot later be changed. The date of issuance of a loan for the financing of a foreign exploration project is the date on which the lender (the Russian company) first transfers funds to the borrower (the foreign company) under the relevant loan agreement. Where a new loan agreement is concluded in place of an existing agreement (or the conditions of an existing agreement are amended), the date of issuance of the loan is the date on which the original obligation arose between the parties. Under the draft law, the tax treatment of loans for the financing of foreign exploration projects is made largely dependent on whether the project in question is judged to be successful or economically unsound and (or) geologically unprospective. Classing of a Foreign Exploration Project as Successful or Economically Unsound and (or) Geologically Unprospective Under the draft law, a taxpayer classes a foreign exploration project as successful or economically unsound and (or) geologically unprospective in accordance with the procedure established in tax accounting policies (which must include the criteria for defining a project as successful or economically unsound and (or) geologically unprospective). That procedure must be approved by the taxpayer before the date of issuance of the first loan for the financing of the foreign exploration project and may not be changed for 10 consecutive tax periods starting from the period in which it was approved. The taxpayer is also obliged to notify the tax authority of the fact that a foreign exploration project has been classed as successful or economically unsound and (or) geologically unprospective in the same way as notification is given of the decision to treat a loan as a loan for the financing of a foreign exploration project, as described above. Treatment of Interest Income The draft law inserts special provisions in Article 271 of the Tax Code regarding the treatment of interest income on loans for the financing of foreign exploration projects. Income in the form of interest charged under a loan agreement for the financing of a foreign exploration project over the period from the date of issuance of the loan to the last day of the month in which the date of the decision on the 8
foreign exploration project falls should be treated as follows: if obligations under the loan agreement for the financing of a foreign exploration project are terminated in full without the taxpayer s property claims being satisfied owing to the fact that work on the foreign exploration project has ceased and the project has been classed as economically unsound and (or) geologically unprospective it should not be recognised for taxation purposes if the loan agreement is not in compliance with one of the conditions established for loan agreements for the financing of a foreign exploration project it should be recognised in full as at the first day of the month following the month in which that condition was violated in other cases it should be recognised in even amounts over two years starting from the month following the month in which the date of the decision on the foreign exploration project falls The date of a decision on a foreign exploration project should be understood to mean the earliest of the following dates: the date on which the taxpayer makes the decision on the degree of success of the foreign exploration project the date on which obligations under the loan agreement are terminated in full without the taxpayer s property claims being satisfied owing to the fact that work on the foreign exploration project has ceased and the project has been classed as economically unsound and (or) geologically unprospective the date of the termination (partial termination) of obligations under the loan agreement the date as at which the loan agreement ceased to be in compliance with one of the conditions established for the treatment of a loan as a loan for the financing of a foreign exploration project for taxation purposes the last day of the month in which 7 consecutive calendar years elapse from the date of issuance of the loan for the financing of the foreign exploration project The draft law also establishes that interest actually received (in monetary form or in kind or by means of the netting of claims and obligations) by a taxpayer under a loan agreement for the financing of a foreign exploration project in the period from the date of issuance of the loan until the last day of the month in which the date of the decision on that foreign exploration project falls should be recognised as at the date on which it is received, which is determined in the manner prescribed by clause 2 of Article 273 of the Tax Code (the cash-basis recognition of income). Thus, the general approach in the draft law in regard to the treatment of interest income on loans for the financing of foreign exploration projects is for the recognition of income for taxation purposes to be deferred until the date on which a decision is made on whether or not the foreign exploration project is successful (or until the lapse of seven years from the date of issuance of the loan), subject to certain special considerations. Treatment of Income and Expenses in the Form of Exchange Rate Gains and Losses The draft law establishes that claims denominated in foreign currency under a loan agreement for the financing of a foreign exploration project (including interest owed) must be translated into roubles at the official exchange rate set by the CBR on the date of the decision on the foreign exploration project (see under Treatment of Interest Income ). Income in the form of an exchange rate gain and (or) expense in the form of an exchange rate loss resulting from the translation of such claims should be recognised as non-sale income (expenses) as follows: if obligations under the loan agreement for the financing of a foreign exploration project are terminated in full without the taxpayer s property claims being satisfied owing to the fact that work on the foreign exploration project has ceased and the project has been classed as economically unsound and (or) geologically unprospective they should not be recognised for taxation purposes 9
if the loan agreement is not in compliance with one of the conditions established for loan agreements for the financing of a foreign exploration project they should be recognised in full as at the last day of the month following the month in which that condition was violated in other cases they should be recognised in even amounts over two years starting from the month following the month in which the date of the decision on the foreign exploration project falls Starting from the day following the date of the decision on the foreign exploration project, claims denominated in foreign currency under the loan agreements concerned should be translated in accordance with the standard procedure laid down in clause 8 of Article 271 and clause 10 of Article 272 of the Tax Code. Treatment of the Amount of a Loan for the Financing of a Foreign Exploration Project as Expenses for the Development of Natural Resources New provisions are added to Article 261 of the Tax Code according to which expenses for the development of natural resources also include expenses incurred by a taxpayer which granted a loan for the financing of a foreign exploration project in the amount of that loan (excluding interest charges), if obligations under the loan agreement have been terminated in full without the taxpayer s property claims being satisfied owing to the fact that work on the foreign exploration project has ceased and the project has been classed as economically unsound and (or) geologically unprospective. The expenses in question are to be included in other expenses in even amounts over two years from the first day of the month following the month in which obligations under the loan agreement were terminated in full as a result of the foreign exploration project being classed as economically unsound and (or) geologically unprospective. Application of Transfer Pricing Rules to Loans for the Financing of Foreign Exploration Projects The draft law provides that where non-arm s length interest rates are applied by a taxpayer in loan agreements for the financing of foreign exploration projects and this causes profits tax to be understated or losses to be overstated, the taxpayer has the right to adjust the tax base and the amount of tax (loss) independently after the end of the calendar year in which income from the transaction in question was recognised as income in accordance with the above-mentioned special provisions. MET on Natural Gas Application of the Zero Rate The text of the draft law prepared for the second reading provides for a zero MET rate to be applied to natural gas (other than associated gas) injected into the formation to maintain pressure during the extraction of gas condensate within one or more subsurface sites which have been licensed for use in accordance with a technical plan for deposit development which provides for such work to be performed at those subsurface sites. The current wording of Article 342 of the Tax Code allows for the zero rate of MET to be applied to natural gas injected into the formation within one subsurface site, which adversely affects the project economics for the deposit development plan as a whole. Coefficient Reflecting the Export Return on a Unit of Standard Fuel in the Formula for the Calculation of MET on Natural Gas Under the proposed changes, the coefficient C gp which is used in calculating the rate of MET on natural gas (as part of the coefficient reflecting the export return on a unit of standard fuel) is increased from 1.4022 to 2.055 from 1 September to 31 December 2018 for companies which are owners of facilities of the Unified Gas Supply System and (or) in which owners of facilities of the Unified Gas Supply System have a direct and (or) indirect participating interest amounting to more than 50% (Gazprom companies). What it means for you The amendments introduced by the draft law will only affect some companies in the industry, but it is important to understand now what impact they are likely to have on the development of the oil and gas market. We would be happy to assist in: 10
Analysing loans made to assess whether they will be affected by the new provisions of the Tax Code Examining the scope for the application of tax preferences in relation to current deposit development plans Evaluating the advisability of transferring to the AIT regime Authors: Victor Borodin Anna Sokolova Anastasia Maryina For additional information please contact the author of this publication: Victor Borodin +7 (495) 755 9760 Victor.Borodin@ru.ey.com 11
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