Organisation for Economic Co-operation and Development

ARGENTINA: GENERAL METADATA Data documentation General notes The fiscal year in Argentina coincides with the calendar year. The Republic of Argentina is a federal country comprising twenty-three provinces and one autonomous city (Autonomous City of Buenos Aires - CABA), which is the capital city of the country. Methodological notes This inventory includes monetary transfers made by the National Administration to finance the current expenditures of different stakeholders related to the energy sector, including state-owned companies, private companies and trust funds. It also includes tax expenditures related to taxes on fuels (motor gasoline, diesel fuel and compressed natural gas). These are calculated by the government as revenue foregone when a tax treatment other than the one established in more general terms in the tax laws, or a different tax treatment to substitute goods, is provided (Ministerio de Hacienda y Finanzas Públicas, 2016).

AUSTRALIA: GENERAL METADATA Data documentation General notes The fiscal year in Australia runs from 1July to 30June. Following OECD convention, data are allocated to the starting calendar year so that data covering the period July2005 to June2006 are allocated to 2005. Australia being a federal country, the data also cover the following states and territories: the Australian Capital Territory (ACT), New South Wales (NSW), the Northern Territory (NT), Queensland (QLD), South Australia (SA), Tasmania (TAS), Victoria (VIC), and Western Australia (WA). Certain features of Australia’s tax system that indirectly support the production of fossil fuels apply to the mining sector as a whole. While the OECD’s approach to support for fossil fuels stresses the importance of specificity [1], the present inventory considers those measures that apply to mining in general to be specific enough to warrant their inclusion in the database. In the absence of data on the actual sector distribution of the usage of these measures, as in other countries, the OECD has estimated based on relative levels of output or exploration expenditure the share of the usage that relates to fossil-fuel extraction, as opposed to the share relating to the extraction of other minerals (e.g. gold or zinc). This estimation should not be interpreted, however, as reflecting the views of the responsible governments. [2] Because 90% of Australia’s power generation uses fossil fuels (and coal in particular), and taking into account the fact that the country does not trade electricity with other economies, measures directly supporting the use of electricity in Australia are here treated as indirect support for fossil fuels. Since Victoria is the only state where recoverable brown coal reserves are available, all state-level measures in place in other states and benefitting coal have been allocated to hard coal only. [ABS Mineral Account (1996) and Minerals Council of Australia (2015) Coal Hard Facts] Notes relating to Producer Support Estimates The offshore extraction of oil and natural gas in Australia is subject to a particular tax regime combining a resource tax and the regular corporate income tax. The former, the Petroleum Resource Rent Tax (PRRT), was introduced with the Petroleum Resource Rent Tax Assessment Act of 1987. It is project-based and applies to taxable profits at the rate of 40%. [3] Rules under the PRRT allow for the full deduction of exploration, development, and decommissioning expenditures in the year in which they are incurred. Financing costs are, however, not deductible for PRRT purposes. Unclaimed deductions can be carried forward and compounded every year at varying rates. Some of these deductions can also be transferred to other projects within the same company or group. The general corporate income-tax rate in Australia is 30% and deductions are allowed for PRRT and royalty payments, business expenses, and exploration costs incurred for mining (including coal) and oil and gas extraction. Some expenses related to mine rehabilitation and the decommissioning of offshore platforms are also deductible for income-tax purposes. Because the tax is not ring-fenced, losses from one project can be deducted against the profits of another. The immediate write-off of expenditures of a capital nature (including exploration and development expenditures) is normally considered under the tax systems of many countries to amount to a preferential tax treatment. The reason is that in calculating taxable profits in most income-tax systems, capital expenses are amortised over the period to which they contribute to earnings. Allowing these types of expenditure to be written-off in full in the year in which they are incurred therefore provides companies with a benefit akin to a zero-interest loan from the government since it delays the collection of taxes. A present-value calculation would thus show a positive transfer from the government to the companies benefitting from such provisions. However, when combined with a provision preventing companies from deducting interest costs and other financing charges, the immediate write-off of expenditures of a capital nature may not be considered preferential tax treatment. This is because this particular combination of tax provisions may approximate what is known as "cash-flow" taxation. Cash-flow tax systems can be theoretically equivalent to the more common imputed-income tax systems where the objective is to levy a neutral business tax. For that reason, measures such as the expensing of exploration and development costs may not be preferential tax provisions in the particular case of Australia’s PRRT. [4] In recent years, the Australian Government has enacted legislation that modified the country’s resource-taxation regime considerably. Changes include the extension of the PRRT regime to most onshore and offshore oil and natural-gas projects, and the introduction and subsequent repeal of the short-lived Mineral Resource Rent Tax (MRRT), which only applied from 2012 through 2013 and sought to tax the profits from the extraction of coal and iron ore at a 30% rate. Footnotes [1] Article2 of the WTO’s Agreement on Subsidies and Countervailing Measures (SCM) also stresses the importance of "specificity" in determining whether a particular measure falls under the scope of the agreement. [2] An estimated allocation based on gross-output shares or exploration expenditure by mineral is used here to provide readers with a sense of the magnitudes involved. Since these allocations are not from government sources and are based on general volume and value ratios, they might not always correlate well with actual distributions, if such information were available. These assumptions have been made by the OECD and should not be interpreted as reflecting the views of the responsible government. [3] Some offshore areas like the North West Shelf were, until recently, still subject to the previous royalty and crude-oil excise regime, or to production-sharing contracts. However, legislation enacted by the Australian Government now provides for the extension of the PRRT regime to all onshore and offshore oil and gas projects by 1July2012, with the exception of the Joint Petroleum Development Area in the Timor Sea which remains subject to production-sharing contracts with Timor-Leste under the Timor Sea Treaty. [4] See Box5 in OECD (2015).

AUSTRIA: GENERAL METADATA Data documentation General notes The fiscal year in Austria coincides with the calendar year. Amounts prior to 1999 are expressed as "euro-fixed series", meaning that this inventory applies the fixed EMU conversion rate (EUR 1 = ATS 13.7603) to data initially expressed in Austrian Schilling (ATS). In the case of the support measure AUT_te_04 ("Energy-Tax Refund to Energy-Intensive Industries"), the conversion into EUR was already made by the Federal Ministry of Finance. Annual estimates were found on the website of the Federal Ministry of Finance or provided directly by the Federal Ministry of Finance (for years prior to 2004).

BELGIUM: GENERAL METADATA Data documentation General notes The fiscal year in Belgium coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", meaning that this inventory applies the fixed EMU conversion rate (EUR 1 = BEF 40.339) to data initially expressed in the Belgian Franc (BEF). Producer Support Estimate Belgium supported the production of hard coal until 1992, at which time the last mine still in operation was closed. Since then, it has not supported the production of any fossil fuel.

BRAZIL: GENERAL METADATA Data documentation General notes Brazil is a federation comprising 27sub-national jurisdictions [1] that possess a certain degree of freedom in setting prices for energy generation, transmission, and distribution. For this reason, there may be variations between federal and regional authorities in the adoption and implementation of energy-related policies. A few regional spending programmes provide reductions in the ICMS tax for transactions involving diesel fuel used in public transport. A cursory review of these regional policies suggests that the overall value of sub-national support for fossil fuels is much less significant than that of federal support. Brazil’s fiscal year coincides with the calendar year. Methodological note A large part of support to fossil fuels in non-OECD economies takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, which lowers the revenues these companies collect through their sales of fuel. This sometimes results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. For this reason, some of the measures classified here under "Producer Support Estimate" may have been introduced by governments with a view to compensating domestic, vertically integrated oil and gas companies for the lower prices they are required to charge at the retail level, resulting in these measures being connected to some extent to consumer support. Producer Support Estimate Upstream operators of oil and natural-gas concession blocks in Brazil are subject to additional specific government levies - notably royalties, a signature bonus, a special participation tax, and an area-retention tax. Royalties take the form of a monthly tax applied on sales revenue at a rate of 10%, which can be reduced in exceptional cases to 5%. Special participation is a quarterly tax applied on sales revenue at a rate that varies from 10% to 40%, which is adjusted for certain high-volume or high-profit-margin fields. The signature bonus is an amount included by oil and gas producers in their concession bids, and which is payable to the ANP upon signature of the concession agreement. Lastly, the area-retention tax is an annual tax set by the ANP during the bidding round, the rate of which depends on the size and the geological characteristics of the field. Under this latter tax, upstream operators of concession blocks located onshore must pay the owners of the land where they operate an amount determined by the ANP, usually in the range of 0.5% to 1% of the value of production. Under concession agreements, upstream operators are also required to carry out domestic R&D investments equal to at least 1% of their gross revenues. Readers are advised that some fiscal measures related to oil and natural-gas production may not constitute tax expenditures under an alternative baseline where resource taxes (or production taxes) vary with market conditions and production costs. This inventory uses the annual amounts of tax expenditures as reported by the Federal Revenue Secretariat of Brazil. Footnotes [1] The Federative Republic ofBrazil currently consists of 26 states and one federal district.

CANADA: GENERAL METADATA Data documentation General notes The fiscal year in Canada runs from 1 April to 31 March. Following OECD convention, data are allocated to the starting calendar year so that data covering the period April 2005 to March 2006 are allocated to 2005. Canada being a federal country, the data also cover the following provinces and territories: Alberta (AB), British Columbia (BC), Manitoba (MB), New Brunswick (NB), Newfoundland and Labrador (NL), Nova Scotia (NS), Ontario (ON), Prince Edward Island (PE), Quebec (QC), Saskatchewan (SK), and Yukon Territory (YT). [1] The inventory includes a number of provincial tax expenditures within resource royalty systems. These are included because they are explicitly defined as quantified departures from the general royalty rules. As noted in Chapter 2 of OECD (2015), however, it is important that such measures, including their objectives and impacts, be considered (in a parallel way with income-tax and consumption-tax measures) within the context of the broader royalty system of which they form a part. Certain features of Canada’s tax system that indirectly support the production of fossil fuels - including coal and oil sands - apply to the mining sector as a whole. While the OECD definition of support to fossil fuels stresses specificity as a requisite [2], the present inventory considers those measures that apply to mining in general to be specific enough to warrant their inclusion in the database. In the absence of data on the actual sector distribution of the usage of these measures, as in other countries, the OECD has estimated based on relative output levels the share of the usage that relates to fossil-fuel extraction, as opposed to the share relating to the extraction of other minerals (e.g. uranium). This should not be interpreted, however, as reflecting the views of the responsible governments. [3] Notes relating to Producer Support Estimates in the Province of Quebec The province of Quebec does not currently produce fossil fuels on a significant scale, though some companies are actively exploring for oil in the Gaspe Peninsula and around the Anticosti Island. Exploration efforts are also concentrating on the province’s potential for shale gas, mostly in the south (e.g. Basses-Terres du Saint-Laurent). The refundable tax credit for resources (Crédit d’impôt remboursable relatif aux ressources) was introduced in March 2001 by the government of Quebec and provides eligible mining companies operating in the province with a refundable tax credit for up to 38.75% of qualifying exploration expenditure. [4] Qualifying exploration expenditure includes those expenses made with respect to oil and natural-gas, and which attract an additional 50% deduction for tax purposes. While this measure benefits some companies engaged in the exploration for fossil fuels in Quebec, exploration expenditure in the province remains heavily oriented towards non-energy minerals. This measure is therefore not deemed specific enough to warrant inclusion in the present inventory, which would not preclude its inclusion at a later stage should fossil-fuel exploration further increase in scale. Footnotes [1] The inventory does not include at this stage Nunavut and the Northwest Territories. [2] Article 2 of the WTO’s Agreement on Subsidies and Countervailing Measures (SCM) also stresses the importance of "specificity" in determining whether a particular measure falls under the scope of the agreement. [3] An estimated allocation based on gross-output shares is used here to provide readers with a sense of the magnitudes involved. Since these allocations are not from government sources and are based on general volume and value ratios, they might not always correlate well with actual distributions, if such information were available. These assumptions have been made by the OECD and should not be interpreted as reflecting the views of the responsible government. [4] The amount of credit that can be claimed depends on whether taxpayers are also engaged in the extraction of minerals or hydrocarbons, and on the region in which they operate (e.g. the Great North). This measure is not compatible with flow-through shares.

SWITZERLAND: GENERAL METADATA Data documentation General notes The fiscal year in Switzerland coincides with the calendar year.

CHILE: GENERAL METADATA Data documentation General notes The Chilean tax system relies on the use of the UTM (Unidad Tributaria Mensual). The UTM is a unit of account used exclusively for tax purposes. Its exchange rate vis-à-vis the Chilean peso is adjusted monthly on the basis of the consumer price index, thereby keeping its real value more or less constant.

CHINA: GENERAL METADATA Data documentation General notes China’s publically available budget data lack the specificity of many OECD countries. Where available, figures provided as part of the official budget cycle typically group expenses at the highest level for overall categories, while estimates of the revenue foregone due to tax expenditures are rarely provided. Official announcements, especially those related to overall programme budgets, are often made via reports issued by official news agencies of the People’s Central Government (Xinhua, CCTV) or the Chinese Communist Party (People’s Daily). Media sources (Caixin, Caijing and other financial websites) also occasionally reveal budget support levels or estimates of tax expenditures. The sources are typically the Central Government or relevant ministries, firms themselves, or top company officials. News sources will also occasionally compare these statements with other official documents they were able to obtain in order to arrive at broader estimates. These documents are often featured on official government websites of the Central People’s Government or the Ministry of Finance (MOF). Sources are clearly stated in this database, including whether the amounts have been initially provided or subsequently cited by government websites or by official media sources. The same caveats apply to amounts listed as "government grants" (in English-language reports) or either "government support" or "subsidies" (in Chinese-language reports), notably in the annual reports that state energy firms provide to major stock markets (Shanghai; Hong-Kong, China; and New York) as part of their disclosure requirements for listed subsidiaries. Sometimes these numbers specify the source and use of funds, but they are rarely as specific as would be preferred in order to fully allocate the amounts of stated subsidies to the measures listed below or other relevant programmes. Estimates for budgetary support and tax expenditures are allocated to the various support categories and programmes to the best extent possible given available information. In view of the limited availability of the data, assumptions are sometimes necessary to assess the allocation and, in some cases, the amount of support. Those assumptions are clearly stated where applicable. Methodological note A large part of support to fossil fuels in non-OECD countries (and in a few member countries such as Mexico) takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, thereby lowering the revenues these companies collect through sales of fuel. This often results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. For this reason, some of the measures classified here under "Producer Support Estimate" may have been introduced by governments with a view to compensating domestic, vertically integrated oil and gas companies for the lower prices they are required to charge at the retail level, resulting in these measures being connected to some extent to consumer support. Estimates of the support directly conferred to final consumers by regulated prices are available from the International Energy Agency (IEA), which estimates these induced transfers as part of its annual World Energy Outlook publication. Readers are therefore advised not to add together the OECD and IEA estimates given the significant risk of overlap and double-counting this involves.

COLOMBIA: GENERAL METADATA Data documentation General notes Colombia’s fiscal year matches the calendar year.

CZECH REPUBLIC: GENERAL METADATA Data documentation General notes The fiscal year in the Czech Republic coincides with the calendar year. Consumer support estimates were provided directly by the Ministry of Environment, the Ministry of Finance, and the Ministry of Industry and Trade. Measures pertaining to the restructuring of the country’s coal-mining industry and associated environmental liabilities are taken from a study included in the Mineral Commodity Summaries of the Czech Republic (Czech Geological Survey - Geofond, 2010) that was published by the Ministry of Industry and Trade: "Eliminating negative consequences of mining in the Czech Republic" - main methods and financial resources" (Kaštovský and Platzek, 2010). Notes relating to the General Services Support Estimate Since 1991, the Czech Republic has not supported the production or consumption of coal. The state retains, however, an obligation to deal with the social, health, and environmental liabilities associated with past mining activity. The government transferred these obligations to two state-owned enterprises, DIAMO, s.p. and Palivový kombinát Ústí, s.p., which acquired the assets of the closed mining companies. These state-owned enterprises receive government subsidies for the activities they carry out. Since measures financed through these subsidy payments do not act to increase current production or consumption of coal, they are all allocated to the GSSE. Restructuring the coal-mining industry and remediating the negative environmental consequences of mining are conducted in several different ways and using several different financial resources (Kaštovský and Platzek, 2010). Besides the measures reported in this inventory, mining companies have since 1994 been required to set up two reserve funds: a financial reserve for remediation and reclamation of all plots of land affected by mining, and a financial reserve for alleviating material damage caused by mining (e.g. land subsidence).

GERMANY: GENERAL METADATA Data documentation The fiscal year in Germany coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", in which the fixed EMU conversion rate (EUR 1 EUR = DEM 1.956) was applied to data initially expressed in the Deutsche Mark (DEM). In a few cases [1], the conversion into EUR was already made in official government documents. Germany being a federal country, the data also cover the states (Länder) that are still producing hard coal (North Rhine Westphalia, NW) and those that were producing hard coal until recently (Saarland, SR). Also included are payments for the rehabilitation of lignite-mining sites in eastern Germany (see DEU_dt_13) made by the Federal Government and the states of Saxony (SN), Brandenburg (BR), Saxony Anhalt (ST), and Thüringen (TH). Producer Support Estimate Hard-coal mining in Germany has traditionally attracted support for geological, historical, and political reasons. Since production of hard coal remains largely uneconomic, most mines are due to close by 2018 when government support to the industry is planned to be removed. Over the years, production of hard coal has been scaled back through numerous government initiatives. In the 1990s, the industry underwent various capacity-adjustment plans. Funding for these programmes was usually provided jointly by the coal-mining Land and the Federal Government, with the former accounting for about two-thirds of total payments. Hard-coal production has generally been supported through a combination of debt-relief schemes, mining-royalty concessions, reduced pension contributions for miners and provisions guaranteeing demand for the hard coal produced (see Combined Aids in North Rhine-Westphalia). In accordance with the EU’s state-aid rules, the Federal Government does not provide any more assistance to coal-mining under article 5-3 (current production aid). In preparation for the closure of mines, most of the support is now provided in the form of early-retirement funding for coal miners. Footnotes [1] This applies to the support measures for which the source is Landtag des Saarlandes (2005).

DENMARK: GENERAL METADATA Data documentation General notes Denmark’s fiscal year coincides with the calendar year. Producer Support Estimate Income derived from oil and natural-gas production is subject to various taxes and fees: the regular corporate income tax; the hydrocarbon tax (a specific tax on income derived from oil and gas production); royalties and compensatory payments; and profit sharing. Payments under the corporate tax are deductible from the hydrocarbon tax base. In addition, the oil pipeline tariff and compensatory fee can be offset against the hydrocarbon tax, but not against the corporate tax base. As of 2014, the corporate income tax amounts to 24.5%. However, in 2013 the Danish parliament passed two bills that will reduce the corporate income tax rate to 22% by 2016. Until January2014, the hydrocarbon tax regime differentiated between "old" licences granted before January2004 and "new" licences granted since 1 January 2004. For old licences, hydrocarbon income was subject to a 70% tax rate, but licensees were allowed to offset 25% of their capital expenditure (CAPEX) against their hydrocarbon tax bill over a period of ten years. For new licences, the hydrocarbon income tax was set at 52% and the allowance was granted for 5% of CAPEX over six years. From January2014 on, this differentiation is now abolished and old licences are treated under the same tax terms as new ones.

SPAIN: GENERAL METADATA Data documentation General notes The fiscal year in Spain coincides with the calendar year. Following OECD convention, amounts prior to 1999 appear as "euro-fixed series" where fixed EMU conversion rate (EUR 1EUR = ESP 166.386) were applied to data initially expressed in Spanish Peseta (ESP).

ESTONIA: GENERAL METADATA Data documentation General notes The fiscal year in Estonia coincides with the calendar year. Following OECD convention, amounts prior to 2011 are expressed as ‘euro-fixed series’, meaning that the fixed EMU conversion rate (EUR 1 = EEK 15.647) was applied to data initially expressed in the Estonian kroon (EEK).

FINLAND: GENERAL METADATA Data documentation General notes The fiscal year in Finland coincides with the calendar year. The Ministry of Finance reviewed the collected estimates and provided calculations of missing estimates where necessary.

FRANCE: GENERAL METADATA Data documentation General notes The fiscal year in France coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as ‘euro-fixed series’, meaning that this inventory applies the fixed EMU conversion rate (EUR1= FRF 6.559) to data initially expressed in the French Franc (FRF). Producer Support Estimate France used to support the production of hard coal through Charbonnages de France (CdF), a state-owned mining enterprise. Support was at the time deemed necessary owing to the low competitiveness of the French coal industry. By 1990, production had already ceased in the North of the country. An agreement between trade unions and CdF, the Pacte Charbonnier, was therefore concluded in October1994 to organise the progressive dismantling of the remaining production sites. The agreement provided for the end of all production by 2005. This was to be achieved through a series of measures meant to address the social costs associated with mine closures. One such measure, the congé charbonnier de fin de carrière, allowed coal miners to stop working at the age of 45 while remaining entitled to payments worth 80% of their previous wages. The last remaining mine was closed in 2004, ahead of schedule. CdF was liquidated in 2007 and its debt transferred to the French state, along with the responsibility for all inherited social and environmental liabilities. France does not produce coal any more.

UNITED KINGDOM: GENERAL METADATA Data documentation General notes The fiscal year in the United Kingdom runs from 1April to 31March. Following OECD convention, data are allocated to the starting calendar year so that data covering the period April 2016 to March 2017 are allocated to 2016. Producer Support Estimate Taxation of the oil and gas sector in the United Kingdom occurs through a variety of taxes. Notably, fields approved for development prior to 16March1993 were subject to the old Petroleum Revenue Tax (PRT) - a project-based tax levied on the profits from a given field - instituted in 1975. In the last several years the PRT rate was amended twice, being reduced from 50% to 35% in January 2015 and then being cut to nil in January 2016. . The PRT allowed for the full deduction of both operating and capital expenditures. It did not, however, allow the deduction of interest costs and other financing charges from taxable profits. Meanwhile, oil and gas corporations that have invested in approved fields after 16 March 1993 are also subject to a modified version of the regular corporation tax, namely the Ring-Fence Corporation Tax (RFCT). The imposition of a "ring fence" around upstream oil and gas activities means that these particular activities are to be treated separately for tax purposes from any other trade in which oil and gas companies may be engaged. This therefore allows upstream oil and gas activities to be taxed differently at the company-level. Differences in taxation include, for instance, the impossibility for companies to use losses in other activities as deductions against the income arising from oil and natural gas extraction. While all fields are subject to the RFCT, those that were approved for development prior to 16March1993 could deduct the amount of PRT taxes paid from their RFCT tax base. This ensured that the fields that were still subject to the old PRT regime were not taxed twice on the same profits. In addition, all types of fields are liable to the so-called Supplementary Charge (SC), which was introduced in the Finance Act of 2002. The SC is currently a 10% tax on profits from oil and natural gas production that is levied on top of the RFCT. The immediate write-off of both capital and exploration-and-development expenditures is normally considered under the systems in many countries to amount to a preferential tax treatment. The reason is that in calculating taxable profits in most income-tax systems, capital expenses are allocated over the period to which they contribute to earnings. Allowing the immediate writing-off of these types of expenditure therefore provides companies with something akin to a zero-interest loan from the government since it delays the collection of taxes. A present-value calculation would indeed show a positive transfer from the government to the companies benefiting from such provisions. However, when combined with impossibility for companies to deduct interest costs and other financing charges, the immediate write-off of both capital and exploration-and-development expenditures may not be considered a preferential tax treatment. Instead, this particular combination of tax provisions may approximate what is known as a "cash-flow" tax system. Cash-flow tax systems can be theoretically equivalent to the more common imputed-income tax systems where the objective is to levy a neutral business tax (Boadway and Bruce, 1984). For that reason, provisions such as the expensing of exploration and development costs may not be preferential tax provisions in the particular case of the United Kingdom.

GREECE: GENERAL METADATA Data documentation General notes The fiscal year in Greece coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", so that this inventory applies the fixed EMU conversion rate (1EUR = GRD 340.750) to data initially expressed in Greek drachma (GRD).

HUNGARY: GENERAL METADATA Data documentation General notes The fiscal year in Hungary coincides with the calendar year.

The fiscal year in Iceland coincides with the calendar year.

INDONESIA: GENERAL METADATA Data documentation General notes Until 2010, the Indonesian fiscal year ran from 1April till 31March of the following year. Following OECD conventions, for the years prior to 2011, data are allocated to the starting calendar year so that data covering the period April2005 to March2006 are allocated to 2005. After 2010, the Indonesian fiscal year coincides with the calendar year. Most of the data were obtained from publications by the Global Subsidies Initiative, the Indonesian Ministry of Finance, the Ministry of Energy and Mineral Resources (MEMR), and SKK Migas (the energy regulator). Methodological note A large part of support to fossil fuels in non-OECD countries (and in a few member countries such as Mexico) takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, thereby lowering the revenues these companies collect through sales of fuel. This often results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. For this reason, some of the measures classified here under "Producer Support Estimate" may have been introduced by governments with a view to compensating domestic, vertically integrated oil and gas companies for the lower prices they are required to charge at the retail level, resulting in these measures being connected to some extent to consumer support. Estimates of the support directly conferred to final consumers by regulated prices are available from the International Energy Agency (IEA), which estimates these induced transfers as part of its annual "World Energy Outlook" publication. Readers are therefore advised not to add together the OECD and IEA estimates given the significant risk of overlap and double-counting this involves. Producer Support Estimate Since 1966, International Oil Companies (IOCs) seeking to explore and develop oil or natural-gas resources in Indonesia have to enter into Production Sharing Contracts (PSCs) with the MEMR. The terms and conditions of the PSC system have varied with each "generation" of PSCs that has been issued since. The first generation applied from 1965 to 1975, the second generation from 1976 to 1987, and the third from 1988 until now. The main characteristics of the PSC system have, however, remained the same, namely that the government and IOCs share the production of the oil and natural gas rather than the resulting profits, and that the effective income for each side amounts to a share of the "First Tranche Petroleum" and an equity share of the profit oil after cost recovery. Since 2001, Pertamina is required to enter into a Work Agreement (WA) with SKK Migas (previously BP Migas, the energy regulator) for each of its operations, the terms and conditions for which are more or less the same than that for the PSCs. PSCs currently in force in Indonesia usually provide for the state to receive 70% of the produced natural gas, with contractors being allocated the remaining 30%. In the case of coal-bed methane (CBM), however, PSCs signed since 2007 have often featured a lower government share (45%). Historically, the applicable income tax for companies operating in the upstream oil and natural-gas sector has been the prevailing income tax at the time that the PSC got signed, i.e. 25% as of 2013. The income tax applicable to the downstream sector normally also follows the prevailing tax law. However, as other industries in "high priority economic sectors", a number of downstream businesses can benefit from a number of income-tax concessions subject to approval by the Ministry of Finance. These businesses include: oil and natural-gas refineries, LNG and LPG producers, lubricant manufacturers, and the organic chemical industry using oil and natural gas as inputs. The list of income-tax concessions eligible taxpayers can receive includes additional net-income deductions (up to 30% of the amount invested), accelerated depreciation, the extension to ten years of the period for carrying losses forward, and a cap on withholding tax. Footnotes: [1] Instead of a royalty, the Indonesian government charges a so-called "First Tranche Petroleum". This requires that the first 20% of production be shared in favour of the government and before cost recovery according to the equity split set in the contract (Johnston, 1994). In more recent PSCs, the government has taken the entire FTP, although in this case the FTP has usually been lowered to 10% of the first production.

ISRAEL: GENERAL METADATA Data documentation General notes Israel’s fiscal year coincides with the calendar year. Producer Support Estimate The oil and gas industry in Israel is regulated by a system of fees, royalty payments and tax deductions developed in the 1950s. The fiscal provisions that are unique to the oil and gas industry are the Oil Law (1952), Oil Regulations (1953), Income Tax Ordinance (1961) and some parts of the income tax legislation, especially the Deductions from the Income of Holders of Oil Rights (1956) and the Rules for Calculating Tax for the Holding and Sale of Participation Units in an Oil Exploration Partnership (1988). Israel started producing natural gas in 2004. As this is a relatively recent development, the issues of producer taxation and royalty payments are currently under review by the government (Knesset), the Ministry of Finance and participants representing the civil society. In April 2010, the Minister of Finance appointed a committee to examine the fiscal framework for the oil and gas resources in Israel, headed by Professor Eytan Sheshinski. The Sheshinski Committee submitted its final conclusions in January 2011. It recommended that the 12.5% rate of royalty payments should remain unchanged since increasing it could have a negative impact on the development of relatively less profitable gas fields. The depletion deduction, however, should be cancelled as it leads to a considerable reduction of the amount of taxable income which has no economic justification, the Committee concluded. The Committee also instituted a progressive oil and gas levy on profits. The initial rate of the levy is 20%, but it will not be collected before quotient of net cumulative revenues divided by the exploration and development expenses reaches or bypasses 1.5. When this quotient exceeds 2.3, the levy will gradually increase to 50%. Since production from the Tamar field began in 2013, it is projected that the government will only begin collecting revenue from the designated levy in 2018. In addition, as per income tax calculations, costs that accumulated during the lease stage of the oil-and-gas-asset development will be awarded accelerated depreciation at a rate of 10%. Investments made by the end of 2013 were given a maximum of amount of accelerated depreciation rate of 15%.

ITALY: GENERAL METADATA Data documentation General notes Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", meaning that we applied the fixed EMU conversion rate (EUR 1 = ITL 1936.27) to data initially expressed in the Italian Lira (ITL). The fiscal year in Italy runs from 1July to 30June. Following OECD convention, data are allocated to the starting calendar year so that, for example, data covering the period July 2005 to June 2006 are allocated to 2005.

JAPAN: GENERAL METADATA Data documentation General notes The Japanese fiscal year runs from 1April through 31March of the following year. Following OECD convention, fiscal-year data are assigned to the closest calendar year; hence data covering the period April 2009 through March 2010 are reported as "2009" in the database.

KOREA: GENERAL METADATA Data documentation General notes The fiscal year in Korea coincides with the calendar year.

Lithuania officially adopted the Euro with effect from 1 January 2015. Figures prior to this date were originally reported in Lithuanian Litas (LTL) and have been converted using the exchange rate EUR 1 = LTL 3.4528. The Ministry of Finance of Lithuania annually publishes official tax-expenditure data on their website.

LUXEMBOURG: GENERAL METADATA Data documentation General notes The fiscal year in Luxembourg coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", meaning that we apply the fixed EMU conversion rate (EUR 1 = LUF 40.339) to data initially expressed in the Luxembourg franc (LUF).

LATVIA GENERAL METADATA Data documentation General notes The fiscal year in Latvia coincides with the calendar year, except for excise tax relief mechanism of diesel used in agriculture transport where fiscal year is from July 1 till June 30. The Ministry of Finance of Latvia annually publish official tax-expenditure data on the website of the Ministry of Finance.

MEXICO: GENERAL METADATA Data documentation General notes The fiscal year in Mexico coincides with the calendar year. Producer Support Estimate Following the constitutional reform of the energy sector, the Mexican government signed a new fiscal regime for the oil and gas sector into law that will take effect on January 2015. The new regime is two-fold collecting a corporate income tax of 30% plus a set of taxes and fees varying depending on whether extraction and exploration is conducted as: (a) assignments (asignaciones) which are only granted to Pemex or a "state productive company" or (b) contracts signed with Pemex, either in association with private entities or with private entities entirely on their own. Under the assignment regime, state-owned companies pay three different types of federal fees: (i) a shared profit fee, (ii) a hydrocarbons extraction fee and (iii) a hydrocarbon exploration fee. The shared profit fee applies to the value of extracted hydrocarbons during the corresponding fiscal year (including consumption of these by the assignment holder, spillage and flaring) minus deductions. The fee will initially amount to 70% in FY2015 and will be lowered to 65% by FY2019. Next, the hydrocarbons extraction fee is determined in a similar way to the royalty payments charged under the contractual regime with fees varying on a sliding scale depending on the type of hydrocarbon extracted and the prevailing international price. Finally, the hydrocarbon exploration fee, also known as surface rental fee, will be charged on a monthly basis depending on the surface area being explored. The fee is aimed at incentivising companies to fulfil their exploration plans within a specified time frame. With respect to the contractual regime, there will be four different contract types: licence, production sharing, profit sharing and service contracts. Similar to taxes, fees and royalties will apply to different contract types, except in the case of service contracts where contracted companies do not receive any profits from the hydrocarbon extraction project: Licence contracts: contract signing bonus, royalties, exploration phase tax, and a compensation on the value of hydrocarbons Profit sharing and production sharing contracts: royalties, exploration phase tax and a compensation on net operation profit Royalty rates are determined on a sliding scale basis varying according to the type of field, its production level and the prevailing international price of oil and gas (similar to the hydrocarbon extraction fee under the assignment regime). Under this approach, royalties will go up if production or prices move above a certain threshold; the exact amount will only be published in the signed contract. Additionally, companies will also have to pay an exploration phase tax whose value is determined similar to the hydrocarbon exploration fee under the assignment regime. Profit sharing and product sharing contract will pay a compensation based on their net operational profits (the value of hydrocarbons extracted minus royalties and cost deductions) as defined in the signed contract. Licensors, on the other hand, will make payments based on the value of hydrocarbons they produce. In order to encourage oil and gas production, the new regime will provide a royalty discount for shale gas. Under this regime, coast deductions will usually be capped at USD 6.50 for each barrel of oil produced at 12.5% of oil revenues for onshore and shallow water assignments. Furthermore, a cap of 60% will be observed on oil revenues from deep water production and the Chicontepe field, currently operated by Pemex. There will also be a cost deduction cap of 80% for revenues in the production of gas. Compared with the previous fiscal regime, foreign firms were only allowed to operate under service contracts monopolized by Pemex and in addition pay a corporate income tax plus 10 additional taxes. Among the changes, the new system will be much simpler allowing profits to be shared with foreign oil and gas companies. Under this regime, the Mexican government estimates that Pemex can save 36% in tax and royalty payments annually, totalling to about MXP 90 billion. Furthermore, the government has proposed to assume one-third of Pemex’s social security contribution liabilities for its 15 000 employees, worth around USD 127 billion. However, before the government assumes this cost, the following conditions must be negotiated by Pemex with the Union of Petroleum workers: (i) raise the retirement age from 55 to 65 years; (ii) agree that the pension fund will be audited and; (iii) transfer the currently defined benefit plan to a defined contribution type on an individual basis.

NETHERLANDS: GENERAL METADATA Data documentation General notes The fiscal year in the Netherlands coincides with the calendar year. Tax-expenditure estimates for the years 2001-09 were provided by the Ministry of Finance. All other data estimates come from publicly available government sources as indicated below. Producer Support Estimate The taxes and fees that apply to exploration and production of oil and natural gas in the Netherlands are described in the 2003 Mining Act. Income from the production of hydrocarbons is subject to the standard statutory rate of corporate income tax (25%) and a State Profit Share (SPS) levy at a 50% rate, which is itself deductible for income-tax purposes. Royalties are also levied on the onshore extraction of oil and gas at rates that vary between 0% and 7% (or more when the price of imported crude oil exceeds EUR25 per barrel). Oil and gas companies operating upstream in the Netherlands have the ability to deduct an extra 10% of their costs from their taxable income, a provision known as the "cost uplift" or "capital uplift". Exploration expenditures, whether successful or not, can be written-off in full in the year in which they are incurred.

NORWAY: GENERAL METADATA Data documentation General notes The fiscal year in Norway coincides with the calendar year. Tax expenditures in Norway have been reported in the national budget (St. meld. nr.1 (Nasjonalbudsjettet)) since 1999. Since FY2010-2011, estimates of the tax expenditures listed below can be found in the following table in the budgetary reports: "Tax expenditures and sanctions[1] by sector" (Skatteutgifter og -sanksjoner for næringslivet). Producer Support Estimate The taxation of upstream activities on the Norwegian Continental Shelf is directed by the Petroleum Tax Act of 1975; where there are no specific rules given in the PTA, the General Tax Act (GTA) applies. For taxation purposes, income is calculated on the basis of a norm price set by the petroleum price board, giving rise to a difference in revenue figures for taxation and accounting purposes, Income derived from oil and gas production is subject to a special resource tax of 53%, in addition to the ordinary corporate income tax of 25% (in total a marginal tax rate of 78%). A range of expenses are allowable against both the special resource tax and the ordinary corporate income tax; most notably exploration costs are deductible, and a company may claim an annual refund of the tax value of direct and indirect exploration expenses (excluding financial expenses) for each tax year loss. Alternatively, these losses can be carried forward. In practice, this means reimbursement by the government of up to the full value of all the direct and indirect exploration expenses. In this respect, the government shares symmetrically in both profits and losses from exploration and production of petroleum products. Where taxable income is subject to a marginal rate of 78%, investments in offshore production facilities, pipelines and installations are depreciated over 6 years at a rate of 16.66% per annum. Additional allowances are permitted at a rate of 22% (5.5% each year over a four year period) when calculating the special tax basis for the 53% tax rate, such that 89.66% of offshore investments are nominally borne by the government.[2] Other capital investments are depreciated on a declining balance basis at rates between 0 and 30% per annum; for example, exploration rigs are depreciated on a declining balance basis at a maximum rate of 14% per annum. In addition to the regular corporate income tax and special resource tax, petroleum producers must also pay taxes on emissions of carbon dioxide and nitrogen oxide. As of 1 Jan 2016, the CO2 tax is charged at a rate of NOK 1.02 per standard cubic meter on gas consumed or flared on offshore production installations and at a rate of NOK 0.84 per m3 for natural gas and NOK 1.26 per litre for LPG imported from offshore production facilities or withdrawal from a warehouse. The tax on NOx emissions was NOK 21.17 per kilogram in 2016; however rather than pay this fee companies can choose to pay a fee into a fund (tax deductible at a rate of 78%) and commit to emissions reductions targets. Footnotes: [1] Tax expenditures (tax sanctions) are defined as exceptions from the general rules in the tax system that are applied to certain groups or certain activities and imply lower (higher) government tax revenue. Norway uses revenue forgone method for calculating tax expenditures. There are different benchmarks for calculating tax expenditures related to excise duties and environmental taxes. Excise duties are treated individually which means that each excise tax expenditure calculation relies on a different benchmark. [2] Expenditure incurred prior to May 2013 are subject to an annual uplift of 7.5% (30% in total over four years)

NEW ZEALAND: GENERAL METADATA Data documentation General notes The fiscal year in New Zealand runs from 1July to 30June. Following OECD convention, data are allocated to the starting calendar year so that data covering the period July 2005 to June 2006 are allocated to 2005. Producer Support Estimate New Zealand’s fiscal regime applicable to the oil and natural-gas industry combines a corporate income tax and royalty-based taxation. The corporate income tax amounts to 28% of taxable income, where taxable income is defined as any assessable income less deductions and net losses, the latter of which can be carried forward indefinitely. Generally, companies cannot deduct expenditures of a capital nature when incurred. However, deductions for certain exploration and development expenditures of a capital nature are available for oil and natural-gas companies (see Tax Deductions for Petroleum-Mining Expenditures). Depending on the year of the discovery, different royalty regimes apply. For discoveries made on or after 1995, royalties are set out in detail in the 2005 Minerals Programme for Petroleum and comprise of the following: an ad valorem royalty (AVR) component of 5% payable on the basis of either a sales price received or, where there has been no sale or no arm’s length sale, the deemed sales price; and an accounting profits royalty (APR) component of 20% payable on the difference between revenue received from the sale of products and the costs of extracting, processing and selling those products up to the point of sale. In case of an exploration permit, the permit holder is liable to pay only the AVR. For all mining permits with net sales above NZD1 million, the permit holder is required to calculate for each period for which a royalty return must be provided to both the AVR and the APR, and pay whichever is higher. Typically, AVR is paid in the early years of production as prior costs are netted against revenue and at the end of the field’s life, as production falls. APR is typically paid during the peak years of production of non-marginal fields. In order to encourage exploration for new natural-gas reserves, the government reduced royalty rates from June 2004 through 31December 2009 (see Reduction in Royalty Payments for Petroleum). For discoveries after 31 December 2009, the same royalty rates that are in operation before 30 June 2004 are applicable. More generally, royalties are payable for petroleum that is (1) discovered and sold, (2) used in the production process as fuel, (3) exchanged or transferred out of permit boundaries without sale or (3) left unsold at the expiry of the permit (Ernst and Young, 2013). No royalties are payable on petroleum that is flared or returned to natural reservoirs within the permit boundaries (e.g. the re-injection of gas). In 2008, the government introduced an emissions trading scheme (ETS) for greenhouse gases. Legislation for the scheme has been subsequently amended with the latest enacted in 2012. There are no special exceptions for the oil and gas sector under the current ETS regime.

POLAND: GENERAL METADATA Data documentation General notes The fiscal year in Poland normally coincides with the calendar year. Corporations, however, may choose a different starting point of the fiscal year. Producer Support Estimate Most of Polish state aid to the energy sector is apportioned to the coal industry. Poland’s heavy reliance on coal stems from both a large domestic endowment of this fuel and the fact that it used to have a limited access to foreign-exchange earnings with which it could have imported other fuels during the communist period. Because coal-mining was considered a strategic sector, the state subsidised the production of coal, providing various social benefits to coal miners and regulating coal prices to keep them low. With the economic transition of the early 1990s, the state envisioned to transform coal mines into self-reliant commercial companies that would adapt to the conditions of a free-market economy. The continued policy of price controls, however, meant that the industry had a very limited potential for economic growth and hence, needed further state assistance. All subsequent plans for restructuring the coal sector throughout the 1990s supported capacity adjustment, shutting down unprofitable mines and reducing employment to levels that would improve productivity. The overarching objective of those programmes was thus to make the coal-mining sector profitable. These programmes proved ineffective due to the lack of consensus between the government and the trade unions. This changed in 1998 as the new government, supported by Solidarno?? (the biggest Polish trade union), devised a coal-mining restructuring plan, the Reforma górnictwa w?gla kamiennego w Polsce w latach 1998 - 2002. The plan provided additional funding for social schemes and expressed a commitment to write-off the debt which the mines have accumulated over the years. Another plan adopted in 2003 - the Program restrukturyzacji górnictwa w?gla kamiennego w Polsce w latach 2003-2006 - pursued similar objectives. When Poland joined the European Union in 2004, state aid became subject to the Community rules. In practice, this development meant that coal-mining restructuring plans would have to be compatible with the common market, and that the European Commission would need to approve any state-aid scheme before it reached recipients. The Council of Ministers has so far adopted two documents regarding the restructuring of the sector: the Restrukturyzacja górnictwa w?gla kamiennego w latach 2004-2006 oraz strategia na lata 2007-2010, which was then replaced by Strategia dzia?alno?ci górnictwa w?gla kamiennego w Polsce w latach 2007-2015. Poland does not provide subsidies to coal-mining under article 5-3 (current production aid). All current subsidies therefore result from article 7 (aid to cover exceptional costs) and are associated either with mine decommissioning or investment aid to operating mines (for up to 30% of the total investments made). The former measures are mainly allocated to the GSSE as most of them do not increase current production or consumption of coal. The latter are allocated to the PSE since they directly support coal producers. The coal-mining sector underwent major restructuring through a series of management mergers and mine closures. At the beginning of the transition, the industry comprised of 71 independent mines. In 1993, the management of hard-coal production was taken over by seven joint-stock holding companies that held the assets of 60 mines. Four mines remained stand-alone enterprises, while the rest was shut down on unprofitability grounds. The Polish coal-mining sector now comprises 31 mines grouped into seven joint-stock holding companies and is dominated by three state-owned firms: Europe’s largest hard-coal company, Kompania W?glowa S.A. (KW), Katowicki Holding W?glowy S.A. (KHW) and Jastrz?bska Spó?ka W?glowa S.A. In 2000, two state-owned liquidation companies, Spó?ka Restrukturyzacji Kopal? S.A. (SRK) and Bytomska Spó?ka Restrukturyzacji Kopal? Sp. z o.o. (BSRK), were given responsibility to manage mine decommissioning. Since 2006, only two companies in Poland have been benefitting from state aid: KW and KHW. Aid is also being envisaged for the SRK (BSRK was consolidated into SRK in 2009).

PORTUGAL: GENERAL METADATA Data documentation General notes Portugal’s fiscal year coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series," meaning that the fixed EMU conversion rate (EUR 1 = PRT 200.482) is applied to data initially expressed in Portuguese Escudos (PRT).

RUSSIAN FEDERATION: GENERAL METADATA Data documentation General notes Although Russia is a federation comprising 83sub-national jurisdictions [1], a cursory review of regional policies suggests that the overall value of sub-national support for fossil fuels is much less significant than that of federal support. This is partly because Russia possesses a highly centralised budgetary and fiscal system, which acts to limit the amounts of support that can be provided by the country’s provinces, republics, districts, and territories. While there exists a few regional spending programmes that provide targeted support to the local oil and natural-gas industry (e.g., support for exploration and research activities or expenditure in relation to environmental liabilities), beneficiaries tend to be small- or medium-sized companies receiving small amounts of support. Regional government ownership of upstream oil and gas enterprises is very limited. More common is the ownership of electric-power utilities by these governments. However, even though this ownership results in considerable decision-making power over the purchase of natural gas as fuel for electricity generation, transactions are generally market-driven while natural-gas prices remain regulated at the federal level (see the country overview). The measures listed in this inventory are therefore predominantly federal in nature despite the fact that Russia is formed of a large number of sub-national jurisdictions. The fiscal year in Russia coincides with the calendar year. Methodological note A large part of support to fossil fuels in non-OECD countries takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, which lowers the revenues these companies collect through their sales of fuel. This sometimes results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. For this reason, some of the measures classified here under "Producer Support Estimate" may have been introduced by governments with a view to compensating domestic, vertically integrated oil and gas companies for the lower prices they are required to charge at the retail level, resulting in these measures being connected to some extent to consumer support. Estimates of the support directly conferred to final consumers by regulated prices are available from the International Energy Agency (IEA), which estimates these induced transfers as part of its annual World Energy Outlook publication. Readers are therefore advised not to add together the OECD and IEA estimates given the significant risk of overlap and double-counting this involves. Producer Support Estimate Readers are advised that some fiscal measures related to oil and natural-gas production may not constitute tax expenditures under an alternative baseline where resource taxes (or production taxes) vary with market conditions and production costs. This inventory uses the annual amounts of tax expenditures as reported by the Ministry of Finance of the Russian Federation or other government agencies. Footnotes: [1] The Russian federation currently consists of 46 oblasts (provinces), 21 republics, 9 krais (territories), 4 autonomous okrugs (districts), 2 federal cities (Moscow and Saint Petersburg), and one autonomous oblast, for a total of 83 sub-national jurisdictions.

The fiscal year in the Slovak Republic coincides with the calendar year. Data prior to 2009 were converted to "euro-fixed series" by the Ministry of Finance (unless otherwise specified).

SLOVENIA: GENERAL METADATA Data documentation General notes The fiscal year in Slovenia coincides with the calendar year. The conversion into EUR for the estimates in the period prior to 2007 was made by the Ministry of Finance, which kindly provided all estimates and fuel allocations.

SWEDEN: GENERAL METADATA Data documentation General notes The fiscal year in Sweden coincides with the calendar year. Producer Support Estimate No producer support estimates were identified.

TURKEY: GENERAL METADATA Data documentation General notes The fiscal year in Turkey coincides with the calendar year.

UNITED STATES: GENERAL METADATA Data documentation General notes The fiscal year in the United States runs from 1October to 30September. Following OECD convention, data are allocated to the ending calendar year so that data covering the period October2005 to September2006 are allocated to 2006. States can, however, have a different fiscal year. Since the United States is a federal country, data collection was also conducted for a sample comprising the following states: Alaska (AK), California (CA), Colorado (CO), Kentucky (KY), Louisiana (LA), North Dakota (ND), Oklahoma (OK), Pennsylvania (PA), Texas (TX), West Virginia (WV), and Wyoming (WY).

SOUTH AFRICA: GENERAL METADATA Data documentation General notes The fiscal year in South Africa runs from 1April to 31March of the following year. Following OECD conventions, data are allocated to the starting calendar year so that data covering the period April2005 to March2006 are allocated to 2005. The initial data were obtained from the National Treasury and the National Budgets (not the Provincial Budgets). For several estimates, data are taken from annual reports of companies such as Eskom, from other government organisations such as the South Africa Revenue Service SARS), and from other organisations working in the field. Methodological note A large part of support to fossil fuels in non-OECD countries (and in a few member countries such as Mexico) takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, thereby lowering the revenues these companies collect through sales of fuel. This often results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. Estimates of the support directly conferred to final consumers by regulated prices are available from the International Energy Agency (IEA), which estimates these induced transfers as part of its annual "World Energy Outlook" publication. Readers are therefore advised not to add together the OECD and IEA estimates given the significant risk of overlap and double-counting this involves. Producer Support Estimate The fiscal regime applicable to oil, natural-gas, and mining companies in South Africa consists mostly of a corporate income tax, indirect taxes, and royalties. Additionally, oil, natural-gas, and coal-mining companies pay the indirect taxes paid by other sectors, including the regular VAT and the customs duties and import tariffs that are levied on purchased inputs. Resident and non-resident companies are liable for corporation tax at a rate of 28 %. In addition, the government levies various withholding taxes including: on royalties paid to non-residents (at a rate of 15%), on interest payable to non-residents (at a rate of 15%), on dividends (at a rate of 15%), and on the disposal of immovable property (at a rate of 7.5% for a company). Finally, capital gains tax is payable at a rate of 18.65%, with an expected increase to 22.4% for the 2017 fiscal year. The tenth schedule to the Income Tax Act of 1962 sets out specific provisions relating to the taxation of upstream oil and gas exploration and production. These measures include deductions for all expenditures and losses related to exploration and post exploration losses, as well as 100% of capital spend on exploration activities and 50% on post-exploration activities. Furthermore, dividends paid out of income relating to oil and gas activities are not liable to the 15% withholding tax described above. Prior to 2010, South Africa’s oil, natural-gas, and mining companies did not have to pay royalties. The Mineral and Petroleum Resources Royalty Act (MPRRA) of 2008 imposed royalties related to extractive activities, with the rate calculated as a function of gross sales and profit (specifically, earnings before interest and tax), and varying between 0.5% and 5% (for refined resources) and between 0.5% and 7% for non-refined resources). Exemptions apply for certain small producers, but these are also applicable to operators extracting non-energy minerals. Given the size of South Africa’s total mining sector, royalty concessions such as these lack the specificity required to be characterised as support measures for the purpose of the present inventory.

INDIA: GENERAL METADATA Data documentation General notes India is a federation comprising 35sub-national jurisdictions that possess a certain degree of freedom in setting prices for energy generation, transmission, and distribution. For this reason, there may be variations between central and regional authorities in the adoption and implementation of energy-related policies. The fiscal year in India runs from 1April to 31March of the following year. Following OECD convention, data are allocated to the starting calendar year, so that data covering the period April2005 to March2006 are allocated to 2005. Methodological note A large part of support to fossil fuels in non-OECD countries (and in a few member countries such as Mexico) takes the form of price controls or regulations benefitting final consumers. In many cases, this occurs through the government mandating state-owned oil and gas companies to charge lower retail prices, thereby lowering the revenues these companies collect through sales of fuel. This often results in the government subsequently intervening to compensate state-owned oil and gas companies for the losses they incurred in the downstream sector due to the regulated prices, with this compensation taking many forms. Some governments choose, for example, to compensate national oil and gas companies through targeted tax concessions (e.g., VAT exemptions) or equity injections. This inventory focusses on the direct budgetary transfers and tax expenditures that encourage the production or consumption of fossil fuels, including those benefitting national oil and gas companies. For this reason, some of the measures classified here under "Producer Support Estimate" may have been introduced by governments with a view to compensating domestic, vertically integrated oil and gas companies for the lower prices they are required to charge at the retail level, resulting in these measures being connected to some extent to consumer support. Estimates of the support directly conferred to final consumers by regulated prices are available from the International Energy Agency (IEA), which estimates these induced transfers as part of its annual "World Energy Outlook" publication. Readers are therefore advised not to add together the OECD and IEA estimates given the significant risk of overlap and double-counting this involves. Producer Support Estimate Upstream operators of oil and natural-gas exploration blocks in India are subject to a hybrid tax regime under production sharing contracts (PSCs), which comprises fixed and ad valorem royalty payments, production sharing, and the recovery of contract costs (exploration, development, and production costs). In December2012, the Central Government announced plans to reform the current PSC fiscal regime. Readers are advised that some fiscal measures related to oil and natural-gas production may not constitute tax expenditures under an alternative baseline where resource taxes (or production taxes) vary with market conditions and production costs. This inventory uses the annual amounts of tax expenditures as reported in India’s Union Budget. Footnotes [1] The Republic of India currently consists of 28 states and seven Union Territories.

IRELAND: GENERAL METADATA Data documentation General notes The fiscal year in Ireland coincides with the calendar year. Following OECD convention, amounts prior to 1999 are expressed as "euro-fixed series", meaning that we applied the fixed EMU conversion rate (EUR 1 = IEP 0.788) to data initially expressed in the Irish Pound (IEP).