July 2011

Global oil & gas tax newsletterViews from around the world

Spotlight on Brazil: Potential tax 2impacts of the PSA model

Other developments:

Australia introduces a carbon tax and 6updates PRRT proposal

Indonesia passes regulation on recoverable 6operating costs

Russia considers changes to MET regime 8

United Kingdom: Budget 2011 9

Talk to us 11

In this issue

2

From the first unsuccessful attempts of finding oil onshorein the 19th century to the recent discovery of the world’slargest pre-salt reservoirs offshore, the oil and gasindustry in Brazil has changed significantly and hasachieved a new level of maturity.

Since 1997, oil and gas activities have been carried outvia concession agreements under the Petroleum Law andregulated by a specific agency, the National PetroleumAgency (“ANP”). The concession agreement is based onthe royalty/tax model, in which the concessionaire (i.e., the oil company) is granted the right to explore forand produce oil and gas, in return for bearing all costsand risks, including taxes related to the operation. Underthe concession agreement, the concessionaire is theexclusive owner of the production, upon payment of the applicable royalties and a special participation fee tothe Brazilian Government (in addition to other applicablefees and payments made to the government).

The bidding rounds to grant the right to explore for andproduce oil and gas have been solely guided by theconcession model until the state-controlled company,Petróleo Brasileiro S.A. (“Petrobras”), discovered a large oil reservoir in the Tupi Field, located in a pre-salt (or sub-salt) area.1 As a result of this discovery, a newregulatory framework was introduced in 2010 to control

the pre-salt blocks and any other area deemed to bestrategic by the Brazilian Government. However, the newregulatory framework was not extended to the blocksthat were previously under a concession agreement. Thisnew regulatory framework, based on the use of aproduction sharing agreement (“PSA”), will coexist withthe existing regulatory framework of concessionagreements.

Under the envisaged PSA framework, the oil company will bear all costs and risks of oil and gas exploration,evaluation, development and production. If a commercialdiscovery is made, the oil company will be granted theright to recover costs and investments made with a share of the production, the right to the volume ofproduction corresponding to the royalties due, as well asthe right to a profitable return on investment through apre-determined percentage split.

Another relevant aspect of this new regulatory frameworkis the fact that Petrobras will be the operator of all pre-salt blocks via a minimum participation of 30% in aconsortium to be entered into with private companies.Additionally, Petrobras can be directly contracted with bythe Brazilian Government without previous bidding.

Spotlight on Brazil: Potential taximpacts of the PSA model

1 A pre-salt or sub-salt areaforms a range of rock thatstretches under an extensivelayer of salt, which in certainareas of the coast is up to2,000 meters thick. The term”sub” is used because theserocks were deposited beforethe salt layer. The totaldepth of these rocks, whichis the distance between thesurface of the sea and the oilreserves beneath the saltlayer, can reach more than7,000 meters.

Global oil & gas tax newsletter Views from around the world 3

Although this provision is viewed as an imposition by theBrazilian Government, most of the current consortiums ofthe oil and gas industry already have Petrobras as apartner, as illustrated in the chart below.

Under the PSA model, the consortium will have theparticipation of a Brazilian company for management ofoil and gas, Pre-Sal Petroleo S.A (“PPSA”), created in 2010by Law #12,304/10. This new government-ownedcompany will be responsible for the management of allproduction sharing contracts and Federal Government oiland gas commercialization contracts. Also in 2010, Law#12,351/10 created a social fund for regional and socialdevelopment in which revenues from pre-salt areas willbe invested in programs to combat poverty and addressclimate change, educational development, culture, publichealth, science and technology.

From a tax perspective, Brazil still lacks specific income taxlegislation for the upstream oil and gas industry, which isdifferent from what is seen in most of the Organizationfor Economic Cooperation and Development (“OECD”) oiland gas producing countries. For example, there is noring-fence for upstream activities. (Brazil instead taxes atan entity level.)

From a tax perspective, Brazil still lacks specific income taxlegislation for the upstream oil and gas industry …

Since tax regulations are general, there is still uncertainty regarding the appropriate mechanism for the depreciation and depletion of assets from a taxperspective, including oil and gas-specific assets. As a result, procedures for depreciation and depletioncurrently vary across many upstream oil and gascompanies in accordance with their tax attributes andinterpretation of Brazilian tax legislation.

The issue above already affects the upstream oil and gascompanies in the concession model and may also havesignificant impacts on the upcoming PSAs for the pre-saltareas. So far, the new regulatory framework regulationshave not clarified procedures for cost pooling in the PSAs,resulting in further uncertainty regarding how capitalexpenditures will have to be considered for purposes ofcost recovery and profit oil determination.2

Block Partnership Operators

41%

59%

Other co.Petrobras

Field Partnership Operators

64%

36%

Other co.Petrobras

2 The term “profit oil” cangenerally be defined as theamount of production, afterdeducting oil productionallocated to costs andexpenses, which will bedivided between the oilcompany and the BrazilianGovernment under the PSA.

4

In addition to the issues above, Brazil has a very complexindirect tax system which also significantly impacts capitaland operating expenditures (e.g., through levies such asICMS – state VAT-type tax, IPI – federal excise tax, PIS /COFINS – federal taxes on revenues, and ISS – municipaltax on services). For tax purposes, the recovery of indirecttax credits depends on the nature of the transactions of thecompany and its tax attributes. For example, this iscurrently an issue for exporters because ICMS andPIS/COFINS are not levied on exports. Thus, exportersusually accumulate credits which have very limitedpossibilities for utilization or offset. Also due to the lack ofspecific regulation, there are still uncertainties as towhether any indirect tax will apply in regards to the PSAstructure. In this context, the interaction between thePSA-specific regulations to be introduced for costdeterminations3 and the complex indirect taxation inBrazil will present important questions. For example,will regulations acknowledge that ICMS may be a costcomponent for exporters?

As outlined above, the details of the PSA regulations tobe implemented will be essential to determining theeconomic impact of this new regulatory framework andthe related tax implications. The answers to these taxquestions were not entirely debated by the BrazilianGovernment when it issued the respective legislation in2010 and thus leads to the necessity of clarifications todetermine the government take and taxpayers’ returnon investment.

… the interaction between the PSA-specific regulations to be introduced forcost determinations and the complex indirect taxation in Brazil will presentimportant questions.

3 In this context, “cost” cangenerally be defined as theportion of produced oil thatthe oil company applies onan annual basis to recoverdefined costs specified bythe PSA.

Global oil & gas tax newsletter Views from around the world 5

While answers to these highly complex questions are stillbeing debated, the challenge for multinationals operatingin Brazil will be to determine the financial and tax impactof operating under this regulatory framework whenbidding for participations in the pre-salt areas under thenew regulatory framework. On the other hand, from aneconomic perspective, both models (i.e., concession andPSA) are not decreasing the attractiveness of Brazilian oiland gas in practical terms.

Several major oil companies continue operating in theindustry, as Brazil, an economically and politically stablecountry in comparison to other troubled areas around theglobe, continues to demonstrate prolific discoveries.Therefore, even with some uncertainties and difficulties inthe regulatory and tax framework, the major discoveriesand current flow of investments in the Brazilian oil andgas industry indicate that there is a massive potential forexploration in areas of all kinds (onshore fields, offshoreshallow water, deep water and offshore pre-salt areas).

… the challenge for multinationals operating in Brazil will be to determine thefinancial and tax impact of operating under this regulatory framework …

6

Carbon TaxOn Sunday 10 July 2011, the Australian Governmentannounced the long awaited details of Australia’s carbonpricing mechanism.

From 1 July 2012, every tonne of carbon dioxideequivalent (“CO2-e”) produced by approximately 500 ofAustralia’s largest direct emitters will be priced at$23/tonne. The carbon price will be fixed for three yearsfrom 2012 to 2015 (indexed annually by 2.5%) until 1 July 2015, when a floating Emissions Trading Scheme(“ETS”) will commence. During the fixed-price period, thelarge emitters will be required to buy a fixed-price permitfrom the Government in exchange for every tonne ofCO2-e produced. Once the floating ETS commences, itwill be subject to a $15 floor price and a ceiling price of$20 above international carbon prices, with each risingannually 4% and 5%, respectively.

The sectors covered by the carbon pricing mechanism arestationary energy, industrial processes, fugitive processes(other than decommissioned coal mines), non-legacywaste and limited coverage of the transport sector.Agriculture and land-use emissions are excluded. The mechanism will cover four of the six greenhousegases under the Kyoto Protocol – carbon dioxide,methane, nitrous oxide and perfluorocarbons (“PFCs”)from aluminium smelting. Other synthetic greenhousegases are excluded.

The Government has also announced a raft of industryassistance mechanisms designed to assist key industrysectors deal with the impact of the carbon price, with thepossibility of further funding being made available tosupport research into low-pollution technologies.

Tax treatment of carbon permitsSpecific legislative provisions will be introduced to set outthe income tax treatment of permits. Broadly, theproceeds from selling a permit will be assessable in theincome year the permit is sold. A deduction will beallowed for any expenditure incurred on the purchase ofthe permit.

However, the deduction will be effectively deferredthrough a rolling balance method until such time as thepermit is surrendered or sold. Supplies of permits underthe carbon pricing mechanism will be Goods and ServicesTax (“GST”) free, but the normal GST rules will apply toany secondary market activity.

As the details are confirmed, organizations should ensurethey understand the timing and cash flow implications ofpermit payments. These permit payments are expected tobe administered in a similar manner to company taxpayments.

Timeline for actionWe expect to see draft legislation be released at the end ofJuly at which point many more details will become knownand it will be possible to form a greater understanding ofwhat this means to Australian businesses. The completepackage of legislation for the Carbon Tax is expected to bepassed before the end of calendar 2011. That does notleave a lot of time for consultation, so industry needs toimmediately start understanding and preparing for theintroduction of a carbon price.

PRRTFurther to our article in the last Global Oil & Gas TaxNewsletter, on 24 March 2011 the Australian Governmentconfirmed that it had accepted the recommendationsmade by the Policy Transition Group (“PTG”) in relation to the proposed extension of the Petroleum Resource RentTax (“PRRT”) to onshore oil and gas projects as well as tothe North West Shelf project. A Resource TaxImplementation Group has been established to assist theGovernment in developing the legislation to reflect therecommendations made. Deloitte has a representative onthe Implementation Group. Taxpayers affected by theproposed extension need to start considering in more detailhow the PRRT will affect them. In particular, they shouldparticipate in and/or monitor the consultation process toensure that the intention of the PTG recommendations isproperly reflected in the actual legislation and start theimplementation process to ensure they are ready toadminister the proposed rules by 1 July 2012.

Australia introduces a carbon taxand updates PRRT proposal

Taxpayers affected by the proposed extension need to start considering in moredetail how the PRRT will affect them ...

Global oil & gas tax newsletter Views from around the world 7

Regulation on recoverable operating costs andincome tax treatment in the upstream oil and gasindustry is finally passedThe long-awaited regulation for the upstream oil and gasindustry was finally enacted as Government Regulation No.79 of 2010 (“GR-79/2010”) was signed by the President on20 December 2010 and was effective immediately. The mainobjectives of this new regulation are to secure and optimizethe Government’s revenues sourced from Production SharingContracts (“PSC”) and to clarify certain income tax mattersby introducing, among others, the following provisions:

a. Deductible expenses shall be equal to the costs that canbe recoverable by the Contractors from the Government.

b. Guidelines on determination of the types of costs, costallocation methods, and limits on the recoverability ofoperating costs.

c. Indirect taxes, such as VAT, customs duty, Land andBuilding Tax, and regional taxes and levies, shallbecome shareable costs between the Government andthe Contractor by classifying these taxes as acomponent of the costs.

d. Taxation of income derived by Contractors fromoutside the Cooperation Contract scheme.

e. Prevention of the misuse of tax treaties.

Calculation of income taxThe following table summarizes the general methodologyfor calculating the taxable income of Contractors and theapplicable income tax. The important new feature underGR-79/2010 pertains to the tax treatment of incomederived from outside the Cooperation Contract scheme.

Transitional provisions The existing Cooperation Contracts signed before GR-79/2010 will remain valid until the expiration of the contracts. Contracts signed or extended after GR-79/2010 became effective will need to follow theprovisions of the regulation. Within three months, certain matters that are not yet regulated or insufficientlyregulated in Cooperation Contracts signed prior to GR-79/2010 should be brought into compliance with GR-79/2010.

Indonesia passes regulation onrecoverable operating costs

Income within the framework of PSCs

Income within the framework of Service Contracts

Income derived from outside theCooperation Contract scheme *

Taxable Income • Income derived from the operations less current year non-capital costs less current yeardepreciation of capital costs less prior years’ unrecovered operating costs.

• If the operating cost is higher than the income, the excess (i.e. unrecovered costs) can becarried forward to the following fiscal years.

• Uplift or other similar income, subject tofinal tax of 20% of the gross amount.

• Income from transfer of participatinginterests (“PI”) will be subject to final taxat the rate of:

a. 5% of the gross amount for the

transfer of PI during the explorationstage; or

b. 7% of the gross amount for thetransfer of PI during the exploitationstage.

• The following events are exempted fromthe imposition of tax on the transfer of PI:

a. Fulfilling the obligation to transfer PI to

national companies during theexploitation stage; or

b. Transfer of PI for risk sharing in theexploration stage.**

Applicable Tax Rate

• Corporate tax rate according to theIncome Tax Law (i.e., fixed corporate taxrate at the signing of the contract or theprevailing rate, depending on theContractors’ election).

• For contracts signed before GR-79/2010,based on the corporate tax rate prevailingat the signing of the contracts.

• Net profit after corporate tax is subject to income tax in accordancewith the Law (for an Indonesianincorporated Contractor, the net profitafter corporate tax will be considered as adividend provided to be paid***).

• Corporate tax rate according to theIncome Tax Law.

• Net profit after corporate tax is treated asa dividend provided to be paid*** and issubject to income tax.

Notes:* The procedures for withholding and payment of the income tax on uplift and transfer of participating interests will be regulated by the Minister of Finance Regulation.** Subject to the following criteria: a. not transferring the entire participating interest owned in the block; b. the participating interest has been held for at least three years; c. exploration has been performed in the work area (there has been investment expenditure); and d. the transfer of participating interest is not intended to generate profit.*** The term “dividend provided to be paid” generally refers to the remaining profit after tax that a company can pay as a dividend to its shareholders.

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Potential changes in Mineral Extraction Taxationregime for oil & gas in RussiaThe Russian State Duma (lower house of the RussianParliament) in April approved in the first reading the DraftLaw on two new initiatives for oil taxation in Russia: (1) decreasing the coefficient to the Mineral Extraction Tax(“MET”) rate on oil extraction from small deposits; and (2) application of a 0% MET rate on oil extracted ondeposits of the Yamalo-Nenetsky Autonomous District(“YNAD”), located to the north from 65 degrees ofnorthern latitude. The Draft Law is now being amendedin the Duma, waiting for the second reading out of three.

Decreasing the coefficient of the MET rate would encourageexploration within subsoil areas with insignificant initial oilreserves and accelerate exploration of additional volumes ofoil reserves. The new rules are also aimed at bringing acompetitive advantage for smaller oil-extracting companiesin front of the oil majors. The current procedure fordetermining MET for oil production provides differentiatedtaxation depending on the depletion of oil reserves.Exploration of small deposits with reserves of up to 5 milliontons is usually economically unprofitable due to the highequity requirements to cover capital expenditures andoperating costs.

The new MET rules for YNAD should create an economicenvironment for the development of local deposits, whereexploration under the general tax regime was unprofitabledue to the significant capital investments associated withthe creation of infrastructure for the geographical andgeological specifics of this northern region.

At the same time, Gazprom is discussing tax allowancesfor natural gas extraction. In particular, it has beenproposed to reset the MET rate to 0% on natural gasextraction in Eastern Siberia, providing a tax holiday for oil companies engaged in the development of oil fieldssituated in the Eastern Siberia region. Gas producers, andGazprom mainly, are performing several gas programs inEastern Siberia. For example, Gazprom acts as acoordinator of development and implementation of the gas programs in Eastern Siberia and the Far East,developing a unified system of production, transportationand supply with the possibility of exporting gas to Chinaand other countries in the Asia-Pacific region (Eastern GasProgram).

The tax status of the continental shelf in theRussian FederationSince 1 January 2011, amendments to the Russian TaxCode defined the territory of the Russian Federation andother territories under its jurisdiction. For tax purposes,this is understood to be the territory of the RussianFederation and also its territory of artificial islands,installations and constructions under its jurisdiction,according to the legislation of the Russian Federation and applicable international laws.

The current legislation specifies that Russia exercisesjurisdiction over its continental shelf and artificial islands,installations and constructions located on the continentalshelf of the Russian Federation. However, Russian taxlegislation does not define “artificial islands, installationsand constructions.” Moreover, Russian tax legislation doesnot clearly state whether the Russian continental shelfshould be treated as Russian territory for Russian profitstaxation purposes. This highlights the ambiguous taxtreatment of activities on the continental shelf, whereexploration and production for hydrocarbons is increasingrapidly. As a result, further amendments to the existingtax legislation are expected regarding the tax status of the Russian continental shelf.

Russia considers changes to MET regime

The Russian State Duma (lower house of the Russian Parliament) in April approved … two new initiatives for oiltaxation in Russia …

Global oil & gas tax newsletter Views from around the world 9

The Government has announced a major shift in the tax burden from the motorist to oil & gasexploration and production companies that cameas a shock to the industry.

Supplementary charge rateLegislation will be introduced in Finance Bill 2011,effective 24 March 2011, to increase the rate of thesupplementary charge (“SCT”) levied on UK oil and gasproduction from 20% to 32%. The change is being usedto raise taxes to pay for reduced fuel duty rates. SCT ispaid in addition to normal corporation tax so the effectiveNorth Sea marginal tax rate has therefore been raised to81% (from 75%) for fields subject to Petroleum RevenueTax (“PRT”) and 62% (from 50%) for non-PRT fields.

The Government has proposed that the SCT rate will bereduced back towards 20% “on a staged and sustainablebasis” in future years should the oil price fall below a settrigger price on a sustained basis. A future reductiontherefore appears to be an intention rather thansomething that will be included within legislation. Thiswill be linked to the introduction of a fair fuel stabilizerwhereby fuel duty will be increased by the retail pricesindex plus 1 pence per liter should the oil price fall belowthe same trigger price. The Government’s currentproposed trigger price is $75 per barrel, although a finallevel and mechanism will only be set after seeking theviews of oil and gas companies and motoring groups.

The increase in the SCT rate is expected to bring in about£2 billion per annum in additional tax revenues. In total,the SCT increase will bring £10.1 billion of additional taxrevenues over the period 2011-12 to 2015-16, whichcompares to the reduced tax take from the fuel dutymeasures of £9.4 billion over the same period.

No changes have been proposed to the Corporation Tax(“CT”) rates in respect of North Sea oil and gas ring fenceactivities. The mainstream CT rate for large companies is30% and the small companies’ rate for ring fence profits is19%. The PRT rate remains at 50%.

Accounting for the rate changeUnder IFRS, International Accounting Standard 12 ‘IncomeTaxes’ states that deferred tax assets and liabilities aremeasured at the tax rates that are expected to apply tothe period when the asset is realized or the liability issettled, based on tax rates (and tax laws) that have beenenacted or substantively enacted by the end of thereporting period. Similar rules exist within UK GAAP. Under US GAAP the relevant trigger is enactment.

The 32% rate of SCT was substantively enacted on BudgetDay (23 March 2011) under the Provisional Collection ofTaxes Act. The SCT rate change will form part of the 2011Finance Bill which will be enacted on Royal Assent(normally in the summer). Companies will therefore needto consider the impact on their deferred tax position inanticipation of these dates.

Relief for decommissioning costsIn order to prevent the increase in the SCT rate providingan incentive to decommission fields earlier than wouldotherwise be the case, Finance Bill 2012 will introducelegislation to restrict tax relief for decommissioningexpenditure to the previous 20% SCT rate. This will haveeffect from Budget 2012.

The Government has also announced that they will work withthe oil and gas industry with the aim of announcing further,longer-term certainty on decommissioning at Budget 2012and will consider with the industry the case for introducing anew category of field that would qualify for field allowance.

Ring Fence Expenditure Supplement (“RFES”)Following the above rate change and in response todiscussions with the industry, the UK Treasury has alsoannounced that they intend to increase the RFES from 6% to 10% with effect from 1 January 2012. The RFES addsan annual supplement to the value of unused expenditurecarried forward from one period to another, to maintain thetime value of exploration, appraisal and development costs.

Intangible fixed assetsLegislation, effective from 23 March 2011, will beintroduced in Finance Bill 2011 to clarify the application of the intangible fixed asset rules to oil licenses.

United Kingdom: Budget 2011

Companies will therefore need to consider theimpact on their deferred tax position inanticipation of these dates.

Legislation will be introduced in Finance Bill2011, effective 24 March 2011, to increase therate of the supplementary charge (“SCT”)levied on UK oil and gas production from20% to 32%.

The corporation tax regime introduced in Finance Act2002 (now Part 8 of Corporation Tax Act 2009) allowsintangible fixed assets, including goodwill, to be treatedfor tax purposes on an income basis, with relief availableas the intangible fixed asset is amortized or impaired, oron a fixed rate basis of 4% per annum. However, oillicenses and other rights over land were specificallyexcluded from that regime. Draft legislation has beenreleased to clarify that an oil license “includes all goodwill,and any intangible asset which relates to or derives fromor is connected with an oil license or an interest in oil”.

Other measures previously announcedDraft legislation was published in December 2010 to makeminor changes to the North Sea tax regime. The changeswill be included within Finance Bill 2011.

Field allowanceWith effect to fields whose development is authorized onor after 22 April 2009, the legislation will extend the scopeof the field allowance to certain types of fields that havepreviously been decommissioned but are being redeveloped.

In addition, where production income occurs in the sameaccounting period as that in which developmentauthorization is given, the field allowance can now beactivated in that period.

Chargeable gains – license swapsWith effect for disposals made on or after 23 March 2011, theoil license swaps legislation (which provides that no chargeablegains arise on the swap of UK oil and gas licenses in somecircumstances) will be amended to include provision forvarious payments to be made between the parties to betreated as adjustments to consideration. The legislationtherefore removes some of those receipts from the scope oftaxation on chargeable gains, and also ensures that whereexpenditure is effectively reimbursed the additional base costrests with the correct company for chargeable gains purposes.

Chargeable gains – reinvestment With effect to disposals made on or after 24 March 2010,a new ring fence reinvestment clause will treat expendituresincurred on exploration and development as theacquisition of assets that fulfill certain conditions for ringfence reinvestment purposes.

Decommissioned assetsWith effect for chargeable periods commencing after 30 June 2009, the PRT legislation is amended to correct adefect relating to the availability of relief for decommissioningcosts for PRT purposes after a license has expired.

Our viewThe shocking news that the SCT rate has been increasedup to 32% from 20% will be a very disappointing surpriseto the oil and gas industry. It now brings the North Seamarginal tax rate up to 81% (from 75%) for fields subjectto PRT and 62% (from 50%) for non-PRT fields. This comesat a time when the oil and gas industry is struggling withissues such as maintaining investment in North Seainfrastructure and access to it, as well as reduced explorationand appraisal (activity down 9% in 2010 from 2009).

The North Sea tax regime has suffered almost constantchange over the last 10 years and this ongoing instability islikely to be detrimental to investment. The UK ContinentalShelf needs to be attractive against other oil and gas regimes at an international level and this latest change willnot be helpful in this regard. The news that relief fordecommissioning costs has been restricted is also unlikelyto be welcome and is likely to raise further doubts as to whether the government will honor its futuredecommissioning obligations. The increased tax rates domean that the tax relief for capital expenditures, includingexploration and appraisal, is increased; whether it will increasedrilling activity remains to be seen. Combined, thesechanges effectively shift the tax burden from the motoristto the oil and gas exploration and production companies.

The measure on intangibles will potentially affect companiesthat have reflected goodwill on certain types of oil andgas acquisitions in their company financial statements andthey will need to consider the current and deferred taximpact on these.

10

Legislation, effective from 23 March 2011, willbe introduced in Finance Bill 2011 to clarifythe application of the intangible fixed assetrules to oil licenses.

Global oil & gas tax newsletter Views from around the world 11

For additional information regarding global oil and gas resources, please visit www.deloitte.com/oilandgas.If you have questions or comments regarding the content of the Global Oil & Gas Tax Newsletter, please contact one ofthe following global oil and gas tax leaders:

Julian SmallPartner and Global Oil & Gas Tax LeaderDeloitte UK (London) Tel: +44 (0) 20 7007 1853 Email: jsmall@deloitte.co.uk

Harold PaynePartnerDeloitte Australia (Perth)Tel: +61 8 9365 7000Email: hpayne@deloitte.com.au

Carlos VivasPartnerDeloitte Brazil (Rio de Janeiro)Tel: +55 3981 0500Email: cavivas@deloitte.com

Brian PyraPartner Deloitte Canada (Calgary)Tel: +40 3503 1408Email: bpyra@deloitte.ca

John BelseyPartnerDeloitte Middle East (Dubai)Tel: +971 4 439 5765Email: jbelsey@deloitte.com

Dirk Jan van KlinkPartnerDeloitte Netherlands (Rotterdam)Tel: +31 (10) 880 1140Email: DvanKlink@deloitte.nl

Andrey PaninPartnerDeloitte Russia (Moscow)Tel: +74957870600Email: apanin@deloitte.ru

Jeff WrightPartnerDeloitte US (Houston)Tel: +1 713 982 4940Email: jeffwright@deloitte.com

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