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Romania’s O&G framework

This brief zooms in on Romania’s upstream oil and gas framework. In an effort to better understand Romania’s context for hydrocarbon development, it seeks to provide a meaningful comparison with other hydrocarbon producing countries in Europe, such as Norway, Den-mark, or the Netherlands, and one of fastest developing energy producers in the post-communist space, Kazakhstan.

Romania’s framework for hydrocarbon development does not distinguish between onshore and offshore production, meaning that the same laws and fiscal provisions apply in both cases, regardless of the hydrocarbon field location. The National Agency for Mineral Resources (NAMR) is the key institution in managing Romania’s natural resources and has broad powers and responsibilities. As the main authority with responsibilities in administering the national resources, NAMR organizes tenders to award peri-meters for E&P or redevelopment activity. The same authority is responsible for issuing authorizations for both onshore and offshore projects. After the official results of a tender are announced, an agree-ment is concluded for the perimeter between the winning company and NAMR (which acts on behalf of the Romanian state and represents its interests in this process). In order for the agreement to enter into force, it has to be subsequently approved by the Romanian Government via a Governmental Decision (HG). Only after the agreement is thus ratified by the government, it is published in the Official Gazette and becomes valid. The agreements signed by O&G companies with NAMR are called “concession agreements”. In practice, however, the concession holder has to obtain additional licenses, permits, and authorizations to conduct operations at various stages of a project. Despite the fact that the Petroleum Law (Art. 54 (b)) stipulates that there is room for negotiation (NAMR “negotiates the clauses and terms of the petroleum agreements”), in reality no such thing takes place. The agreement is a standard frame-work which is filled in with data relevant for each perimeter, the schedule for mandatory and optional activities (for instance, number of wells to be drilled and over what period), and level of projected investments. Probably the best way to describe the system currently in place in Romania is to say that it is a hybrid – in essence a concessionary system (since the maximum duration of an agreement can reach 45 years) with some characteristics of a licensing system.

A few considerations about Romania’s upstream fiscal system: Romania does not require companies to pay bonuses (upon signature of a contract, upon commercial discovery, or upon start of production). The Romanian state does not grant any tax holiday for petroleum projects, but it does allow 100% cost recovery. Romania’s upstream petroleum regime is one based on royalties and taxes and consists of 2 main elements:

• Royalties (volume based, ranging from 3.5 to 13.5%, paid quarterly on a field-by-field basis);
• Corporate Income Tax (CIT) of 16%.

However, at the beginning of 2013 a tax on excess revenues realized as a result of natural gas price deregulation was introduced. This 60% tax applicable to natural gas only was introduced by Government Ordinance no. 7/2013, published in the Official Gazette (Part I, Issue 53, January 23, 2013). It entered into force on February 1, 2013 and will remain so until December 31, 2014. This tax (essentially a resource rent tax) applicable for the next 2 years is calculated according to the following formula: Excess revenue tax = 0.60 x (Excess revenue – royalty x Excess revenue – upstream investments ¹)

Its introduction was motivated by the need to capture part of the excess revenue that will result following the natural gas price liberalization, and to use these proceeds to protect the vulnerable consumer and “reduce the budget deficit”.

In addition to this new tax, another 0.5% special tax on revenues obtained from exploitation of natural resources other than natural gas was introduced by Government Ordinance no. 6/2013, published in the Official Gazette (Part I, Issue 52, January 22, 2013). The provision applies to the production of crude oil, superior quality coal, low quality coal, uranium, thorium and other extractive activities. The revenues obtained through this special tax are meant to be used for co-financing of ‘ongoing investment projects’, although no specific sector is mentioned.

Both taxes have a limited effect in time (2 years) and an impact on the O&G companies deemed ‘insignificant’ by the authorities. They seem to have been introduced provisionally, in anticipation of the larger and more substantial overhaul to the system of royalties and taxes expected to take place in 2014-2015. Prior to the introduction of these new taxes in February 2013, the overall government take from the Romanian upstream activities rarely exceeded 20-22%, since the royalty paid by most operators is usually around 6-7-8%.

It has to be added that oil and gas companies operating in Romania are also required to pay a series of tariffs to the NAMR which are administrative in nature. For instance, official tariffs are paid for access to the information on national petroleum reserves and data in the Petroleum Book (the value of the fee varies depending on the volume, quality of the information provided and whether it is old/new, etc); for authorizations issued by the agency at various stages of petroleum operations (permits for prospecting and exploration, approvals for association, transfer of a concession, and other such administrative documents). Generally, these are small amounts and do not weigh very much in the cost of doing business in Romania.

To provide some international context, I shall make some quick references to the petroleum frameworks of several other countries with tradition in hydrocarbon activity. The information below is taken from the 2012 Ernst & Young Global oil and gas tax guide:

• Norway, the richest country in Europe in terms of hydrocarbon reserves, has a fiscal petroleum system that uses an ordinary 28% CIT and a 50% resource rent tax, yielding a combined 78% tax rate. The Norwegian Petroleum Tax Act distinguishes between onshore and offshore tax regimes: no resource rent tax applies for the onshore production while a 50% resource rent tax applies for the offshore production, where the entire Norwegian oil and gas production is located.
• Denmark has no royalties (with a few exceptions), bonuses, or Production sharing regime (with one exception). The petroleum fiscal regime combines the standard CIT (25%) and a hydrocarbon tax that is levied ‘exclusively on extraordinarily profitable oilfield production’ thus acting as a de facto resource rent tax: a 70% hydrocarbon tax rate (under Chapter 3) or a 52% tax rate (under Chapter 3A). The former applies to licenses granted before January 1, 2004, the latter applies to licenses granted after this date. Thus the fiscal burden on E&P activities differs depending on whether the license is old (77.5% combined tax rate) or new (64% combined tax rate).
• Netherlands’s petroleum fiscal regime uses value based royalties (0 to 7% in 2011), a CIT (25%), a surface rental tax (€703/km² in a production area) and a State Profit Share (SPS) levy. The State Profit Share (50%) is levied on income from mineral production activities. As to the royalties, the E&Y guide adds that the royalty rates “increase by 25% in the event that the average price of an imported barrel of crude oil exceeds €25. A 100% increase applies in the event of an absence of state participation in the license.” (pp. 325).
• Kazakhstan has a complex petroleum fiscal system comprised of: a royalty equivalent (volume based 0.5-18% mineral extraction tax), a 20% CIT, signature and commercial discovery bonuses, an excess profit tax (progressive, up to 60%, calculated annually), and a rent tax on export (0 to 32%). This regime applies to all new contracts as of January 1, 2009, except for PSAs that became effective before this date and contracts approved by the president. Different MET rates apply depending on whether the hydrocarbon production is earmarked for export or sold domestically and where it is processed.
• Israel has a progressive windfall profit tax of up to 50% which is triggered only after full investment recovery (plus a yield).

Summing up, Norway has a 50% resource rent tax on offshore hydrocarbon production, Denmark, a 70% or, respectively, a 52% hydrocarbon tax triggered by extraordinarily profitable oil and gas fields, Netherlands, a special 50% State Profit Share (SPS) levy on mineral production activities while Kazakhstan has a progressive excess profit tax of up to 60%. All these taxes (sometimes with different names) have to be analyzed in the broader country petroleum context (presence or absence of royalties, bonuses, production sharing, other fiscal incentives, etc), but what it shows is that among countries that have chosen to impose a windfall profit tax for oil and gas activities we can find developed countries (Norway, Israel) alongside developing countries (Kazakhstan). Each country has its own approach, one that has to strike a balance between the need to remain an attractive investment destination and that of getting a “fair share” of the mineral resource rent, especially in a high oil price environment. It is clear from this comparison that Romania offers very attractive terms to companies active in its upstream sector, a status not likely to suffer a dramatic change following the latest fiscal amendments introduced earlier this year for the oil and gas sector.

FOOTNOTES:

¹ The upstream investments that can be deducted cannot exceed 30% of the excess revenue.