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Royalties and PSAs

The topic of royalties and Production Sharing Agreements (PSAs) is in essence a discussion about petroleum fiscal systems. Both have featured highly in the Romanian public space lately in view of the possibility, starting with 2014, to review the level of oil and gas royalties (currently frozen at 2004 levels). The article discusses some theoretical and historical aspects in trying to build a wider analytical framework in order to examine more in depth Romania’s case in a future article. In pursuit of this objective, the text looks into a few specificities of mineral resource taxation to illustrate the great variety of legal and fiscal regimes available worldwide for the development of oil and gas resources.

The present analysis is but a short incursion into the history and theory of petroleum fiscality and focuses on upstream taxation. I would start by saying that there is a huge body of literature on this topic, of which I recommend two exceptional publications: an IMF paper of 2001 authored by Thomas Baunsgaard and a 2008 Energy Charter Secretariat publication entitled “Taxation along the Oil and Gas Supply Chain”.

Worldwide, oil and gas projects can be developed under different business structures. Which one is chosen will have a huge impact on the revenue allocation and profit sharing scheme:

• concessionary regimes (con-cessions, licenses or exploration/ production permits);
• contractual regimes (PSAs or Service Agreements);
• tax regimes (royalties, income taxes, and resource rent taxes).

The first category is defined by the least government/National Oil Company (NOC) implication (the most “hands-off ” approach for the state). Leases were common in the early days of the oil industry in the United States (U.S.) while outside the U.S. the predominant legal form for oil development were the concessions. Under the very first oil concessions in history, International Oil Companies (IOCs) were granted ownership of the oil produced in exchange for various payments to the host country. Licenses and E&P permits developed later in countries like UK and Norway. To date, a fundamental difference remains between Anglo-Saxon countries and the rest of the world regarding ownership of the mineral resource. In common law countries (USA, UK, Australia) the sense of ownership over the resource is closely intertwined with the strong tradition of property rights. In the early days of the energy industry in the U.S., the landowner had mineral rights and the lessee paid him rent and royalties on the oil discovered. At the beginning of the XXth century, additional royalties were introduced on oil extraction, payable to the authorities of the country this time. Later on, during the 1910-1960s, the principle of sovereignty over mineral resources took hold in international law and was enshrined in the UN Resolution No. 1803 (XVII) (1962) “Permanent Sovereignty over Natural Resources”.

Since then, most of the countries have regarded the resources located below the ground as belonging to the state. With the emergence of this principle, even the common law countries have developed forms of legislation (lease or license agreements) that granted the state a bigger say in energy resources management and regulation while at the same time protecting the property rights. . Thus, in Anglo-Saxon countries, licenses can grant a proprietary right in nature, as opposed to PSAs which assert the state ownership over the resource and are reflective of the predominant view in the world today of sovereignty over subsoil riches.

Contractual regimes can take the form either of a PSA or of a Service Agreement. In the case of a PSA, the IOC takes upon itself the expenses and is rewarded in oil (payment in kind – PIK): the oil that covers the costs of project development is known as cost oil, what is in excess is referred to as profit oil. Under the Service Contracts, the companies receive a service fee. These systems have different taxation and accounting implications, therefore different consequences for company valuation.

Strictly from a historical perspective, royalties were the first and most encountered form of mineral taxation in the early days of the petroleum industry. Initially, the dominant investment framework for oil development outside the United States was the concession system (extremely unfavorable for the host countries by today’s standards). The 1950s saw the emergence of “hybrid fiscal regimes combining royalties with ordinary taxes” while the 1970s and 1980s were marked by increased experiments with equity participation, production sharing and service contracts (Baunsgaard). All these frameworks and their variations are still used today.

Petroleum fiscal systems

How to tax the oil and gas sector is a paramount question for countries endowed with hydrocarbons. The design of a country’s petroleum fiscal regime is always a matter of finding the optimum equilibrium between the desire of an energy rich country to capture a “fair share” of the rent and that to remain a competitive investment destination. Thus a state has a broad range of instruments at its disposal to devise its fiscal regime-instruments that fall in two large categories:

1. Fiscal (direct and indirect taxes, of which we will focus on the royalty);
2. Non fiscal (fixed fees, bonuses, production sharing, state equity).

Some countries levy windfall profit taxes in order to set them aside into a sovereign wealth fund (SWF) – an efficient way to counter the resource curse and plan effectively for the well being of the next generations. Recent events in global economy stressed the importance of having a balanced oil fiscal regime that can acts as a systemic safety net, and, at the same time, continue to provide attractive returns for potential foreign investors. In April 2012, then PM Razvan Ungureanu voiced the idea to create a Romanian SWF, while the newly appointed Minister of Economy, Daniel Chitoiu, stated in early May his intention to amend the mineral taxation regime, suggesting the inadequacy of the current royalty levels. But besides royalties (a fiscal instrument), there are also non-fiscal tools that can be used to increase the state revenue from oil and gas such as:

• Fixed fees and bonuses: these refer to the signature, discovery and production bonuses that companies undertaking E&P may be required to pay to the host government at various stages of project development (prior to project start, on discovery of resources, at various levels of productions). They exist to secure an early revenue stream for the host state, since it would usually have to wait until the investors recover their initial capital plus the required rate of return (RoR) until it can fully benefit from the rewards (initial capital investments are heavily frontloaded, and since investors have priority in sharing the gains, the government take will be mainly back-loaded, thus these bonuses are designed to sugarcoat the waiting time).
• Production sharing: is a long term agreement between a country (or NOC) and foreign investors. While the hydrocarbon molecules continue to belong to the state, IOCs are recompensed with a share of the production and are allowed to book them in their financial statements. There is a variety of production sharing arrangements around the world. Each of them is an individual agreement which creates a special framework for project development as it includes legal and fiscal provisions that apply only to that particular project/oil and gas field.
• State equity: while the reasons for a government to be an active shareholder of the JV that develops a project may be many, it is not always an easy thing to do, especially for a developing country. Cash calls can present significant difficulties, particularly for the government of a country with inadequate sovereign rating and struggling liquidity.
• Service contracts were very popular in Latin America in the 1970s and 1980s, but have regained in popularity recently in such places as the Middle East, in countries that are very sensitive to the question of foreign involvement in the petroleum industry. The most recent example is Iraq, where all the contracts awarded during the two bidding rounds (July and December 2009) were service contracts. The mixture of these various tax and non-tax tools can result in two types of fiscal regimes: Revenue based taxation and Profit based taxation.

The difference between the two is defined by what is actually being taxed (revenue or profit). A second major difference is the risk-reward distribution profiles between the state and the investor, associated with the two cases. For instance, under a revenue based tax system, the investor takes on a greater risk than the host government. That means that the government receives tax proceeds regardless of whether the project is profitable or not. The revenue based taxation disregards the long payback periods inherent to the development of oil and gas resources and the huge upfront costs involved. In this case the companies/consortium developing the project carry all the risk, and later either incur all the losses or enjoy all the rewards. In cases where the economics of the project proves to be more profitable than initially expected, the government exercises pressure on developers to renegotiate the terms with the aim to secure a “bigger piece of the pie” (rent). In a tax and royalty regime it can do so by changing the tax legislation, while in the case of a PSA – by seeking to renegotiate the terms of the agreement (many of which protect the project with the help of either specific percentages that apply to that project only or via ‘fiscal stability clauses’).

On the contrary, a profit based taxation system makes use of a “progressive regime”, one in which the government take goes up when the project profitability goes up. Such a situation can be prompted by higher oil prices or better than expected geological data (more output) that extends the life of the field and shortens the payback period. Profit based tax systems can make use of progressive profit tax or a stepped resource rent tax schedule (Baunsgaard). The problem however with a progressive tax regime is that, it can backfire in the case of projects that are less profitable, situation in which the government may never have the chance to apply a higher tax regime as the project does not reach profitability. This is one of the reasons why governments prefer to combine fiscal and non-fiscal instruments when they devise their petroleum fiscal regimes. It helps them hedge the uncertainties specific to oil and gas development and secure revenue streams commensurate with their appetite for risk.

Most industrialized nations have developed a profit based tax system (Australia, Norway, UK) and it seems that in most OECD nations, the petroleum sector is subject to a tax and royalty system. In contrast, PSAs have been widespread in Southeast Asia, Middle East, Africa, and FSU countries beginning with the 1990s. Historically, PSAs have appeared against the background of the increased resource nationalism of the 1960s, soon after the formation of OPEC. So, the preference for a tax & royalty regime or a PSA has a lot to do with how economically advanced is the country in question, the access it has to capital, its know-how, the particular features of its oil and gas fields (location, size, production costs, hydrocarbon quality, etc.), track record of energy resource development or lack thereof.

Royalties

The royalty is a resource tax which can be paid either in kind (as % of production) or in money (as % of revenue or as a fixed amount). It comes out of the revenue (P x Q) and is paid irrespective of profitability. Baunsgaard underscores that there can be three levels of upstream taxation: on revenue (I), on profit (II), and on rent (III). Royalties are the first level of taxation. Taxes such as the Corporate Income Tax are part of the second level, while some countries have an additional (third level) of upstream taxation in the form of a “resource rent tax” (a profit tax) which is imposed on high profitability projects. Essentially a tax on the petroleum rent, it is levied on the excess profit – the pure surplus realized from commercializing the resource, i.e. what is left after all the costs have been deducted, including taxes and the RoR on invested capital. The level of royalties can be stipulated by the laws governing the oil and gas sector or specified in the Production Sharing Agreement. In Romania, petroleum royalties start at 3.5% (minimum) and go up to 13.5% (maximum). Their variability depends on production volume and is paid quarterly on each commercial field individually. However, there is another factor that can be taken into account to set up royalties, namely the level of oil price on the global market. Under a progressive regime, the government take (total revenues from the cash flow of a field, including the royalty) can vary with the oil price. This implies indeed more volatility for the government revenue stream – more risk when the oil price is low, but also higher reward when the price is high. In the early 1990s, Kazakhstan granted extremely favorable conditions in order to attract investors and develop its energy industry. Part of the strategy to attract foreign investors included even exemption from payment of royalties until cost recovery was achieved. This was the case for the Kashagan PSA signed in 1997. In 2008 however, the government renegotiated the terms of the agreement to introduce a floating royalty structure under which the project consortium would pay the state 3.5% of output when world oil prices are above USD 45/barrel, 7.5-8% at USD 130/barrel, and 12.5% at USD 195/barrel, thus linking the royalty rate to the price of oil.

Brief history:

“The PSA is said to be a brainchild of Ibnu Sutowo [medical doctor and army general], the founder of the Indonesian state oil company “Pertamina”. He borrowed the concept from the sharing of harvest between tenant farmers and landowners, which was a common agricultural practice in Indonesia then. The first PSA was signed in 1961 between Pertamina and a Canadian company, Asamera Oil, for an onshore acreage in North Sumatra, although the one signed in 1967 with an American consortium company, IIAPCO, for a block off the coast of West Java was more prominent”.

Source: “Taxation along the oil and gas supply chain”, Energy Charter Secretariat, 2008

Production Sharing Agreements (PSAs)

The Production and Sharing Agreement (PSA) is a framework developed by the UN for Indonesia (the country where the first ever PSA was implemented in the 1960s) as a means of establishing the sovereign right over the use of subsoil resources.

There is no “standard PSA” just like there is no “one size fits all” policy for setting the royalties’ rates. The PSA is an agreement with the host country that creates a different regime that applies for the duration of the project. It constitutes the “core” part of the whole project formation process, especially if a project is developed through limited recourse finance. The agreement details key technical, commercial and economic terms related to the right to do business in that country and usually address things like sitting, licensing, environmental permitting, labor, operation of production, infrastructure (offered to the project and offered by the project). Many of the aspects that are addressed are related to the country’s macroeconomic structure (local financial system, monetary and fiscal policy) which affect the project performance in many ways: taxation of materials imported for the project facilities, repatriation of earnings, taxation of interest, policy on withholding dividends and interest. Stabilization clauses (commitment to fiscal and regulatory stability) are often embedded in these agreements as well as exact provisions for designated jurisdictions in case of arbitration. Similarly, a PSA may contain also a “domestic supply obligation clause” or it may include negotiated legal and fiscal exceptions to the rules governing hydrocarbon development in a country with the purpose of providing a separate framework over the lifetime of a sizeable project. It is somewhat ironic that, the PSAs which were initially developed to protect the sovereign rights of the resource rich country from the exploitation of the IOCs, ended up protecting the interests of the IOCs and are now considered one of the most advantageous business structures for the oil and gas majors. In his study Baunsgaard states that: “there is no intrinsic reason to prefer a tax/royalty regime to a production sharing regime or vice versa. The choice between the two will reflect administrative preferences or a particular structure that may be most suitable for local conditions”. Since the effects of a fiscal regime can be replicated with the tools specific to a PSA, this forces the conclusion that the preference for one or the other is a function of a country’s particular stage of development and its specific needs at a given moment in time. We intend to continue this discussion with a focus on Romania in a subsequent edition.

References:

1. Thomas Baunsgaard, “A Primer on Mineral Taxation”, International Monetary Fund Working Paper WP/01/139.
2. Energy Charter Secreta-riat,“Taxation along the oil and gas supply chain”, 2008.