Examining Petroleum Fiscal Regimes
By Steve Parish

The only element of the upstream "Risk Cake" governments can really influence in the short term is fiscal risk, which can be done more or less at will. E&P (or prospectivity) risk can change, but only by virtue of exploration success, or lack thereof. Political risk, as seen purely from an E&P perspective, can change, but this happens usually over the medium to long term (five to 10 years), and is something that happens infrequently.

A country's fiscal risk is inextricably linked to the structure and stability of its fiscal regime, but what makes a petroleum fiscal regime attractive? Or to put it another way, what makes an attractive petroleum fiscal regime? The answer depends on your perspective. Investors looking to invest their exploration budgets will naturally be drawn to regimes that offer flexible but stable fiscal and contractual terms that have been designed to cope with the ups and downs of inputs such as product prices and costs. But they will also want to compare fiscal regimes to see which ones provide opportunities for leverage in negotiations with governments.

Host countries, on the other hand, are looking to extract maximum value from their natural resources. They will want a regime that provides them with the highest take whilst not totally discouraging potential investors. However, they will also want insight into the terms offered by competitors as well as neighbours.

So, whether you're investigating a new E&P opportunity or performing a routine screening analysis, you will want answers to fiscal-oriented questions such as:

• What type of contract is employed in a country?
• Are there mandatory payments such as bonuses and fees?
• Is there any state participation?
• Which taxes, including corporate taxes, are payable?
• How can I determine if one regime is more or less attractive than another?

Whichever side of the fence you sit, the IHS Petroleum Economics & Policy Solutions (PEPS) Country Fiscal modules provide an online source of unrivalled data and analysis on more than 200 generic petroleum fiscal regimes currently available for new E&P ventures.

Country Fiscal is part of PEPS, our modular information and analysis service providing data and analysis of above-ground risks in the upstream petroleum industry. PEPS is a one-stop shop providing high-level information that will quickly increase your knowledge of above-ground issues in a country's E&P sector.

Country Fiscal contains four modules: Overview, Analysis, Rankings and Interactive. In this article, we examine the Overview module, which provides thumbnail sketches of regimes' most important fiscal and contractual terms including bonuses and fees, royalty, state participation, production sharing (where applicable), income tax depreciation and rates, and other petroleum-specific taxes such as additional profits taxes, dividend withholding tax and domestic supply obligations.

The Overview module offers information that answers high-level questions in an objective, convenient and consistent manner. For example:

What type of fiscal regime is used in a country?
Broadly, there are two types of fiscal regimes that apply throughout the world: royalty/tax and production sharing. Just over half the regimes in our global analysis (54 percent) are of the production sharing agreement (PSA) type. Some countries such as Russia and Kazakhstan have moved away from production sharing and allow new investments only under royalty/tax terms. Other countries have moved in the opposite direction. For example, in Brazil, future licensing rounds are expected to be offered under production sharing terms.

Are there mandatory payments such as signature bonuses?
Signature bonuses are a requirement in 45 percent of the regimes in our analysis, a percentage that increases to 57 percent if one looks just at the PSA regimes. In places like Angola, signature bonuses can run to the hundreds of millions of dollars.

How common is state participation?
Direct state participation in upstream projects has an impact on the exploration decision because it reduces the investor's potential rewards whilst (normally) obliging the investor to retain the entire financial risk. Our analysis shows 43 percent of the regimes provide the state with the option to participate directly in upstream projects. Few of the regimes with direct state participation provide for the state to contribute its share of exploration and appraisal (E&A) costs at the time of expenditure (i.e., participate as a working interest partner from day one of a project). More often, state participation is in the form of a back-in to a commercial discovery, and often without reimbursement to the investor of the state's share of E&A costs. The level of state participation varies considerably and in 12 percent of the regimes, state participation in projects may be 40 percent or more (e.g., Algeria, Brunei, China and the Netherlands). When considering PSAs alone, state participation is an option in 50 percent of the regimes.

What about royalty?
Royalty is an off-the-top take from each unit of production and are very widespread, being found in 71 percent of the regimes. Whilst often used as a means of ensuring the host country receives cash flow from the start of projects, most royalties and bonuses are usually not based on profit and therefore have a regressive impact on the economics of a petroleum project.

Royalty is typically set in the range of 8 percent to 12.5 percent, but 16 percent of the regimes employ royalty mechanisms that can provide the host with 15 percent or more of the project's gross revenue. Some of these higher royalty rates are flat rate (e.g., 18 percent in Bolivia), but there are many examples where royalty is levied on a sliding scale with maximum rates reaching 20 percent (Abu Dhabi, Madagascar and Vietnam), 30 percent (Bulgaria and Venezuela) and even 50 percent (Alberta). More than half (58 percent) of PSAs include royalty, but this is a deduction from gross production, which has the effect of reducing the amount of production available for sharing between host and investor and therefore does not have a direct impact on the investor's cash flow (unlike royalty under the royalty/tax system).

How do corporate income tax rates compare?
Corporate income tax on petroleum projects is sometimes imposed at a rate that differs from the generally applicable corporate rate. In 21 percent of the regimes, the income tax rate is more than 40 percent (e.g. Cameroon, India, Trinidad and Tobago, and Tunisia). In a third of production sharing regimes, the profit shares are agreed on an after-tax basis and the investor's income tax liability is discharged by the state from its share of production. Surprisingly, in an industry perceived by some as having a licence to print money, there are places where foreign investment in the upstream is sweetened with the offer of income tax holidays. Such incentives occur in 7 percent of the regimes and vary widely ranging from one year in Vietnam to 15 years in Jamaica.

… and additional profits taxes?
Additional profits taxes are used in a number of regimes to specifically target upstream activities. In the United Kingdom, for example, where the standard rate of income tax is 28 percent, upstream operations are taxed at 30 percent. In 2002, a supplemental charge was introduced that applied to both existing and future developments and was initially set at 10 percent. However, within four years the rate had been increased to 20 percent. Such manipulation of fiscal regimes has the potential to make previously profitable projects marginal at best and uneconomic at worst. The United Kingdom regime is an example of a fiscally unstable regime. At the other end of the scale, Gabon provides that the terms agreed at the date of contract signature remain valid for the duration.

Over recent years oil and gas prices have risen to (and fallen from) unprecedented levels. From a recent low of $17/bbl in 1999, the price of WTI rose almost inexorably until July 2008 when it hit a high of $147/bbl, only to fall back to $30/bbl by the end of the same year. Today WTI is trading around $85/bbl. These astonishing price rises have delivered project profits that were never envisaged and which some host governments naturally regard as excessive. To counter this, some regimes have adopted mechanisms to capture the upside from high prices, but the approach to collecting this windfall is varied. In most cases this measure is enacted when profits, measured for example by rate of return, exceed predetermined levels (Kazakhstan), while in some, the simple breaching of an oil price threshold is sufficient for the windfall tax to cut in, such as in Algeria (1st-6th licensing rounds), Angola (onshore), China and Pakistan.

This brief tour of the Overview module demonstrates the breadth and depth of the IHS PEPS Country Fiscal service. For more information please contact us. 

 
Steve Parish is a Senior Petroleum Economist at IHS and is responsible for the content of PEPS Country Fiscal.