Everything you wanted to know about Tunisian oil and gas.
"Offshore prospects appear to be moderately promising, but more so for natural gas than for oil. The country has a broad continental shelf in the Gulfs of Gabes, Tunis and Hammamet. There is only a relatively narrow shelf to the north in the Mediterranean proper. It is in the broad shelf that several E&P companies have been interested.
The Pelagian Basin is a major petroleum province in Tunisia. It is proving to be more rich in natural gas than in oil. The basin straddles the coast and includes the Gulfs of Gabes and Hammamet, together with adjacent onshore areas. The hydrocarbon habitat is similar both onshore and offshore.
The E&P Regime: Called "Hydrocarbons Code", Tunisia's E&P law for oil and gas regroups all the fiscal and legal regulations for E&P and the downstream. It gives the operators a variety of incentives. These range from a flat income tax rate and negotiable prices for commercial gas and electricity to tax-deductible provisions for field abandonment and reinvestment in exploration.
Under the law, the tax rate has been reduced from 75 to 50%. The royalty is 10% for oil and 8% for gas. ETAP takes equity in every E&P venture. The law authorises ETAP to set gas purchase prices at levels acceptable to the E&P operators. Oil prices are set by mutual agreement between ETAP and the operators.
Gas prices are based on low sulphur fuel, now over $5/m CF. Previously the gas price used to be set at 85% of the value of high sulphur fuel oil in the west Mediterranean market. That deterred foreign operators from developing gas fields. This has been mainly in the case of BG, which refused to develop a huge field until the government improved the gas pricing system and the fiscal regime (see Part 2). BG was upset by the previous system because the price of high-sulphur fuel oil fell from an average of $113/ton in 1996 to just about $70/ton in 1998, and in early 1999 HSFO was trading at $50-55/ton.
The law grants the gas E&P company the option of having a concession for an IPP related to its gas production. STEG is authorised by the same law to negotiate the power purchase price with both ETAP and the operator. The same goes for Steg's purchase of natural gas from local operators. On the basis of the agreed price formula the operator can have an IPP in line with STEG's plans for the expansion of the power sector (see Downstream Trends).
Particularly interesting is that the very small and remote gas fields now can be developed for small IPPs. There are many such fields in Tunisia which have not been developed.
In addition, the new law gives ETAP greater flexibility in negotiating PSAs for oil and gas and for both new exploration blocks and known petroleum reserves. But E&P companies already operating in Tunisia and preferring to have their pre-2000 PSA terms unchanged have been allowed to maintain them.
The fiscal regime gives the operators tax deductions for the cost of abandoning a field whose reserves have been depleted. Under the previous system there were no such incentives. Another new incentive is that the law gives the operators tax relief when profits from oil and gas E&P are reinvested in Tunisia. This applies for reinvestment in both the upstream and downstream sectors, such as gas-fired IPPs. The tax relief is negotiable on a case by case basis as the law gives both ETAP and STEG flexibility on this.
The pre-2000 regime was based on a law No. 90-55 issued on June 12, 1990 which replaced all previous legislations regarding the petroleum sector. This remains in force for those operators who prefer it."
From an article at http://goliath.ecnext.com/coms2/gi_0199-5378814/TUNISIA-The-Geology.html
TTM - I'm still in but I'm down to about half the holding I had at Xmas. I have been switching over to BMN in the uranium sector, but I will maintain some holding in COE right through. I've been in COE since October 2006 so I'm not really a trader.
COE Price at posting:
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