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Turkey - The E&P Background.

All prospective onshore blocks in Turkey have been licenced. TPAO acts as an operator in its areas and partner of other companies elsewhere. Improved E&P terms in March 1983 encouraged a number of firms to explore in Turkey. A major oil find in 1989 lured more firms to Turkey. But the pace of finds was slow in later and many have since left the country.

A further improvement of E&P terms under a new law approved in 2013lured a number of IOCs back to Turkey. This caps the tax burden on profit at 55%. This offers investors theoretical protection against future tax increases, although the government may issue another law to raise the tax again if and when new prospective regions emerged such as the offshore Mediterranean and Black Sea areas.

Under the new law, royalties are calculated on market prices, rather than on the basis of well-head prices. The production sharing terms compare favourably with the EPSAs now on offer in neighbouring countries such as Azerbaijan. But IOCs insist that the new Turkish terms are still less attractive than those in Iraq's Kurdistan.

Oil in place, defined as "ultimately recoverable", may exceed 2bn barrels mostly in Raman West, Turkey's largest field. But this is 13.3? API with 5.7% sulphur and cannot be recovered because of a permeability barrier. Only a small part is recoverable under a current EOR system involving CO[sup.2] flooding.

Firms coming to Turkey included Roy M. Huffington of the US, which got 13 licences at the north-western end of the Taurus-Zagros belt and other blocks. Offshore and onshore exploration in Iskenderun Bay was done by TPAO and Salen Energy of Sweden, but the outcome was negative. US, Canadian and Norwegian firms led by Seahawk took the Saros Bay acreage. Barrick Petroleum of Canada joined TPAO in a Black Sea block as well as in the onshore Sinop and Samsun Basins. Lennox Oil of Scotland took the Salt Lake Basin in central Turkey. In March 2004 Omax Resources of Canada got 33.3% in the Adana oil and gas zone in return for 16.7% in the Iskenderun block. After the deal, Omax got 33.3% in both blocks.

The petroleum law allows the foreign or local private operator to export 35% of production in onshore fields and 45% of output in offshore fields. A "Certificate" allows local and foreign firms to establish downstream ventures. Certificates for periods of up to 30 years, renewable for another 10 years, have been issued for oil refining, transport and distribution, as well as gas marketing. The Minister of Energy and Natural Resources issues these certificates. Provisions for the repatriation of exploration expenses and profits have been improved. There are better E&P terms in technically difficult or geologically complex areas, such as the Black Sea. Each case is negotiated separately.

Improvements include a better definition of what is remittable under the law, and an easier process for the extension of licence and drilling periods in areas affected by political violence. The cost recovery rate is 50%, which is attractive compared to terms on offer in the Middle East.

Production sharing applicable between TPAO and operators is based on a sliding scale, which varies with the volume of production. Shell, for example, had a 50-50 split at the lowest end of the scale; beyond 10,000 b/d its share fell in favour of TPAO. At the highest level, the split was 30-70. Accordingly, the repatriation of registered capital could only be made from oil revenues generated from a new discovery. Small fields, or small producing JVs, are quite profitable, the main reason Perenco bought Shell's assets (see omt18TurkFieldsMay5-14). In other states such fields are considered marginal.

Incentives include: tax exemptions; a duty-free import allowance for materials not available in Turkey; depreciation on fixed assets; exemption from VAT, limited to purchase of goods and services for exploration; a depletion allowance, though restricted to capitalised exploration costs, intangible drilling costs, and costs of dry-holes; the possibility of creating and/or transferring rights in licences and leases, similar to those applied in real property; the right to export 35% of onshore, and 45% of offshore oil production from fields found after January 1980; and deduction of some exploration costs from annual licence rentals.

A surcharge of refiners, decreed in 1980, has funded a special facility to provide upstream operators with soft loans in the local currency, the Turkish lira. The facility has given E&P firms TL loans for up to five years at 10% annual interest, which until 2003 was quite low compared to high interest rates on TL loans. Loans to TPAO were for 20 years at 10%.

TPAO and other operators have been offered an FOB-East Mediterranean crude oil pricing marker, based on spot market quotations, to determine the value of what they produce. This is under a law decreed in June 1983. A December 1985 decree reduced the with-holding tax rate on non-domiciled foreign companies serving the oil exploration sector, from 25% to 5%.

The Petroleum Affairs Directorate at the Ministry of Energy is in charge of the upstream sector. In 1987 it circulated a model EPSA, under which TPAO was able to take a direct stake of 15%, and the government's interest could reach 50% through a 35% tax in the event of a commercial discovery. This has since been revised. In concession agreements, companies pay a royalty of 12.5%, and a tax on net corporate income.

The permit is a non-exclusive right allowing the holder to carry out exploration, including structural core-hole drilling for geological data. The period of the permit is specified by the Directorate. A permit may cover one or several districts or open portions of districts. The licence is an exclusive right allowing the holder to drill, develop and produce. The maximum area covered by a licence is 50,000 hectares. No company may hold, directly or indirectly, more than eight licences in any one of the 18 districts. TPAO is entitled to a maximum of 12 licences in each district.

The licence has a term of five years, to be extended for another five years in two increments. The term can be extended for a period sufficient for the licencee to delineate the field it has found. (Terms and limits may be extended by 50% in offshore areas). The licencee must begin exploration within one year from the date of the award. Drilling must begin no later than three years from the award.

After a commercial find, field definition and development, the licencee begins production, paying a low annual rent during the first three years, a higher rent during the next two years and a higher one there-after. Costs incurred by the licencee in any given year for exploration and drilling may be deducted from the amount of rents. A licencee is liable for a royalty of 12.5% of production. This cannot be credited against rentals. Rent may be cut 50% for offshore exploration.

The Lease: Having made a find, the licencee can get a lease covering an area not exceeding half the block. The lease gives the holder an exclusive right to explore, develop and produce. No holder other than TPAO may have more than 150,000 hectares in any district. The lease term is 20 years, renewable for another 20 in two 10-year increments. Unless petroleum is produced in commercial quantities within one year from the date, the lease is granted, with output to be maintained substantially without interruption. The lessee pays low annual rent per hectare for the first year and higher rents for the subsequent years. The 12.5% royalty is not deductible from rents paid.
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Publication:APS Review Gas Market Trends
Date:May 5, 2014
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