Go-ahead hopes for Namibia's Kudu gasfield
Exactly 40 years after it was discovered, the Kudu gasfield is moving towards a development decision
By the end of the year, agreements are targeted to be in place to allow work to start on the development of Namibia's Kudu gasfield - an achievement which has eluded companies large and small since its discovery in 1974. Plans call for gas from the field, lying 170 km off the southern part of the coast, to be landed to fuel a power-station to be constructed near Oranjemund, with the electricity to be sold in Namibia, Zambia and South Africa.
Namibia's state-owned Namcor hopes to sign, by December, an agreement to farm-out a large part of its 54% interest in Kudu to a new participant, while Tullow, the operator, will retain its 31% and Itochu will retain the other 15%. Gas sales agreements with KuduPower -the company, led by the state's NamPower, which will build the power-station - should be signed the same month, making way for a final investment decision.
On that schedule, construction work should begin early next year and gas should start to flow in early-2018. The field development will consist of a floating production facility, moored in 170 metres of water, with subsea wells tapping the 39 billion cubic metres (cm) of proven reserves. Tullow has estimated that the development will cost $1.3bn - excluding the floater, which will be leased - although the firm says the figure is subject to revision.
The power station will be an 800 megawatt (MW) combined-cycle gas-turbine unit - the largest in Africa - costing $1.2bn and supplying 400 MW to power-short Namibia, 300 MW to Zambia and 100 MW to South Africa. Interests in KuduPower will be NamPower with 51%, CEC Africa (a subsidiary of Zambia's Copperbelt Energy) with 30%, and another partner, still being sought, to hold the remaining 19%.
According to NamPower, quoting CEC Africa data, electricity from the Kudu development will be competitive with other new power stations in Namibia. KuduPower electricity will cost 12 US cents per kilowatt-hour (c/kWh) including transmission mark-up, it says - within the 11-13-plus c/kWh range for new coal-fired generating capacity in the country. Electricity tariffs in Namibia, and also Zambia and South Africa, are forecast to rise in coming years to reflect the need to build new capacity - NamPower forecasts that Namibia's electricity demand will rise by 33-60% by 2025, depending on growth assumptions.
However, after 40 years of unsuccessful attempts to develop Kudu, grounds for caution remain. Gasfield investors and financial backers like to see a developed local market for gas, but Namibia has no gas use and South Africa - because of its vast coal production - uses only a little. Lack of a local market points to the chosen gas-to-power scheme, but South Africa's low-cost coal remains a problem: coal has always been southern Africa's preferred generating fuel, and it is the price-setter for the region's electricity.
With proven reserves of 39bn cm, the Kudu reservoir is not large enough to support a liquefied natural gas (LNG) development. After the withdrawal of the original operator, Chevron, the Kudu licence was taken by Shell in 1993, and the company set out to prove-up sufficient reserves to support the first use of a floating-LNG facility. Shell wanted 140bn cm - but in 2002, after drilling an additional four wells, taking the total in the field to seven, it pulled out saying it had not found the required volume.
Although Kudu's 170 metres water-depth is not a problem, the reservoir is deep at 4,500 metres sub-seabed and wells will be costly. Also raising costs will be the small amount of condensate present in the gas - enough to require removal, but not enough to produce sufficient sales revenue to cover the cost of removing it. Wellheads will need anti-freeze injection to prevent hydrate formation, with the glycol supplied from shore through a small-diameter pipeline.
With fewer than 25 wells having been drilled in the Namibian offshore - a vast area, extending more than 1,500 km north-to-south by about 400 km wide - the country is only lightly explored. Much of the area is under licence, with smaller operators predominating - but larger firms have been farming-in recently, following de-risking work by the operators.
Earlier this year, Murphy and OMV farmed-in to two areas held by Brazil's Cowan, with Murphy taking over as operator and interests becoming Murphy, 40%, OMV, 25%, Cowan, 20% and Namcor, 15%. The areas, Blocks 2613A and B in the Luderitz basin, are covered by recent 2-D seismic acquired by Cowan, and 3-D is to be shot this year.
In a similar agreement, in February this year Shell moved back into Namibia by acquiring the 90% interest of Signet Petroleum in Blocks 2913A and 2914B, after Signet had carried out 2-D seismic work. Namcor holds the other 10% of the licence covering the blocks, which lie in the Orange basin.
But farming-in to de-risked blocks produced a disappointment for Repsol in June, when it drilled the first well in a licence it moved into in early-2013. The well, Welwitschia-1A in the Walvis basin, was dry at total depth - and its cost, raised by drilling and logging problems and the start of winter weather, is expected by the operator to be 10% over the $91m budget. Repsol has 44% of the licence, covering Blocks 1910A, 1911 and 2011A, with UK company Tower Resources holding 30% and Arcadia holding 26%.
Also disappointed is Brazil's HRT, which completed a three-well programme last year - although one well, Wingat-1 in the Walvis basin, gave oil shows and allowed oil source-rocks to be identified for the first time. Wingat-1 was drilled in the 2212/07 block, held by HRT with 86% and Galp Energia with 14%. HRT, which holds 10 blocks in Namibia, says the challenge now is to link source rock to reservoir. The company is planning a fourth well next year, for which it is seeking a farm-in partner.
Figure1: Namibia offshore blocks
Tullow shares the optimism for the Walvis basin, in July agreeing to farm-in to the licence covering the 2012A block, operated by Canada's Eco Atlantic. The agreement will give Tullow a 25% interest in return for paying for a 1,000 square km 3-D seismic survey, with Eco Atlantic's interest falling from 70% to 45% - other interests are Azinam, 20% and Namcor, 10%. Tullow can earn an additional 15% from Eco Atlantic, and take over as operator, if it elects to drill a well.
Also seeking farm-in partners is Guernsey-registered Chariot, which holds areas in the northern, central and southern offshore and says it has identified 25 prospects and seven leads. Chariot says it has drill-ready prospects in its northern and central blocks, with the outlook for a northern block potentially to be lifted by the awaited result of another operator's well, nearby. In the south, it plans to take in a partner to finance 3-D seismic, having carried out 2-D work.
Namibia has operated an open-door licensing system for 15 years, as a result of which there are now 45 exploration licences in force, held by 32 groups, according to Namcor. The licences cover most of the offshore out to about 3,000 metres water-depth, with deeper areas being mostly open. In view of the interest in the country's offshore, the ministry of mines and energy is considering ending the open-door arrangement and returning to licensing rounds.
Fiscal terms for oil and gas production are said to be comparatively attractive. The state will take a royalty of 5%, and corporation tax is charged at 35%. There is also an additional profits tax, in three tiers linked to field profitability - the tax becomes payable, at 25%, when the after-tax real rate-of-return reaches 15%, with biddable higher rates applying at profitability-thresholds of 20% and 25%. Exploration costs incurred anywhere in Namibia can be set against corporation tax, and there is no capital gains tax.