Opec uncertainty threatens Angola’s expansion plans
Angola’s breathtaking development as an oil producer is slowing, perhaps stalling, because capacity is so far in excess of the country’s Opec production quota
ANGOLA’s oil-production capacity has nearly tripled in the 15 years since the country’s first deep-water discovery. As well as becoming one of the world’s fastest-expanding oil provinces – and a welcoming environment for the major companies’ capital and expertise – Angola has emerged as a large source of crude for China and the US, each of which takes about a third of the country’s over 1.8m barrels a day (b/d) of production.
Geologists say there need be no end in sight to Angola’s expansion – but since January 2008, when the country was taken into Opec’s production-quota system, the pace of development work has noticeably slowed. Since that date, only two large deep-water developments, Total’s Clov and ExxonMobil’s Kizomba satellites, have been launched, while another, BP’s PSVM, was approaching contract awards at the time and went ahead. Many fields, appraised and with early development engineering completed, have seen little or no recent progress.
The problem is that Angola’s output is already well in excess of its production quota, and is set to rise further. Opec allows Angola a quota of 1.517m b/d – but, according to IEA figures, production has averaged about 1.80m b/d in each of the past three years. Other estimates are higher – Petroleum Economist’s field-by-field figures point to over 2.00m b/d in 2010, including condensates and liquefied petroleum gas.
Government figures acknowledge the over-production. Towards the end of last year, the finance ministry said output in 2010 was due to average 1.86m b/d, and would rise to 1.90m b/d this year and to 2.13m b/d in 2012.
Production capacity is yet higher. Petroleum Economist’s field-by-field figures indicate a capacity of 2.23m b/d at the end of 2010. Projects being implemented could raise the figure to as much as 2.77m b/d before the end of 2012, although, with allowance for some loss of capacity in the older fields, 2.60m b/d might be more realistic.
With oil prices high, Opec is not immediately concerned about persuading its members to adhere to their output quotas and there is widespread over-production. However, the oil market can change and companies with development projects planned have long time-horizons: Angola’s deep-water developments typically involve a four-year construction period and investments can be well over $5bn. Production needs to run at design capacity, long-term, to ensure project rate-of-return targets are met.
High reliance on just four companies could be another consideration holding back project go-aheads. With the exception of one small field operated by state-owned Sonangol, all Angola’s deep-water production comes from licences operated by Chevron, Total, ExxonMobil and BP. These companies all have numerous fields in preparation for development, but evidently do not want to overstretch their engineering teams by running development projects in parallel.
The Angolan authorities sought to address this limitation in the country’s last licensing round, which opened as long ago as 2005 and was intended to widen the operator base. The round brought in four new operators – Eni, Petrobras, Tullow and Vaalco – and also Total, which signed-up for the relinquished part of its existing Block 17.
Eni went on to spectacular success in its Block 15/06, with seven discoveries made and two production hubs planned, and Total also made discoveries. However, the other new operators have not been so well rewarded – and Petrobras is understood to be reconsidering its strategy after drilling three unsuccessful wells. Another licensing round opened in 2007, but was delayed several times without a clear reason, leading to suggestions that the expected high signature bonuses and substantial interests required for Sonangol were too much for the relatively small companies the authorities wanted to attract.
According to oil minister José Maria Botelho de Vasconcelos in December, the next round will open this year. The emphasis is likely to be on the country’s pre-salt prospects, for which there are high hopes. Because Africa was once joined with South America, Angola’s geology is similar to that of Brazil where large pre-salt discoveries have been made. The areas offered in the delayed round – Blocks 19, 20, 46, 47, 48 and the onshore Cabinda Central and Kwanza basin KON 11 and 12 licences – are said to have pre-salt potential.
But pre-salt exploration is not for the faint-hearted. According to Sonangol’s estimate, pre-salt wells in deep water will cost $100m each – and the success rate is unlikely to be high because the salt layer reflects seismic energy in many directions, making imaging difficult. The firm indicated last year that pre-salt blocks would not be thrown open for bids in the usual way, but would be offered to selected companies with the necessary resources of capital and technology.
Meanwhile, Chinese and Indian companies continue their march into existing licence areas, snapping up interests as they become available. In the BP-operated Block 31 – due to become the country’s first ultra-deep-water producing area by the end of the year, when the four-field PSVM starts flowing – India’s state-owned ONGC is negotiating to acquire the 25% holding that ExxonMobil wants to sell. China Sonangol International (CSI), Sonangol’s venture with Chinese infrastructure construction interests, recently took over Total’s 5% holding in the same block. Also on offer are the interests of Croatia’s Ina in eight shallow-water producing fields in Block 3.
Sonangol claims the right to find buyers for holdings that companies want to sell and it exercises the right vigorously. In 2009, the company blocked Marathon’s agreed sale of a 20% interest in Block 32 and acquired the holding for CSI, with Manuel Vicente, Sonangol’s president, asserting that “when [companies] are no longer interested they have to return [assets] to the owner, the government of Angola, and cannot commercialise them publicly.”
One consequence of this arrangement, however, is criticism that the licensing process can be less than transparent. A number of little-known companies without significant oil experience have been granted interests – for example, Kotoil and Poliedro in Block 2/85. Recently, US company Cobalt International accepted Nazaki and Alper into its licences covering Blocks 9 and 21, with substantial shares. Cobalt says it is paying 62.5% of the cost of work in the two blocks, although its holding is 40%.
Private-equity backed Cobalt is soon to start drilling in Block 21 and says its two planned wells will be the country’s first deep-water wells specifically targeting pre-salt prospects. The firm has contracted Diamond Offshore’s Ocean Confidence semi-submersible for wells into the Cameia structure, at a water-depth of 1,700 metres, and Bicuar, at 1,550 metres, and is due to move the unit to Angola in the first quarter.
LNG next year
Angola is due to achieve its long-held ambition of joining the world’s liquefied natural gas (LNG) exporters next year, although the final cost of the Angola LNG project is said to be escalating well above the $8bn estimated by Bechtel, holder of the main contract for the onshore facilities. Angola LNG – Chevron, 36.4%, Sonangol, 22.8%, and BP, Eni and Total with 13.6% each – is building a facility of 5.2m tonnes a year capacity on Kwanda island, near Soyo, with output destined for the Pascagoula terminal on the US Gulf coast.
Gas is to be supplied from oilfields in Chevron’s Blocks 0 and 14, ExxonMobil’s Block 15, Total’s Block 17 and BP’s Block 18, backed up with non-associated gas from fields already discovered in Blocks 1 and 2. The flow from the Chevron fields will necessitate a crossing of the Congo river estuary and the installation of several structures, for which bids are being invited. As well as supplying the LNG plant, the gathering system will make available 1.3bn cubic metres a year of gas for inland use.
Progress with another mega-project, Sonangol’s planned new Sonaref refinery at Lobito, is less positive. The start-up target for the first phase of the facility, providing just over half of the eventual 200,000 b/d capacity, has been put back to 2015, with the second phase following a year later – although engineering sources say that work is still at a very early stage.
Sonangol is pursuing the project on its own, having failed to attract the participation of foreign partners. Last year, it said the likely cost had risen by $8bn above its earlier $2bn estimate. The facility will be costly because it is to be capable of processing Angola’s heavy and acidic crude streams, for which there is limited refining capacity available worldwide.
Meanwhile, Angola’s only refinery is inadequate to cover the country’s rapidly growing requirements and there are substantial imports of refined products. There are plans to increase the 39,000 b/d capacity of the facility, at Luanda, to 100,000 b/d. The refinery is now controlled by Sonangol, following its acquisition of Total’s interest.