It took a long time for exploration to make its impact offshore East Africa. Now it has, will there be another wait for LNG projects to look profitable? Professor Alex Kemp reflects.
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The uncertainties surrounding the discovery and exploitation of oil and gas resources are generally well known. The case of East Africa is a good illustration.
Exploration in Tanzania began many years ago. For example, an unsuccessful well was drilled in Zanzibar in the mid-1950s. The Songo Songo gas field was discovered by AGIP in 1974. But, commercial exploitation from this relatively small field did not start until 2004. There was only modest exploration interest.
In recent years, the situation has been transformed through a series of major gas discoveries, generally in offshore deepwater locations. Exploration in these areas only got underway in 2006, with the first major discovery being in 2010. The Tanzanian Ministry of Energy and Minerals estimates total reserves exceeding 57 Tcf, of which 47 Tcf are offshore.
In Mozambique there is a similar history. There was very modest exploration interest after the Second World War. In 1961, the Pande onshore gas field was discovered by Gulf Oil, but it remained undeveloped for very many years with production starting only in 2004. Exploration interest similarly waned for many years. It revived somewhat in the 1990s, but with relatively unsuccessful results in onshore Rovuma basin. Serious offshore exploration did not start until the 21st century. But, spectacular successes have ensued, with several large discoveries in deep offshore waters. Currently, frequently quoted estimates of reserves are around 100 Tcf.
The present position in both countries is thus a happy one, in terms of reserves discovered. Further, there is a reasonable cross-section of large, medium and small investors. This is often regarded as a desirable feature on the grounds that differing views regarding prospectivity and investment opportunities can positively impact activity levels.
Understandably, there has been much excitement in the two countries following the large discoveries, and expectations about the possible benefits from exploitation of the gas resources have been notably aroused. Both governments have highlighted these benefits. In Tanzania, the government has toughened the contractual terms in recent model production sharing agreements by introducing an additional profits tax (resource rent tax), as well as the conventional royalty (effectively paid by the Tanzanian Petroleum Development Corp.), profit gas sharing, and corporate income tax.
In both countries it has been generally accepted that, while some of the produced gas would be used locally as a domestic market obligation, the majority would be liquefied and exported most probably to Asia, where demand is increasing at a fast pace. But, the collapse in oil prices over the past two years has caused investors to rethink the economic aspects of these liquefied natural gas (LNG) projects.
There are two reasons for this. Long-term gas sales contracts to Japan, for example, are indexed to oil prices. The collapse in oil prices has resulted in the average Japan LNG price falling from over US$15/MMBTU in 2013 and 2014 to little more than $5/MMBTU in the early part of 2016. Asian spot LNG prices have behaved in a similar manner.
The second reason for the rethink of the economics of LNG projects from East Africa is the emergence of strong competition from other gas exporters. Australia and the US are important additions to other existing suppliers.
The net effect of the above circumstances is likely to cause some delays to field developments and LNG projects. The overall investment costs are extremely large. As elsewhere in the upstream oil and gas sector, efforts are being made to reduce costs and this will certainly continue.
Costs of LNG schemes have come down substantially in recent years and this should continue over the next few years. In the production sharing contract terms, in Mozambique there are profit-related terms through the R-Factor profit-gas sharing mechanism. This mechanism is progressively related to profitability. The resource rent tax in Tanzania is entirely profit-related. Both mechanisms will to some extent moderate the tax take when profitability is reduced.
From the investors’ viewpoint much also depends on the views taken about future gas prices. The investments will be very long-term ones, and, just as with the oil price, the gas price could well rebound by the time production occurs in the early 2020s. The investors likely to make positive decisions regarding field developments and LNG schemes will be those who (1) take a long-term view and (2) are able to finance the huge costs.
In practice this should mean that the large multinational companies will play key roles. It is encouraging to note that Exxon is reported to be interested in buying into discoveries in Mozambique while Shell has increased its stake in Tanzania.
Also extremely encouraging is the announcement of a long-term LNG sales agreement between Eni and BP, whereby the latter will purchase the entire output from the Coral South field over a 20-year period (See page 52). This contract should greatly ease the financing of both the field development and the planned floating LNG plant.
In sum, the gas deposits in both countries will be successfully exploited. The big question is, when will this happen? In the interim, difficult cost reductions will have to be made, and possibly equally difficult contractual arrangements regarding both the field investments and gas sales agreements.
Alex Kemp is professor of petroleum economics and director of Aberdeen Centre for Research in Energy Economics and Finance at the University of Aberdeen. He has published more than 200 papers on petroleum economics and was a specialist adviser to the UK House of Commons Select Committee on Energy in 1980-1992, and in 2004, and 2009. He was awarded the OBE in 2006, for services to the oil and gas industries and wrote The Official History of North Sea Oil and Gas, published in 2011.