Despite oil prices reaching in excess of $40 per barrel, Africa is unlikely to witness a steady flow of projects for at least a couple of years. "A high oil price is not the only factor that drives projects forward" says Andy Pheasant, director in power and energy at Dresdner Kleinwort Wasserstein. "Most projects are in any case analysed at $18 to $22 per barrel. Just as crucial are the politics of the region, logistical efficiencies and the commercial arrangements surrounding a particular project."

The most exciting exploration blocks have been bid off the coast of Nigeria, around the small islands of Sao Tome and Principe. The joint development authority comprising representatives from the governments of Nigeria and Sao Tome began the licensing procedure last October, after a delay caused by wrangling between the two governments about how to carve up the blocks and a political coup in Sao Tome. Both ExxonMobil and Environmental Remediation Holding Corporation (ERMC) have exercised their pre-emption rights over the blocks, granted as consideration for exploration work the companies undertook in preparation for the tender. Each block is likely to comprise a consortium comprising one or two majors, independents and local (predominantly Nigerian) corporates.

Analysts have said that most of the oil reservoirs located in the joint development zone have estimated reserves of 800 million to one billion barrels - the region has a similar geology to the coast of Brazil. The licence winners for block one were announced in late April. Chevron Texaco has acquired a 51% stake, ExxonMobil 40%, and Norwegian firm Equity Energy Resources, 9%. Chevron will be operator for the block. The award follows Chevron's $123 million signing bid fee. Both Nigeria and Sao Tome should receive $200 million a piece from the signing fees of all blocks.

Block one is located 300km to the north of Sao Tome in 1,750 metres of water. That oil can be extracted from such depths illustrates the advancements in technology, and furthers the polarisation between majors and independents in finding and development. "Ultra deep water is generally a big boys' game," says Pheasant. "To sink an exploration well in deep water can cost as much as $10 million to $20 million per well, compared with a cost closer to $2 million to $3 million for an onshore exploration well. Deep water off the west coast of Africa is beyond most independents, unless they have a small interest within a consortium. There are though opportunities in the shallower waters offshore countries such as Gabon, Cote'd'Ivoire, South Africa and Cameroon, where independents can initially go it alone as an operator, or later as part of a consortium."

But there are a number of private equity houses and venture capitalists willing to back the expertise of independents and help fund their exploration in the Sub-Sahara region. A case in point is the investment that a US independent, Kosmos Energy, has received to pursue the acquisition, exploration and development of oil and gas ventures in West Africa. Kosmos has received commitments of around $300 million from company management, and private equity houses, Warburg Pincus and Blackstone Capital Partners. As well as exploration, the financial backing also gives the company greater clout in upstream projects.

The most likely exit strategy for small unlisted independents is a trade sale to a larger independent or major depending on the quality of their exploration rights. Share prices have not kept pace with the rising oil prices, which tips business strategies towards growth by acquisition.

The emerging independents

Ireland-headquartered Tullow Oil has been active in the M&A market with a $500 million cash and share offer accepted for Energy Africa, a South African-listed exploration company, and is waiting on approvals to finalise the deal. Tullow will partly fund the purchase by new debt facilities and partly by a share placement that will raise about £120 million. Tullow has also entered into an agreement with African Petroleum Investment Limited (APIL) to purchase 50% of the joint venture, EAGHL, it established with Energy Africa. Consideration for the stake is $70 million, to be financed by another placement. ABN Amro advised Tullow.

Energy Africa, which was 56.5% owned by Engen, a South African firm controlled by Malaysia's Petronas, has a number of licensing and production fields throughout Africa and the North Sea. In Sub-Sahara these include stakes in blocks off the coasts of Mauritania, Senegal, Equatorial Guinea, Gabon, Congo, Namibia and South Africa, and onshore sites in Uganda, Gabon and Congo. Following the acquisitions Tullow has an annual operating cash flow of approximately £170 million, and a production of around 54,000 barrels of oil equivalent per day and proved plus probable reserves of some 175 million barrels of oil equivalent with a total reserves life of over 10 years.

There are a number of other independents with a high exposure to Sub-Saharan exploration and production; these include Dana Petroleum (UK), Woodside (Ausralia), Forest Oil (US), and Addax Petroleum (Swiss), amongst others. The upside to greater play by the independents is that they are more likely to go the project financing route on downstream developments. This is some tonic to project financiers and senior lenders, which are generally shunned by the majors.

"The other side of the high oil price argument is that the oil majors and state owned oil companies now have significantly improved liquidity, and the need to finance is therefore lessened," says Don Hultman, executive director, structured capital markets at ABN Amro. "Although project finance will remain an attractive option in some scenarios, at the margin, with long-term oil price projections continually revised upwards, and the resultant ability to fund exploration and capital expenditures from cash improves, the decision to utilise complex and time consuming project finance structures becomes increasingly less attractive."

Despite the difficulties of financing in the region - differences in the legal and regulatory framework, emerging Equator Principles issues and political risks - project financing will continue to be used where there is a less cash rich partner in the project, such as an independent or a parastatal organisation, or where there is a need to negate political risk.

Two to follow

A template for future projects is likely to be the hybrid financing for the $1.2 billion Mozambique-South Africa Pipeline. Sponsored by Sasol, it reached financial close on a 12-year R3.38 billion ($532 million) loan on 15 March. Although all the commercial risk is taken on balance sheet, the deal turns non-recourse in the event of a political risk-driven default. There are three tranches to the deal: R1.46 billion in commercial debt underwritten by Standard Bank; R450 million from the European Investment Bank; and R1.47 billion in multilateral/development fund debt lead arranged by Development Bank of South Africa. The R1.46 billion tranche 1 is full recourse to the sponsor, but turns non-recourse on a political risk insurance (PRI) event. PRI is provided by MIGA, which put up R820 million of cover and reinsured R310 million evenly between Italian ECA Sace and Australia's EFIC. Also, South African ECA ECICSA is guaranteeing R430 million and IBRD's PRG unit covering R210 million. Pricing on the tranche is 320-330bp over Jibor, dependent on the sum of the fee to each PRI provider and the corporate loan margin.

"I envisage a number of other financings following the structured political risk approach adopted by Sasol," says Greg Fyfe, head of structured political risk, project finance at Standard Bank, "A key issue for sponsors is how to structure the political risk cover to achieve both the 'hard' and 'soft' benefits of the cover. The 'hard' benefits relate to the ambit of the cover itself and the protection that this cover provides to their balance sheet, whereas the 'soft' benefits include the inherent political risk mitigation which a particular political risk insurer brings, as well as how the cover is structured. Also key is the weighing of expense and time of project financing against its ability to mitigate political risk. A structure such as Sasol's reduces the time and expense of conventional project financing but allows a sponsor to benefit from a better political risk guarantee. The structure of the cover is also focussed on both the prevention and cure of a political risk event. It is particularly useful in circumstances where a sponsor has balance sheet capacity and appetite for commercial risk - which there is for African oil and gas - but an unwillingness to be exposed to the political climate."

The Chad-Cameroon pipeline financing has the most prescriptive details of how a government is to spend its money from oil extraction to date. After four years in the making, the financing package for the 1070km Chad-Cameroon pipeline connecting Chad's Doba oil fields to offshore loading facilities on Cameroon's Atlantic coast closed in 2001 and syndication was signed in June. A $600 million non-recourse tranche was raised solely against downstream development, with project financing accounting for only 30% of the pipeline and 15% of the total project but its key use was in attracting political risk mitigation. The debt was lead arranged by ABN Amro and Credit Agricole Indosuez and ECAs Coface and US Ex-Im. Equity partners include both governments and a private consortium led by ExxonMobil and including Malaysia's Petronas and Chevron. The World Bank provided loans totalling $134.1 million and the IFC, the Bank's private sector arm, raised a further $200 million toward the overall $3.7 billion cost of the development. With the project expected to generate $2 billion over 25 years a revenue management law was passed by the Chadian Parliament in 1999. Under this law 10% of royalties are placed in a future generations fund, and the remaining 90% is divided between 5% for development in the Doba oil field areas; 80% for education, health and social services, rural development, infrastructure and water management projects; and 15% to the Treasury current account.

The extent to which either of these models will be used in future looks certain for a wait, with few immediate projects in the pipeline. The West African gas pipeline is awaiting a final investment decision, although perhaps with the exception of Ghana, all sections of the pipeline look set to be funded by equity. The principal driver behind the investment is the chronic shortage of reliable energy in Nigeria's neighbouring countries and the gas flaring issue. The pipeline links Chevron's Escravos gasfields in Nigeria to power plants in Ghana, via plants in Benin and Togo. Chevron Nigeria was appointed project manager and Deutsche Bank is advising Chevron.

A $1 billion receivables-backed loan is expected to close imminently for the second phase of the Mobil Producing Nigeria natural gas liquids (NGL) plant. Mobil Producing Nigeria Unlimited and Nigeria National Petroleum Corporation are the sponsors (with Mobil operating) and CSFB is assembling the financing. OPIC will provide a $325 million investment guarantee. The sixth train on NLNG is moving forward and is currently in the bid stages. Citigroup is advising the sponsors, which comprise NNPC, Total, ENI and Shell. Also in Nigeria, the $2.25 billion Brass LNG project is believed to have appointed WestLB as an advisor, but FEED studies are still ongoing.

The financing for the $2 billion to $3 billion Lobito SONAREF oil refinery project in Angola is not expected until another 12 or 18 months. Although an element of project financing is anticipated, certain sections, such as the LNG portion, are likely to be financed entirely by equity.

"When developers and government officials come to the table it is important that both parties have realistic expectations and awareness of what is possible and what is required," says Paul Biggs partner and head of project finance at Cadwalader, Wickersham and Taft. "It is important that expectations are properly managed at an early stage: if this is not the case, parties can get surprised further down the line and this dramatically protracts the time it takes a deal to reach financial close."