Mozambique’s 100 trillion cubic feet of gas reserve reserves – enough to supply Europe’s four biggest economies for the next ten years – is exciting the most interest. At least one multi-billion dollar liquefied natural gas project in Mozambique is expected to reach financial close next year. Tanzania was the source of a gas-to-power financing as long ago as 2001, in the form of the AES-developed Songas project. The commercial exploitation of Tanzania’s gas reserves, also with a view to export as LNG, is now progressing.

Further into the future, oil discoveries in Uganda, and a proposed pipeline to transport landlocked South Sudan’s oil for export through Kenya, also promise project finance opportunities. In a sector that one banker describes as “unbelievably hot”, East Africa has come alight.

Mozambique’s LNG potential

Anadarko, one of the largest independent oil and gas producers, has a 36.5% stake in Mozambique’s Rovuma Basin’s offshore Area 1, and is likely to be the first to market from the region. It has appointed Societe Generale as its financial adviser and is deemed the more obvious candidate out of Mozambique’s two biggest producers to take the project finance route.

As one banker following the sector notes, Anadarko doesn’t have the high rating of competitor ENI, which is sitting on a 70% stake in Area 4 of the Basin. But it won’t want to carry the smaller shareholders in the Area 1 discovery. These include Japan’s Mitsui, with 20%, but also India-based BPRL, a wholly owned subsidiary of Bharat Petroleum Corporation, with 10%, Videocon Energy Ventures, also with 10%, and Cove Energy, which Thailand’s PTT Exploration and Production recently bought, with 8.5%. Rounding out the Area 1 group of owners is Mozambique’s Empresa Nacional de Hidrocarbonetos (ENH), whose 15% interest is carried during the block’s exploration phase.

Anadarko has made three discoveries – Prosperidade, Golfinho and Atum – and says that the three between them have recoverable reserves of 27 trillion to over 60 trillion cubic feet. Reserves of this size make an LNG project feasible, and the sponsors are currently in early-stage design and engineering, with the hope of getting the reserves certified next year. Anadarko plans to start gas production and the first of an initial two trains by 2018. That puts financial close on the project, which market observers value at over $20 billion, with the debt portion accounting for around 60-65%, at the end of 2013.

However, in another, more likely scenario, Anadarko and ENI could pool their assets into one giant LNG project. ENI is in a joint venture with Portugal’s Galp Energia, which has a 10% stake in Area 4, Korea’s Kogas, also with a 10% stake, and ENH, with 10%. The sponsors of the two blocks will make a decision based on whether tax incentives will cover midstream infrastructure development. The government’s pending commercial framework agreement will settle the question, argues Giles Farrer, senior LNG analyst at Wood McKenzie. “Sponsors are waiting for announcements around the tax ring-fence to see whether upstream operations and the LNG plant would come under the same, or separate, tax systems.”

The cost savings could make one project a compelling option, notes one market observer. “LNG is hard to do in any market. The prospect of developing two is unimaginable. Building one for both has to be the obvious decision.” The implications of separate projects coming to the market at the same time, inviting comparisons between sponsor credits, and pushing labour and equipment costs up, will be daunting for both sponsors and arrangers.

Sharing the cost burden

Whether Anadarko comes out of the starting blocks first with its own project, or the two pool resources, Rovuma’s vast capital requirements mean sponsors will need to tap every source of capital available, including sponsor equity, commercial bank debt, multilateral contributions and export credit agency support, involving SACE, a likely backer of ENI, and US Ex-Im, behind Anadarko.

Bankers also suspect that lender demand for substantial sponsor support is likely to trigger a shift in the equity structure of the joint ventures over the next 12 months, with existing sponsors farming down to reduce their exposure, avoid damage to their credit rating and share capital contributions. “The current sponsors can’t pull it off. There will be a change of equity structure for sure,” says one lender.

Minor shareholders without either the appetite for exposure to, or expertise in, LNG may sell out of their stakes to oil majors keen to get a slice of the upstream asset. Likely buyers include Shell, which tried and failed to beat PTTEP in the race for Cove, as well as Total and BP. The shareholder most frequently linked to speculation that it might sell is Videocon, and there is market speculation over ENH’s ability to finance its share. It may need to sell down equity to fund future development, say bankers, especially if it cannot raise corporate, quasi-sovereign debt to fund equity contributions.

In a pattern that has become common in Australia and more recently Nigeria, where state-run oil group NNPC plans to sell a portion of its shareholding in Brass LNG to offtakers, Rovuma’s sponsors will likely sell down equity to Japanese and Korean buyers of the LNG. Seeking to diversify away from big suppliers Qatar and Australia they favour Mozambique’s proximity to Asia and its cheaper production costs. The entrance of Asian offtakers would, in turn, bring Asian ECAs such as Japan’s JBIC and Korea’s Kexim on board with direct loans, guarantees that would allow commercial banks to provide longer tenors, and a measure of political influence in Mozambique.

Offtake agreements will be crucial to financing any LNG plant, although market observers are unsure as to how long these will be. Financing will depend on offtake agreements of over 20 years, enough to cover 15-year debt and leave a five-year tail. But long-dated offtake agreements may become less popular as sponsors look for more flexibility in terms of where they send their cargoes. Pricing formulas may emerge that switch output to spot price-based pricing two-thirds of the way through the life of any debt. Buyers may also seek the ability to ship LNG somewhere else, spreading output between different destinations.

In the search for offtakers, the sponsorts will have to be confident that they can get their gas to market by 2018. Several other LNG export facilities are about to come on stream, with the biggest threat coming from the shale gas output of the US. From 2015 several developers hope to export this gas in the form of LNG, with one, Cheniere, closing the $3.6 billion financing for its Sabine Pass facility in July. Some estimates put global supply of LNG at 472 million metric tons by 2020, against demand of 369 million tonnes. This potential gap is why the Rovuma sponsors will likely begin funding the first train before a long-term project debt package is in place.

Relationships rule

Maximising commercial lender interest will be another challenge. Bankers compare the scale of the task to Papua New Guinea’s $14 billion LNG development, which was three times bigger than any previous project financing in that country when it closed in 2009. Rovuma’s needs will require a much broader bank market participation than ever before. Mozambique has closed big deals in the past, namely the $1 billion financing of the Mozal aluminium smelter in 2001, but LNG will need new lenders, unfamiliar with Mozambique risk, to win approval to take on exposure to Mozambique.

The sponsor and offtaker composition of the two projects should help uncover new sources of debt. PTTEP, the new owner of Cove Energy, used a bridge loan from UBS to fund that acquisition, and has since moved to pay down that loan with a new equity issue. But Thai banks have become willing to follow their dearest corporate clients overseas. Indian sponsors have also been able to bring in their relationship banks on overseas power and infrastructure financings. Positively, Japanese corporate offtakers’ strong commercial banking relationships will deepen the lender pool and South African banks, which participated in Mozal, should also come in.

Participating in a Mozambique LNG financing will be a key test of the staying power of the large international banks with leadership ambitions in emerging markets oil and gas. “This this is clearly something we’d like to be involved in – Mozambique is a strategic country for us,” says Marc de Saint Gerand, director of oil and gas project finance at Standard Chartered. But the Basel III capital adequacy regulations will be particularly harsh to long-dated debt commitments to frontier emerging markets, and a Mozambique financing will need generous guarantees and sponsor support.

Further north, nearer to market?

Tanzania’s LNG discoveries may also come to market in the coming year, although Mozambique’s discoveries dwarf those of its northern neighbour. The Tanzanian reserve, however, may produce the first financing. Norway’s Statoil and Exxon have discovered 9 trillion cubic feet off Tanzania and have already awarded KBR a front-end engineering and design contract for a new LNG plant. Elsewhere, BG Group, along with Ophir Energy has discovered around 7 trillion cubic feet and is aiming for a two-train facility. “BG’s advantage is that it is a portfolio trader – the key to Tanzania’s success could be progress on offtake structures, even though unit costs could be lower in Mozambique,” says Paul Eardley-Taylor, head of oil and gas for southern Africa at Standard Bank.

The Songas project shows that it is possible to finance the exploitation of Tanzania’s gas reserves, though the deal is now 11 years old, the reserves are only 25km offshore, and the $340 million financing package used the Tanzanian sovereign as an intermediary borrower. The government lent on the funds to the project company, which took a 112MW power plant private and converted it to run on offshore gas. Globeleq now controls Songas, which accounts for 30% of the country’s power generation.

Elsewhere in the region, Tullow is about to refinance its 7-year $3.5 billion reserves-based debt facility, which is now in its fourth year. The company’s offshore Ghana assets in the Jubilee field are part of the existing RBL and will likely remaina part of the new package, but the new debt will allow Tullow to finance new developments in Kenya and Ethiopia. The sponsor has yet to settle on lead banks for the transaction, but is likely to diversify its sources of debt with a high-yield bond next year.

The significant cash reserves of Tullow’s fellow sponsors in Uganda, Total and CNOOC, will be essential when it comes to financing the extraction of Uganda’s estimated 2 billion barrels of oil. The biggest issue for lenders will be how the sponsors plan to bring their reserves to market, given that oil exports will have to go through Kenya, and Uganda’s government is insisting that they build a large domestic refinery.

Similarly, poor access to export markets hampers South Sudan’s significant upstream prospects, which again have Total as a key sponsor. At the moment the landlocked South is reliant on pipelines running through Sudan. Project finance debt for a pipeline to the Kenyan port of Lamu would require transparent agreements with tariff guarantees, proven reserves, offtake agreements and environmental assessments. The difficulties associated with obtaining all these quickly mean that sponsors will most likely fund any pipeline on-balance sheet.

South Sudanese export infrastructure will hopefully be the exception, think project finance lenders, though elsewhere in the region sponsors will have to back projects with sizeable equity stakes, and Asian offtakers will have to provide capital as well as lean on their own banking and ECA relationships. The absence of local liquidity means all projects will depend on external funding and support from multilaterals, and be mindful of their developmental impacts. The race to get the gas to market in time to meet a 2018-202 window adds another layer of complexity. “It’s just around the corner,” notes Standard Bank’s Eardley-Taylor.