Nigeria ready to launch?
Nigeria has massive, but long under-used gas reserves. Now, it may be about to find a local market
Over the past 18 months, interest in Nigeria’s domestic gas sector from both foreign and local investors has started to pick up, triggering pledges of more than $5bn of funding for four major projects. These ambitions still need to be turned into reality, but they could mark a significant upturn to the sector’s fortunes.
The largest of these is a $3bn investment planned by the Dangote Group and indigenous oil producer, First Exploration & Production Development Company (First E&P) to connect the Offshore Gas Gathering System (OGGS), which belongs to Shell, to the western shore of Lagos where it will connect with a $12bn refinery and petrochemicals complex being built by businessman Aliko Dangote. The system comprises a network of pipelines connecting offshore and onshore gasfields in the Niger Delta to the Nigeria Liquefied Natural Gas (NLNG) plant on Bonny Island, Rivers State.
The new pipeline project, known as the East-West Offshore Gas Gathering System (EWOGGS) is one of Nigeria’s largest-ever gas infrastructure projects. It involves the construction of a gas transmission line with capacity to deliver 3bn cubic feet of gas a day, from the offshore fields near Bonny Island, to the Lekki Free Trade Zone in Lagos where Dangote’s 0.65m barrels-a-day refinery is located. Dangote’s multi-billion-dollar project, which includes Africa’s largest urea plant—a $2bn facility with a capacity of 3m tonnes a year—is largely dependent on successful development of this new gas pipeline infrastructure. Dangote has said the refinery will begin production in 2019.
Shell Nigeria has also announced plans to invest $300m in the development of a gas pipeline network in partnership with Gasland Nigeria, a subsidiary of Shoreline Energy Ltd, which has the concession for gas distribution in the Epe, Lekki, Victoria Island and Ikoyi areas of Lagos State. The project would benefit from the EWOGGS, as the system gives Shell a conduit through which to transport gas to Lagos and sell to industrial and corporate users in the concession area.
Meanwhile, Schlumberger said in June that it plans to invest up to $0.7bn in developing two shallow water Nigerian oil blocks—OML 83 and 85—which also hold two large gasfields, Madu and Anyala. The world’s largest oilfield services company will cover all costs up to first oil, in a partnership with field operator First E&P and the Nigerian National Petroleum Corporation. The project will be developed using an existing FPSO and is designed to add 50,000 b/d of oil and 120m cf/d of gas. A final investment decision is expected to be made in December 2017, with first production possible in 2019.
Finally, Greenville Oil & Gas, a Nigerian-based company chaired by Belgian Eddy van den Broeke, said in August it planned to invest up to $0.85bn in a mini-liquefied natural gas plant in Rivers State—the country’s first. The company recently signed a gas supply agreement with Total for the first $0.5bn phase of the plant from one of its blocks. The first phase involves the construction of three trains of 750 t/d each, with two more trains of 1,500–3,000 t/d planned for the second phase. The company says it will initially use around 250 trucks to transport gas around Nigeria, providing an alternative to intermittent pipeline gas.
Why are these projects important? Gas supply through the EWOGGS pipeline could revolutionise the Nigerian gas market. The project would provide a more secure offshore alternative to existing onshore pipeline infrastructure for transporting gas from the gas-rich Niger Delta to the major commercial centre in Lagos. The existing infrastructure, notably the Escravos-Lagos Pipeline System (ELPS) and the Trans-Forcados Pipeline (TFP), is regularly subject to attack or vandalism.
So, the EWOGGS offers the prospect of more reliable gas sales into a network of industrial and power sector gas users around Lagos. It could also be extended further into southwest Nigeria to link up with power generation plants there, which are frequently cut off from gas supply when the ELPS and TFP are out of action. Furthermore, it could also link up with the West African Gas Pipeline, where customers in Benin, Togo, Ghana and potentially Côte d’Ivoire would be eager to receive more gas supply than they currently get due to Nigeria’s limited gas production.
Gas pricing could still derail much investment in the sector
Part of the reason for under-exploitation of the country’s huge proven gas reserves—estimated at around 190 trillion cf, for the domestic and regional market—is due largely to unattractive gas pricing for the power sector, but poor infrastructure is another major factor.
Historically, the considerable down-time for gas pipelines has deterred investment in gas production, despite plentiful demand potential. Shell’s planned investment with Gasland Nigeria may well be indicative of what happens if that pipeline bottleneck can be removed.
The Schlumberger/First E&P OML 83 & 85 field development also benefits from the EWOGGS project. The gas from the fields has a major off-taker in the form of the Dangote petrochemical and fertiliser plant in Lagos, and will need the EWOGGS to get it there.
While the government has been more pro-active of late in promoting the need for investment in the gas sector, the main reason for this flurry of activity may lie in simple supply and demand. Nigeria has substantial gas reserves—and has vast power needs too—so companies are being forced to come up with creative solutions to circumvent blockages, if they are to prosper.
As a result, most new investments tackle the obstacles created by militancy, gas pricing and use models designed to minimise the impact of debt problems in the power sector and onshore pipeline security.
If Greenville’s mini-LNG plant is a success, it could spur the development of others as well as compressed natural gas facilities around the country, effectively doing the same job as a pipeline. Furthermore, Greenville’s plans to introduce LNG-powered trucks for moving the fuel around could also spur a wider switch in the trucking industry towards using LNG-powered vehicles. As a result that could create significant extra demand for both LNG and pipeline gas. LNG would ultimately be a cheaper fuel than diesel and friendlier to the environment.
The regulatory environment could still be a sticking point, even if the government has been trying to reduce its interference in the sector to stimulate investment.
A new National Gas Policy, approved in July by the Federal Executive Council—the country’s highest decision-making body—seeks to create a proper gas market and is expected to form the basis of future gas legislation.
$300m - Shell's planned investment in a gas pipeline network
This policy replaces the old gas masterplan, which was largely ineffective and never fully implemented, and focuses on separating the gas sector from the oil sector fiscally, so it can be assessed independently. The idea is to provide a platform for the development of non-associated gas projects, most of which remain undeveloped.
At present, gas regulations under the Associated Gas Framework Agreement—codified in the Petroleum Profits Tax Act—only allow gas sector investments to be recoverable from oil income. So, while companies could build expensive gas infrastructure to write off against their oil revenues at a given project, there would be no similar benefit for non-associated gasfields, making investment there look unattractive. As a result, Nigeria’s gas production comes mainly from associated gasfields.
But, while the new policy seeks to create a framework for more gasfields to be viable, gas pricing could still derail much investment in the sector. While the private sector in gas functions within a “willing buyer, willing seller” gas market framework, the power sector is still regulated via prices that are not cost-reflective. Power plants are expected to purchase gas at $2.50 per million British thermal units but (with an additional $0.80/mBtu in transit fees), which is considerably lower than the private sector market-driven rate of $4–7/mBtu.
More importantly, for the average small non-associated gasfield with fewer than 1bn cf of gas reserves in the Niger Delta to be economic, a price of at least $3.50/mBtu would be needed. Further offshore, the cost of production increases, except where development expenses can be covered within oilfield development.
The power sector also adds a layer of inefficiency, as it operates with electricity tariffs that are not cost-reflective at the distribution/retail end of the supply chain, in part because they are still based on the old exchange rate of 198 Naira to the dollar before Nigeria’s recent currency devaluation.
Distribution companies also have their revenues constrained by factors, such as system losses and legacy debts from government ministries and other agencies. Weak revenue collection by the distribution companies has resulted in under-payment to power generation companies who are in turn unable to pay in full for the gas they buy from the gas companies.