Nigeria’s downstream fuels sector has endured a tumultuous few years, from a nationwide strike over consumer costs to corruption scandals. However, more recently a measure of stability has returned to the market, aided in part by government reforms to the pricing framework for fuels. The sector is a crucial one for the country given that the growing 186m-person population is increasing energy demands. In addition, the sector provides substantial income and vast opportunities for a nation that has comparatively elevated levels of poverty, unemployment and underemployment.
Basic Metrics
Despite Nigeria’s abundant petroleum deposits, as much as 74% of energy consumption in the country comes from burning biomass, including wood, manure and other foraged resources, and agricultural residues. The main petroleum product is premium motor spirit (PMS), which accounts for around 70% of the market share of petroleum products. Consumption of petroleum products slumped in 2015, falling from 275,000 barrels per day (bpd) to 266,000 bpd.
The country had 27,238 filling stations as of 2015, and the Department of Petroleum Resources (DPR) licensed another 1050 in 2016. Local independents now dominate this market, with a 91% share. A pricing history from DPR indicates that the major filling stations are more likely to charge consumers the regulated rate and not add on a premium.
Prices In Flux
When the cost of crude oil was over $100 a barrel, Nigeria’s commitment to cap the cost of fuels for its millions of price-sensitive consumers had become an expensive subsidy, in part because while the government’s revenues went up on the basis of its crude exports, it had to import refined fuels and cover the difference between market rates and pump prices. The process was also prone to overbilling and corruption. However, a number of factors have helped to make the market more stable, in turn reducing market distortions and lowering government expenditures, while at the same time improving transparency.
The first is that the fuel pump price has moved closer to the actual cost of the product. The government no longer regulates the prices of kerosene and diesel, leaving PMS as the last staple fuel for which prices are set by the state. The price jumped 67% in 2016, to N145 ($0.51) per litre. Formally, this means petrol is no longer subsidised. Consumers are paying a market rate, and Abuja is not allocating its scarce resources in a way that impacts the Treasury and distorts the market. However, indirect subsidies remain in the system and are a function of exchange rates, creeping in when the naira falls and the state does not adjust prices accordingly.
Fewer Actors
Another reason for the more stable market is that a more challenging foreign exchange environment has led to speculative private operators reducing their activity. The country’s foreign exchange crisis has made fuel importing a less attractive business, given that importers cannot source dollars from the Central Bank of Nigeria and instead have to go to the parallel market. With parallel market rates charging as much as two-thirds higher than the central bank’s formal rate for dollars, which hovered at around N315:$1 in early 2017, fuel importers have seen their margins disappear and most have abandoned the market. As a result, the government handles the majority of imports now: the Pipelines and Products Marketing Company, a subsidiary of state energy company the Nigerian National Petroleum Corporation (NNPC), now has a market share of more than 90%.
Another reason for the diminished role of the private sector in fuel importing is that it has come under increased scrutiny from the government. President Muhammadu Buhari’s anti-corruption drive has involved the cancelling of old contracts and rewriting them with a higher level of scrutiny so that they have more stringent terms.
Stubborn Disparities
The system continues to evolve and price distortions remain, however. As of February 2017, a 79% gap had opened between the prices for diesel and for PMS, two fuels which are more closely priced in international markets.
Despite the regulated price for PMS, in reality prices vary by region, which underscores the difficulty of ensuring compliance with the regulated system. As of March 2017 the National Bureau of Statistics reported a range between N145 ($0.51) per litre in Lagos and N177 ($0.63) per litre in Yobe. However, even with the price hikes of 2016, and despite the difficulty in holding the market to the regulated price, PMS in Nigeria is still the lowest price in sub-Saharan Africa, often by a wide margin.
With a formal cost of PMS that is lower than that of its neighbours, there is an incentive to import into the country and then smuggle into these neighbouring nations, which in turn makes a measure of true demand in the country difficult because some consumption is diverted across borders.
Consolidation
It is not only the import segment that has seen consolidation – there has also been recent consolidation and investment among marketers as NIPCO acquired the Nigerian downstream operations of ExxonMobil, while Forte Oil accepted a $200m capital investment from Swiss trading company Mercuria. Local player Oando also sold a large portion of its downstream assets to the Swiss trading firm Vitol and the London-based private equity firm Helios Investment Partners.
Currently reporting revenues of $290.95bn, Total Nigeria is the only foreign entrant in the downstream marketing sector, in which it is the largest player. Other large marketers in terms of market share include Conoil, MRS Oil and the NNPC. According to a report by Ecobank, as firms look to consolidate in the downstream sector, it is likely these deals will encourage acquisition bids for more large independent petroleum marketing companies.
Gas Consumption
The gas market has also been evolving in recent years as demand in the unregulated market increases. Gas is sold in a hybrid market in Nigeria: a regulated environment in which the price is set at $2.50 per million British thermal unit (mBtu), and supply is scarce and generally limited to power plants producing for the national grid; and an unregulated one in which gas sellers individually negotiate supply deals with major users, for example industrial customers. Negotiated prices are generally higher, with some reports indicating that industrial consumers are willing to pay as much as $7 per mBtu, but as these are typically undisclosed contracts, a precise measure of the market is not available. Generally, however, $4 is considered a market price for which most gas producers would be incentivised to boost production.
In the power sector, the growing ranks of independent power producers (IPPs) are expected to buy in the deregulated market. For example, Azura Edo IPP, which is under construction now, negotiated a deal with Seplat Petroleum Development to buy gas at $3 per thousand cu feet. Gas deliveries are generally subject to an $0.80-per-mBtu transport fee, payable to the NNPC as the operator of most of the pipelines in the country.
The regulated gas supply for the NNPC comes from a domestic supply obligation it applies to producers. The NNPC sets figures for each gas producer, but none have met the full obligation since 2008. For instance, Shell has not provided more than 42% of its obligation, and ExxonMobil and Total have not sold any gas at all to the state since 2008. That is partly due to capacity problems in the pipeline networks, such as the recent attacks by militants, but also due to the comparatively low price, which is far below the rates paid in countries like China and India, where in 2016 the prices stood at $7.54 and $5.50 per mBtu, respectively.
However, indigenous companies may soon be able to make up some of that missing supply: companies such as Seplat Petroleum Development, Seven Energy and Frontier Oil have signed deals to supply gas to power plants. Although these firms will face the same infrastructural challenges as the majors, DPR data suggest that these companies have thus far been willing to sign gas supply agreements in both the regulated and deregulated markets, and will be able to deliver gas when the infrastructure is functional. For example, Frontier sold 253% of its obligatory amount into the system in 2014, and 905% in 2015. Meanwhile, Seplat’s compliance rate was 83% and 82% in those years. This may partly be a reflection of the fact that access to the gas export market for indigenous producers has been challenging. Most gas exports are as liquefied natural gas (LNG) through Nigerian LNG, which is a consortium of gas producers including Shell, Total and ENI.
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