Make-or-break time for Nigerian oil
The government's oil reforms, seen initially as positive for the industry, have been high-jacked by the country's legislators and now threaten upstream investment, Martin Quinlan writes
THE ADMINISTRATION of President Umaru Yar'Adua – now headed by acting-president Goodluck Jonathan, following the president's ill-health – came to power three years ago this month with ambitious plans to reform the cumbersome structures of Nigeria's oil industry. The resulting Petroleum Industry Bill (PIB), now in the late stages of its journey through the legislature, certainly reforms – but the tax increases it imposes could bring the country's vital deep-water development to a halt.
Shell, Chevron and ExxonMobil, the three largest operators in Nigeria, have all criticised the PIB's fiscal changes, with Shell – the country's dominant producer for over 50 years – being uncharacteristically forthright. In February, Ann Pickard, the outgoing head of Shell Africa, said: "All, or almost all proposed deep-water projects between now and 2020 will become uneconomic [and] approximately $50bn would not be invested as planned." Earlier, group chief executive officer Peter Voser cited uncertainties about the fiscal structure among reasons why "we no longer depend on [Nigeria] for our growth aspirations" (PE 2/10 p26).
Yet, two years ago, Shell and other producers had welcomed the new government's first moves in the oil industry. Plans had been set out to replace the joint-venture (JV) agreements between state-owned Nigerian National Petroleum Corporation (NNPC) and the producing companies – the older agreements, covering most of the country's onshore and shallow-water fields – with incorporated joint ventures (IJV). The new entities will be able to raise loans commercially and repay them from income, ending the long-running problem of a government-funded NNPC not having the cash to meet its shares of JV expenditures.
Another welcome change set out in the PIB is the replacement of NNPC – a vast and all-encompassing organisation, wielding great patronage and power – with a number of new entities. A new National Petroleum Company of Nigeria (Napcon) is due to take over the state's upstream interests, with planning and regulatory aspects separated off, respectively, into a petroleum directorate and an upstream regulator. Downstream, the four state-owned refineries are due to be sold, a petroleum products distribution agency will be set up and there will be another regulator for the products and natural gas markets.
But the positive changes were accompanied by plans for increases in the taxes payable under the country's production-sharing contracts (PSC), introduced in 1993 for the first offer of deep-water areas. Then, when the PIB started moving through parliament, representatives made the tax and licensing terms yet-more onerous, pandering to the popular view that the oil companies had been benefiting excessively. Many hundreds of changes were made to the already-labyrinthine document.
The PIB is still subject to changes, but as it moves towards approval – Jonathan backs it and last month appointed a new cabinet to assert his authority – it calls for two new taxes applying to both JV and PSC operations. There will be a new hydrocarbons tax, set at 50%, which will be levied on production instead of profits so costs cannot be set against it and there will be a new corporate tax specifically for petroleum operations, set at 30%. Companies say the new regime will bite deeper than the present petroleum-profits tax, levied at 85%, but with costs allowed against it.
The PIB also introduces higher royalties. At present, the standard 20% royalty for onshore operations is reduced for offshore fields in step with water-depth, to: 16.67% for fields in up to 200 metres of water; 12.0% for 201-500 metres; 8.0% for 501-800 metres; 4.0% for 801-1,000 metres; and to zero when the depth exceeds 1,000 metres. The new royalty, not depth-related, will be linked to the production rate and the oil price, and can rise to 25% or more.
Changes in the way PSCs are structured will also sharply increase the tax "take". At present, PSCs provide for 100% of revenue, after the discounted royalty, to be available for cost recovery. When costs have been recovered, a stream of tax oil is deducted and the remaining stream of profit oil is shared between the company and the state. The 1993 contracts give the company an 80% share of profit oil for the first 350m barrels of production, with the share declining as cumulative production increases. For contracts signed after 1998, the initial company share is reduced to 70%.
Under the PIB's changes, the revenue stream for cost recovery will be reduced, although it was not clear last month by how much – clauses in the PIB are apparently contradictory, reflecting how it has evolved. The change will require taxes to be paid earlier and will increase the state's share of revenue.
Plans for Napcon have also evolved since the PIB was published. Initially, it was to have been 100% state-owned with partial privatisation envisaged for the future. Later, it was decided that Napcon's shares in JVs would be reduced to 41%, from the 55% held by NNPC in the Shell JV and 60% in the others (see Table 1), with the interests relinquished to be held in trust for the benefit of local communities in producing states. Then, in March, NNPC's managing director, Mohammed Barkindo*, visited London to discuss financing options with banks, saying the firm will become a fully privatised commercial company when the PIB is passed.
The choice of 41% for Napcon's reduced interests in the JVs is significant, because the company will have a higher share than the operator's 30% or 40%. At present, the operator takes most of the decisions but, when JVs become IJVs, Napcon will – in theory – be in control. How the IJVs will function is another concern for the producers.
Meanwhile, the government is also requiring increased "Nigerianisation" of oil operations. Companies will have to submit a succession plan for each position held by an expatriate, leading to the expatriate being replaced by his or her Nigerian understudy in a maximum of four years. Operators will be required to set up offices in the Niger delta area, instead of in Lagos or Abuja, to boost local employment. Nigerian-owned companies will be favoured for licence awards, oil sales, shipping contracts and oilfield services.
The uncertainty, together with the continuing difficulties of operating in the Niger delta, can make the idea of selling fields in the onshore, swamp and shallow-water offshore areas increasingly attractive. In December, Shell invited offers for a swathe of onshore fields and other producers are thought likely to do the same. Many fields in the delta are small and mature, and could be operated by smaller companies – which, if Nigerian-owned, might be less likely to be targeted by militants.
In January, Shell and its JV partners, Total and Eni, sold their interests in the OML 4, 38 and 41 licences to Seplat, owned by local firms Platform Petroleum and Shebah Petroleum, and France's Maurel & Prom. Oil and gas fields in the areas, in the northwestern part of the delta, can flow 50,000 barrels a day (b/d) of oil-equivalent, but are shut down because of pipeline damage.
Production and capacity
Hostilities in the delta eased in the second half of last year in response to a government amnesty and offers of cash, allowing country-wide production to climb from a low of 1.7m b/d in July to just over 2.0m b/d in the early months of this year (see Figure 1). However, rebel groups resumed attacks at the end of January, saying that the government had not kept its side of the agreement. According to the International Energy Agency (IEA), average production over 2009 was 1.82m b/d – but this is well below sustainable capacity, estimated at 2.6m b/d. With an additional 0.5m b/d of capacity shut-in, Nigeria is producing at only about two-thirds of its possible output.
Onshore troubles make the country's deep-water operations increasingly important – but, with the prospect of higher taxes, high local-content requirements for oil projects and high support costs, the pace of work offshore has been disappointing. Only four large and two small fields have been brought on stream in Nigeria's deep waters – a sharp contrast to Angola's achievements over the same period (PE 3/10 p10) – and only one stand-alone development is seeing work at present.
The four large developments are Shell's Bonga, flowing 225,000 b/d, ExxonMobil's Erha and Erha North (190,000 b/d), Chevron's Agbami (250,000 b/d) and Total's Akpo (175,000 b/d), while the others are Eni's Abo (30,000 b/d) and Oyo (25,000 b/d). Deep-water production, totalling nearly 0.9m b/d, is exported direct from floating production, storage and offloading (FPSO) vessels, avoiding the onshore risks – although the FPSO at Bonga was attacked in 2008.
The stand-alone development in progress is Total's Usan, launched in February 2008 and due to yield first oil early in 2012. Usan, in water 750-850 metres deep, will use 42 subsea wells to flow 180,000 b/d to an FPSO. The only other deep-water development being implemented is Shell's Bonga Northwest field, to be tied back to the existing Bonga FPSO. Bonga Northwest, launched in October and due for first oil early in 2014, will use 12 subsea wells in 900-1,200 metres of water.
Meanwhile, the other deep-water projects remain "under study", as they have been for some years. These include ExxonMobil's Bosi (likely to flow 135,000 b/d), Uge (110,000 b/d) and Erha North Phase 2 (50,000 b/d). Shell has Bonga North (a Bonga tie-back, likely to flow up to 100,000 b/d) and Bonga Southwest, linked with Chevron's Aparo, which will need its own FPSO and could flow 140,000 b/d. Total has Egina, likely to flow 200,000 b/d.
Refineries and gas
Downstream, the PIB's reforms are needed desperately. The government has made several attempts to sell the country's four refineries, operated by NNPC, without success because regulated gasoline prices are so low. Attempts to raise the price – most recently, early last year – have always led to protests and strikes, with the authorities backing down. Subsidies are estimated to cost the government $3bn-4bn each year.
Meanwhile, the refineries – two at Port Harcourt and one each at Warri and Kaduna – are in such bad condition that they rarely operate at more than 50% of their nameplate capacities, which total 445,000 b/d. Earlier this year, all four were shut down completely when pipelines supplying the inland facilities were damaged.
Consequently, Nigeria is a large-scale importer of refined products, supplied mainly by the trading companies. Gasoline demand ran at about 120,000 b/d last year, according to the IEA, but imports, inflated by volumes illegally re-sold to neighbouring countries, are much higher. For some trading companies, Nigeria is known as a destination where sub-standard cargoes will be accepted.
In the natural gas sector, the PIB sets out to grow the inland market. With so much gas flared-off at the oilfields, this obvious objective – in an electricity-short country – has been government policy for decades, but success has been limited (see Figure 3). The main constraints have been low prices and payment problems, making the supply investments unattractive, and NNPC's inability to pay its share of capital projects – Shell criticised the government recently for "giving priority to maintaining oil production over reducing gas flares".
Pipeline damage is another continuing problem, disrupting exports of liquefied natural gas (LNG) as well as gas supplies to power plants. For much of last year, Shell's Soku gas plant, which supplies 40% of the gas needed by Nigeria LNG's Bonny island liquefaction complex, was shut down following attacks on pipelines (PE 1/10 p14). Nigeria LNG declared force majeure on deliveries and its six-train 21.15m tonnes a year (t/y) capacity was substantially under-utilised for most of 2009.
With the world LNG market in over-supply, most of the various plans for new facilities in Nigeria have made little progress of late. The exception is Brass LNG, a complex to be built at Brass island, Bayelsa state, for which construction bids were invited in March. However, final go-ahead depends on whether producers will be able to supply the necessary gas under the PIB's new regime, according to Brass LNG's chairman, Jackson Gaius-Obaseki. He said he would press the government for "enablers and incentives" for the project.
Brass LNG – backed by NNPC with 49% and, each with 17%, ConocoPhillips, Eni and Total – will comprise two trains of 5m t/y each. In 2007, when the project had been moving towards the go-ahead, outline sales contracts had been signed with BP, BG and GDF Suez, and Bechtel had been awarded a project management contract for early works at the Brass site.
*Acting-president Goodluck Jonathan named Diezani Allison-Madueke as minister of petroleum resources in his new cabinet last month, and replaced NNPC's managing director, Mohammed Barkindo, with Shehu Ladan, a former executive of the company. Rilwanu Lukman, until March the presidential oil adviser, who had been steering the Petroleum Industry Bill through parliament, was not reappointed.