With one of the world’s most comprehensive privatisation efforts taking place in Nigeria’s electricity sector, the problem of ensuring adequate natural gas supply for power generation has taken centre stage. Although natural gas production has steadily increased in recent years in line with domestic supply obligations and the broad road map of the Gas Master Plan (GMP), development of the required gas pipeline infrastructure in a country where it has traditionally been fragmented between regions has lagged far behind.
Further challenges have been precipitated by plummeting global oil prices, which have also pulled down prices for liquefied natural gas (LNG), from a peak of over $20 per million standard cu feet (scf) in February 2014 to less than $10 by November of that year. Lower demand in Asia has contributed to the dramatic drop in spot prices. Another concern is security: in January-March 2015, Nigeria lost more than N8bn ($48.8m) due to gas pipeline vandalism, according to the Nigerian Gas Company, a subsidiary of state-owned Nigerian National Petroleum Corporation (NNPC). Although repairs on the Escravos-Lagos pipeline that was vandalised in early March 2015 were completed by the end of the month, power plants were deprived of some 1500 MW in the interim, contributing to electricity shortages.
With the long-awaited linkage of the east and west gas pipeline systems now delayed by roughly two years, power plants in the west do not yet have access to supplies from the country’s gas-rich south-east. Although the broader success of the power privatisation initiative is predicated on the NNPC’s ability to build the gas pipeline backbone, some generating companies have concluded deals with gas producers directly for the construction of smaller pipeline spurs to ensure adequate supply. Attracting such private investment to develop longer pipelines with larger capacities, however, will require a significantly higher domestic gas price.
The fact that Nigeria, a hydrocarbons-rich economy with a population of 170m, produces less power than a medium-sized European city points to a vast and long-standing opportunity in the country’s growth plans. To address this, the government unveiled a gas-to-power programme aimed at solving structural issues and ensuring locally sourced gas for power generation. The GMP, first published in late 2008, planned the development of major new gas-gathering and transport infrastructure, to be built by the NNPC and private investors. To unlock new supplies, the GMP included both carrot and stick: gradually increasing the domestic price of gas from as low as $0.2 per million scf to $2.5 per million scf by the end of 2014 to reach parity with export sales through Nigeria’s LNG plant, and instituting domestic supply obligations of between 20% and 35% of gas production for all oil and gas operators. The aim is to encourage international companies to sell to the domestic market, though transmission is still considered to be a bottleneck.
Under the power privatisation initiative, a new Gas Aggregation Company of Nigeria (GACN) was established as an intermediary between gas producers and off-takers among independent power producers (IPPs), harmonising the price nationwide and dispatching supplies to match demand. Power-sector demand, which accounts for roughly 70% of domestic gas consumption, according to the NNPC, has already grown swiftly, nearly doubling from 761m scf per day to 1.36bn scf per day in the year to the fourth quarter of 2010 and reaching 1.7bn scf per day in 2013, according to GACN figures. It is expected to reach a total of 3.5bn scf per day by 2016. In a December 2013 report Ecobank forecast an even higher 5bn scf per day requirement by 2017 if all 10 privatised plants under the National Integrated Power Project (NIPP) are completed.
International oil companies remain the largest producers of natural gas, although more than three-fourths of this output, which stood at 8.2trn scf in the first quarter of 2014, is currently exported in the form of LNG. Total domestic market obligations rose 126.5% to 5.15bn scf per day between 2008 and 2013, though the obligations have not been fully met, with the Shell Petroleum Development Company (SPDC) consortium alone accounting for around 38% of the total, according to GACN. Oil producers are fined N10 ($0.06) per million scf of gas flared, but authorities plan to raise this to $3.50 under the long-delayed Petroleum Industry Bill. SPDC’s consortium is forging ahead with two key gas-gathering projects worth a total of $2bn and expected to cut its gas flaring in Nigeria by 95%. The first, the Southern Swamp Associated Gas Solutions Project, will add 100m scf per day to domestic supplies once completed in 2017, fed through the existing western pipeline system, the Escravos-Lagos Pipeline System (ELPS). The second, the Forcados Yokri Integrated Project, will add another 80m scf per day of gas gathered from shallow-water associated gas.
As an operator, SPDC is planning to develop the $3.5bn Assa-North/Ohaji-South fields on oil mining licence (OML) 53 in Imo State, though Chevron offered its stake in the licence for sale in 2013. Once the project’s two phases are completed in 2018, if the investment go-ahead is granted, they will add some 1bn scf per day to domestic supplies on the eastern pipeline system. In June 2013 SPDC also made a final investment decision on the Gbaran-Ubie phase 2 project and related crude oil Trans-Niger Pipeline Loop-line for a combined $3.9bn. The crude pipeline will carry gas liquids from the south-east to the Bonny export terminal, while the Gbaran-Ubie project will supply Nigeria LNG and the Gbaran-Ubie IPP. As part of its divestments from eight onshore blocks since 2012, SPDC has sold stakes in several of its key domestic gas supplying plants, with the new operator, the NNPC, ramping up its output. In all, SPDC sold its stakes in some 450m scf per day of aggregate output, by selling the 315m-scf-per-day Utorogu plant on OML 34, the 80m-scf-per-day Oben plant on OML 4 and the 50m-scf-per-day Sapele plant on OML 41. The Odidi field on OML 42, with capacity of 300m scf per day, was also sold, although it remains inactive given extensive vandalism of the facility.
In total, the Nigerian Petroleum Development Company (NPDC) had reached 475m scf per day in gas production capacity by the end of 2013, including a new 40m-scf-per-day plant at Oredo that opened in late 2013, even if its effective output in December 2013 was only 289m scf per day. The national operator is expanding the Utorogu plant by another 200m scf per day by 2015. Aside from the NPDC’s gas production, very few local operators are expanding their gas output. “There are only very few indigenous oil and gas operators bringing new gas supplies to market. It is mainly down to Frontier and Seplat,” Dele Kuti, head of oil and gas, power and infrastructure at Stanbic IBTC, told OBG. “There is significant gas potential on Chevron’s divested blocks, but the legal challenges to the divestment process are delaying this.” Although Shoreline holds about 1trn scf of proven gas reserves on OML 30, which it acquired from SPDC, it has delayed plans to restart production, instead focusing for now on boosting oil output. The only Nigerian players developing new gas supplies are those building pipeline spurs to IPPs themselves, given the low regulated domestic gas price.
Historically, two key challenges to attracting investments in gas-gathering and pipeline infrastructure projects have been the low price of domestic gas and chronic shortfalls in power companies’ payments. With privatisation, the spectre of default by power companies has been addressed, while the government has gradually raised the price of gas from $0.2 per million scf in 2010 to $1 per million scf in 2013 and $2.5 per million scf by the end of 2014.
Despite these developments, several gas-gathering projects, including SPDC’s Assa North/Ohaji South, are on hold pending revision of the domestic gas price, and by implication the multi-year tariff order (MYTO). According to industry estimates, a doubling of the domestic gas price would require a 25% increase in the MYTO – the same breakeven price as for gas export projects. “For any export-oriented gas project in Nigeria, investors would require a minimum gas price of $2.5 per million scf to ensure the project’s viability,” Mlandzeni Boyce, business manager at Sasol E&P Nigeria, told OBG. Yet even doubling the gas price to $2.5 per million scf would only attract private investments for pipelines in the south-east near existing gas supplies, instead of for the longer east-west and south-north pipelines needed to bring gas to the power-hungry west and north.
Meanwhile, the potential for paying significantly higher prices for gas is evident for industrial users. The roughly 100 industrial clients of gas companies like Oando and Shell in Lagos typically pay up to $10 per million scf or more for their gas, which they use for their captive gas-fired power generating units. “Once you satisfy the requirements for gas sales to IPPs, you can sell to industrial clients at an acceptable price,” said Uzoma Akalabu, Nigerian content development manager at Septa Energy, a subsidiary of Seven Energy that has stakes in both gas producers and off-takers in the power sector. Several smaller, local gas producers have already concluded gas supply agreements at higher prices, of up to $3 per million scf, which are sufficient to justify investments in the required pipelines.
By the second quarter of 2014, a total of three domestic oil and gas producers had signed gas supply agreements with power-generating companies. Seven Energy became Frontier Oil’s technical and financing partner on the Uquo marginal field, which contains only gas, in a divestment by SPDC in 2009 and developed a 100m-scf-per-day gas plant on it. Seven Energy built its own 62-km, 45-cm Accugas pipeline from the plant to the 190-MW Ibom IPP and started supplying it with 43.5m scf per day of gas in December 2013, under a 10-year agreement. In late 2012 the second phase of the Uquo plant was launched to expand capacity to 200m scf per day and supply another 131m scf per day to the 560-MW Calabar plant as part of the NIPP under a 20-year sales agreement.
The project involves building a 37-kmpipeline to Oron, where it will link up to a 138-km gas pipeline connecting Akwa Ibom to cement producer UniCem in Calabar, which was bought from Oando in late 2013. This connection, initially due for completion by the end of 2014, faced delays as of December 2014 due to blockages caused during pipeline cleaning and other preparations for its coming on-stream.
Another local independent, Seplat Petroleum, is forging ahead with even bigger gas supply plans. Having acquired the 90m-scf-per-day Oben gas plant through SPDC’s divestment from OML 4, Seplat is investing $300m to expand the facility by adding another 150m scf per day to capacity and supplying 160m scf per day to the 450-MW Azura-Edo IPP under a 15-year agreement signed in May 2014. It will also drill another two new wells a year until it reaches a daily production capacity of 350m-400m scf. Crucially, the gas sale price was set at $3 per million scf, the highest to date for a power sector deal. The third notable project near completion is Transcorp’s on OML 281, which it acquired in 2007 alongside SacOil Holding and Energy Equity Resources. The block holds reserves estimated at 4trn scf of gas, as well as proven oil reserves of 104m barrels, which the consortium plans to tap to supply Transcorp’s 972-MW Ughelli plant in Delta State.
Gas supplies from major new projects like the Oben gas plant upgrade are premised on the completion of key gas pipelines, for which the NNPC is responsible. Indeed, the Azura-Edo IPP is building a 1-km spur to the ELPS, which itself will be connected to the eastern pipelines through the OB3 artery. The first phase of the GMP and the country’s highest-volume gas line at 122 cm, the 120-km pipeline from the Obiafu/Obrikom Central Processing Facilities in Rivers State to the Ogbe Intermediate Pigging Station in Edo State will be the key link between the eastern system and ELPS, but has been delayed due to community concerns and the NNPC’s difficulties securing right of way. The initial completion date of 2016 on the $500m contract, which was awarded to Oilserv, is likely to be pushed back to 2017. In early 2014 the NNPC also published a request for interest in financial support for the construction of a south-north pipeline running from Calabar to Ajaokuta and eventually Kano, though the level of private interest remains unclear.
In January 2015 the government announced it had begun designs for its planned $5bn, 1200-km Trans-Nigeria Gas Pipeline aimed at bringing gas to the north and east by 2018. Funding is to come from a mix of debt and equity from both public and private sources, including a public-private partnership currently being arranged, according to NNPC’s group executive director of gas and power, David Ige.
While privatisation of power-generating assets has ensured credible off-take for new gas output, it has also added pressure to complete projects in a timely fashion. Despite delays in critical infrastructure like OB3, new supplies should ensure adequate supply of gas, even if some IPPs may have to wait for 2017 to access them. Although questions remain over whether power generators will be able to last that long, raising the domestic price of gas and therefore the MYTO should help to attract capital from investors other than the NNPC.