Nigeria’s reserves are often characterised as a drop of oil in an ocean of natural gas. With total proven natural gas reserves ranging between 182trn standard cu ft (scf), according to BP’s “Statistical Review of World Energy 2013”, and 187trn scf, according to the Nigerian National Petroleum Corporation (NNPC) – making it the world’s ninth largest – the potential for monetising these reserves is significant.

POTENTIAL: Given that all of this is associated gas (gas found alongside oil), Nigeria’s Federal Ministry of Petroleum Resources (FMPR) estimates that total reserves could reach 600trn scf if operators started exploring for gas independently, meaning these could represent the world’s fourth-largest reserves. Nigeria’s gas is high grade (low sulphur content), sweet and rich in liquids, making it ideal for supplying power plants. However, unlike competing natural gas giant Qatar, Nigeria’s reserves are spread over four major fields, rather than just one.

While two new liquefied natural gas (LNG) projects are at varying stages of planning, the government is prioritising channelling gas to power for domestic use as well as gas-based industries like fertiliser and petrochemicals. With power sector reform ongoing and dependent on a sufficient supply of natural gas, time is of the essence in developing gas processing, compression and transport infrastructure. Although passage of the Petroleum Industry Bill (PIB) will be necessary to unlock more proven gas reserves over the long run, key aspects of Nigeria’s Gas Master Plan (GMP) are already being developed.

MONETISING WITH EXPORTS: Investments in gas processing have thus far been dominated by export projects, with LNG accounting for some 95% of gas monetised in 2010, according to the Department of Petroleum Resources (DPR). Nigeria commercialised its first monetising project in 1999 in opening the Nigeria LNG (NLNG) plant’s first train. Operated by a consortium of NNPC (49%), Shell (25.6%), France’s Total LNG Nigeria (15%) and Italy’s ENI (10.4%), the plant on Bonny Island completed construction of its sixth train by the close of 2007, boosting production capacity to 22m tonnes of LNG and 5m tonnes of natural gas liquids per year. At full capacity the plant requires 3.5bn scf per day, supplied from three joint ventures (JV). The Shell Petroleum Development Corporation (SPDC) JV draws gas from three onshore fields (Soku, Bonnny and, since 2010, Gbaran-Ubie) and two offshore (the Bonga floating production, storage and offloading [FPSO] facility and EA field). Agip’s JV supplied gas from the Obiafu-Obrikom integrated gas supply centre, which gathers feed from its surrounding fields. Total’s JV supplies gas from its Obite site (which it is expanding in 2013), the Ibewa and Obagi onshore fields, and liquids-rich gas from the Amemam and Akpo platforms.

Supplies to NLNG have periodically been interrupted by vandalism and sabotage of gas pipelines, however, with the latest example in May 2013 when Shell declared force majeure at the Gbaran-Ubie and Soku gas plants, cutting gas supply to NLNG by up to 50%. An LNG export shutdown in 2013 caused by Nigeria’s Maritime Administration and Safety Agency, over claims of unpaid fees by NLNG, interrupted shipments for two months before NLNG paid its dues in July 2013. Nonetheless, NLNG achieved the highest daily production rate of 67,770 tonnes in 2012, accounting for roughly 7% of global supply, with Europe buying 63% of the product and Asia 32%. This diversification of customers was prompted by the marked slowdown in US imports amidst growing shale gas production there. Since 2007 NLNG has also supplied roughly 150,000 tonnes of liquefied petroleum gas (LPG), or cooking gas, to 10 Lagos-based LPG marketers (see overview).

PIPING AWAY: Nigeria’s second export channel is the 678-km West Africa Gas Pipeline (WAGP) offshore heading to Ghana, Benin and Togo, backed by operators Chevron (36.7%), Shell (18%), NNPC (25%), and national gas and power companies in Benin, Togo and Ghana. With installed capacity of 800m scf/day, the pipeline linking to Chevron’s existing Escravos-Lagos gas pipeline exports initial volumes of 200m scf/day, expected to peak at 580m scf/day by 2026, when it might be extended to Côte d’Ivoire. The pipeline opened in mid-2012 before being damaged by the anchor of a pirate ship in late August 2012. After eight months of gas flaring, which caused shortages of gas for power in the three destination markets, the pipeline was reopened in the second quarter of 2013.

A third gas monetising project under way is the landmark $8.4bn Escravos gas-to-liquids (GTL) project developed by Chevron (75% of the project) alongside South Africa’s Sasol (the technology owner, with 10%) and NNPC (15%), due for commercialisation by December 2013. This will make Nigeria the fourth country globally to operate such a facility, which will transform 325m cf/day into 35,000 barrels per day (bpd) – with an option to extend this to 120,000 bpd – of GTL diesel, GTL naphtha (used in plastics) and LPG, exported mainly to Europe.

FUTURE EXPORTS: More export projects have been tabled since 2006, including three potential LNG projects and a second export pipeline. The first (most economical) is NLNG’s extension to train 7, adding an annual 7m tonnes to current capacity. The $12bn train would take four years to build and draw on existing shareholders’ gas supplies. In 2006 then-president Olusegun Obasanjo tabled a greenfield LNG plant in Olokola (OK), overlapping the states of Ondo and Ogun. The 22m-tonnes-per-annum facility, known as OKLNG, is adjacent to the OK-Free Trade Zone under development and would consist of four trains backed by NNPC (49%), Chevron (19%), Shell (19%) and the UK’s BG Group (13%). While the roughly $10bn OKLNG would be a mere 5 km from existing onshore gas deposits in the western Delta, a final investment decision seemed far off in 2013 after BG pulled out of the project in May 2012.

The third project is on Bayelsa State’s Brass Island. Backed by NNPC (49%), Agip/ENI (17%), Total (17%) and ConocoPhillips (17%), the $15bn facility is to consist of two trains with a capacity of 5.5m tonnes per year (with an additional two-train option). While the Brass LNG project would be closest to the existing NLNG facility, with gas supplies roughly 80 km away, a final investment decision (FID) anticipated in early 2013 was delayed by ConocoPhillips’ sale of its Nigerian assets to local operator Oando that year. As a result, Brass LNG is now seeking third-party investors to take on the remaining 17% stake by end-2013.

FAR REACH: The most ambitious Nigerian gas plan is a trans-Saharan gas pipeline first proposed in 2002 that would travel through Niger and Algeria, and link Delta gas reserves to European markets. Although Total and Russia’s Gazprom had shown interest in the project, which would export up to 30bn scf/year to Europe via a 4100-km pipeline, cost estimates of above $30bn and an uncertain security situation both in the Delta and Sahara regions have stalled the project. Nigeria budgeted $400m in 2013 to start preliminary feasibility studies on the project.

In addition to security concerns, multiple taxation is another issue that must be addressed in the oil and gas industry, as it is still a major challenge for contractors and investors, according to Ambassador Samuel Jaja, group managing director of Piprox Group. “At the moment, foreign investors are deterred by a lack of policy framework, particularly for pipeline projects that cross multiple states where there is no clear-cut and standard agreement between government, contractors and communities,” Jaja told OBG.

DOMESTIC PRICING: While new export projects may indeed go forward, since 2008 the emphasis in the energy sector has shifted towards creating a greater domestic natural gas market to supply Nigeria’s power sector and key industrial consumers in the cement, petrochemicals and fertiliser industries. The federal government published its GMP in 2008, establishing domestic sales obligations (DSOs) for gas producers, a three-tiered gas pricing scheme and a blueprint to develop nationwide gas pipeline infrastructure.

“The Nigerian gas policy has been aligned to maximise the oil and gas sector’s value to the economy and transit from an oil industry to an integrated oil and gas industry,” Uzoma Akalabu, content development manager at local oil and gas firm Septa Energy, told OBG. “These initiatives have been geared towards boosting the domestic market and realising the maximum revenue possible from gas.”

The government aimed to expand domestic gas supply fivefold from 1bn scf/day to 5bn scf/day by 2015 and 10bn scf/day by 2020 to support a three-fold expansion in gas-fired power generating capacity by 2015, as well as to generate value-added production of fertilisers and petrochemicals like methanol. A DSO of between 20% and 35% of gas producers’ reserves was introduced, linking progress on new LNG export capacity to local market development. Volumes sold as part of DSOs are expected to rise from 3.5bn scf in 2010 to 5bn scf in 2013.

REVISING PRICES: While significant uncertainty continues to surround future fiscal terms given the pending status of the PIB, incentives for the downstream gas industry (including petrochemicals plants) include a 20% capital allowance for four years (and 19% for the fifth), 5% investment tax credits, and royalty rates of 7% for onshore gas production and 5% for offshore production. The GMP’s National Domestic Gas Supply and Pricing Regulation rules established a three-tier tariff structure: raising the gas price from an average of $0.30 per million scf to $1 per million scf for local gas-based industries, $2 per million scf for power generation and $3 per million scf for exports, mainly LNG. While the price of gas remained $1 per million scf for power in 2012, the plan is to raise it to $1.5 per million scf in 2013 (the price on which current power multi-year tariff orders are based) and $2 per million scf from 2014 for new contracts. Legacy contract prices are expected to take somewhat longer to phase out.

Crucially, the latest version of the PIB decoupled domestic gas pricing from wider reform, allowing the domestic tariff to be implemented independently. The new independent Gas Aggregator Company of Nigeria (GACN) was established in 2010 to aggregate gas for domestic purposes and match volumes between buyers and sellers.

DEMAND OUTLOOK: With some 75% of power production currently relying on natural gas, according to the World Bank, privatisation and expansion in the number of power plants will drive domestic consumption (see Utilities chapter). Nigeria’s plan is to raise power generation capacity from the current 8 GW, of which only 3-4 GW are in use, to 40 GW by 2020, according to Shell.

The privatisations of six legacy Power Holding Company of Nigeria (PHCN) companies and 10 national integrated power projects (NIPP) in 2013 will generate more private demand for gas. Two international oil companies (IOC) have already developed their own independent power plants (IPPs): Shell’s 650-MW Afam6 plant in Rivers State and Agip’s 480-MW Okpai in Delta State. The government is requiring all IOCs to build at least one IPP as part of the GMP. Total is developing a 400-MW IPP on its gas-rich oil mining lease (OML) 58, and in April 2013 ExxonMobil’s Mobil Producing Nigeria began construction on a 500-MW power plant at its Qua Iboe terminal.

While PHCN gas payments have traditionally been delayed, with built-up arrears of some N30bn ($189m) by 2013, according to the Federal Ministry of Power, privatisation of power plants will establish reliable private demand through GACN. Some 9.4% of gas produced was sold for domestic power generation and 2% to NIPP projects in 2012, according to NNPC data.

GREATER WANT: Demand from NIPP projects alone – especially driven by the Ihovor, Geregu and Omotosho plants – will grow from 260m cf/day in 2013 to 600m cf/day by 2014, according to the FMPR. To avoid a looming mismatch between demand and supply, the FMPR launched a series of “emergency interventions” in 2012, adding a total of 230m cf/day in the year to June 2013, according to the ministry.

While NNPC expects demand from the power sector to grow from 2.27bn cf/day in 2013 to 4.07bn cf/day by 2017, demand from non-power industries is forecast to rise similarly, from 607m cf/day to 1.49bn cf/day, over the same time period. “Gas monetisation projects, such as ammonia-urea and methanol production, will not only foster gas infrastructure investments, but will also help add additional value to gas that would otherwise have continued to be flared,” Vito Testaguzza, managing director at Saipem Contracting Nigeria, told OBG.

Alongside existing demand from petrochemicals producers like Indorama, which acquired the privatised Eleme Petrochemicals facilities in 2006, and Notore, the sole fertiliser producer, a number of investments in gas-based industries will drive demand. All told, five greenfield fertiliser projects are planned to come on-line by 2017, with a combined capacity of 7.8m tonnes per year of ammonia-urea, alongside several methanol plants. To facilitate such large-scale, gas-based industrialisation, NNPC announced in May 2013 that it plans to build Africa’s largest (2700 ha) gas-based industrial zone in Ogidigben, near Warri, and is looking to attract some $16bn in investment.

GAS GATHERING: At 128 years, Nigeria’s high reserves-to-production ratio, compared to 41 years for its oil reserves, according to NNPC, reflects the country’s currently limited gas production. Despite the start of gas monetisation projects, Nigeria has sustained its position as the world’s second-largest gas flarer after Russia for the past decade. Successive revisions of the 1979 Associated Gas Act sought to penalise flaring, placing fines of over $500,000 per flare. NLNG estimates Nigeria lost some $95bn worth of gas between 1970 and 2008 as a result of flaring.

Gas operations throughout the country have indeed begun to reduce flaring, with the rate falling from 30% in 2010 to 18% by end-2012, and flaring is forecast to drop further to 11% in 2013, according to FMPR, which aims to reduce the overall rate to 2% by 2017. At present, the majority of gas production is operated by IOCs, in 40:60 JV arrangements with NNPC, with SPDC supplying roughly 70% of domestically consumed gas (see overview).

IN SUPPLY: The usable domestic gas supply grew from 573m cf/day in 2004 to 1.5bn cf/day by June 2013, according to NNPC’s group executive director for gas and power, David Ige. Supply is forecast to expand by another 2.15bn cf/day between 2015 and 2019, on the back of six key gas-producing projects by both IOCs and local gas producers awarded SPDC-divested blocks. “A majority of SPDC-divested blocks acquired by indigenous operators seem to contain significant natural gas reserves,” Akalabu told OBG.

NNPC’s operating subsidiary, NPDC, reached production of 400m cf/day in 2012, with sales of 65m cf/day pipeline from its Oredo field on OML 111 in November 2012. The operator says that it aims to raise production to 600m cf/day by year-end 2013. Other local operators like Frontier Energy and Green Energy are also developing their gas production and investing in power generation plants (see analysis). In 2010 Pan Ocean opened the first phase of its Ovade-Ogharefe gas processing plant on OML 98, in which it holds a 40% stake alongside NNPC, producing 130m cf/day of gas. The project, the largest flare-reduction project in West Africa and qualified under the Kyoto Protocol’s Clean Development Mechanism, is undergoing its phase-two extension to add another 70m cf/day to output.

MORE TO COME: IOCs are also investing significantly in expanding their onshore gas production, led by Shell, which in 2012 said it supplied around 70% of the domestic gas market. SPDC is investing $2bn in two projects to extend gas-gathering facilities to 90% of its total operations. The Southern Swamp Associated Gas Solution (SSAGS) and the shallow-water Forcados-Yokri projects will produce 85,000 bpd and 100,000 bpd of oil equivalent, respectively, when they are completed by 2016. “The SSAGS project we are building is a landmark in that it is the first project to be fully executed in compliance with the Nigerian Content Act. Once completed, it will reduce Shell’s gas flaring by 95%,” Testaguzza told OBG.

In June 2013 SPDC also announced a $2.4bn investment in five new gas projects in Bayelsa State – collectively grouped under Gbaran-Ubie Phase 2 – with combined capacity of 215,000 bpd of oil equivalent. The largest single gas supply project was announced in June 2012: the Assa-North/Ohaji-South fields on OML 53 in Imo State. Operated by SPDC with Chevron as a minority partner (20%), the consortium will invest $3.5bn in two separate phases by 2018 to develop additional gas processing capacity of some 1bn cf/day for the domestic power market. In addition, Total has expanded gas production from the OML 58 licence, in which it holds 40% alongside NNPC, from 370m cf/day to 550m cf/day.

INFRASTRUCTURE: Aside from late payments, gas producers’ key challenge has been the lack of an integrated nationwide pipeline system. The current infrastructure, primarily owned and operated by NNPC subsidiary Nigerian Gas Company (NGC), is split between eastern and western networks of a combined 1100 km that are not interconnected. Gas processing and pipeline infrastructure, more capital-intensive than for oil, has been slow to develop.

The western infrastructure, known as the Escravos-Lagos Pipeline System (ELPS), feeds the main ( residential and industrial) consumption centres of the south-west, as well as the pipeline to Ghana. Yet while the eastern network had over 300m cf/day of excess gas supply, according to the FMPR, it cannot be transported to the western pipelines. The ministry estimates that of the 800m cf/day transported on the western network, some 520m scf/day is used for power, enough to generate an average of 1800 MW, and 280m scf/day is sold to domestic industries through the WAGP.

Private gas suppliers like Oando have built their own networks as well; Oando has 100 km of gas pipelines in the greater Lagos area, for example, selling gas from the ELPS to some 100 industrial clients like cement and consumer goods producers. Oando is also investing $125m in a 128-km pipeline with capacity of 100m cf/day from Akwa Ibom gas fields to Calabar-based industries like United Chemicals.

Authorities are keen to encourage more linkages between gas producers and power consumers. Local operator Seven Energy opened the first private pipeline to a power plant in mid-2011, linking its Uquo gas field to the Ibom power plant, with which it holds a 10-year renewable gas supply contract. Seven is also building a 30-km pipeline from Oron to Calabar to supply the Calabar power plant as part of a 20-year supply contract, with construction to begin in 2013. Total production will reach 500m scf/day by year-end 2013, with the 200m-scf/day gas compressor completed in 2012.

IN THE PIPELINE: NNPC is forging ahead with five key pipeline projects. The 136 km Oben-Geregu pipeline was completed at a cost of $245m in November 2011, ensuring gas supply to the Geregu power plant. The 41-km, $41m Itoki-Olorunshogo pipeline came on-line in 2012, supplying gas to NIPP power plants in Olorunshogo. Work has also focused on developing large-capacity backbone infrastructure, beginning with the expansion of the ELPS pipeline loop. The 104-km Escravos-Warri ELPS-A pipeline, costing $258m, was also completed, linking stranded gas at Escravos to Warri and adding 150m cf/day in production by October 2012. The ELPS 2 project covering 324 km from Warri-Oben-Lagos is due to finish in 2013, and aims to double capacity to 2bn cf/day for power and industrial consumers in the south-west. Finally, the 127-km, east-west pipeline from Obiafu-Obrikom to Oben (OB3) and costing $662m is due for completion by the third quarter of 2015; pipe laying for the project is scheduled to commence in January 2014.

Other pipeline projects in the eastern grid include the $52m, 24-km pipeline along the Imo River; the $153m, 54-km pipeline from ExxonMobil’s Qua Iboe terminal to the Obigbo power plant; and a $235m, 51-km pipeline from the Oso gas field to Qua Iboe terminal. Some $600m of the $1bn Eurobond Nigeria issued in July 2013 is slated for the OB3 pipeline.

CENTRALISING PRODUCTION: Feasibility studies have also been completed on the first of three planned central processing facilities (CPFs) envisioned by the GMP. The Western CPF, developed by NNPC, Shell, Chevron and Sahara, will have a capacity of 2.2bn cf/day, including 1.6bn cf of wet gas and 0.6bn cf of dry gas. Construction by global engineering firm KBR and Germany’s engineering consultancy ILF is planned to run from 2013 through 2018 at a cost of $6bn, and the CPF will also feed gas to the Ogidigben gas city. The second CPF in the central Delta is backed by NNPC, Oando and Agip, and will have a capacity of 800m cf/day, drawing on supplies from Assa North. The final investment decision is expected in 2013. Progress on the Eastern CPF, to be the largest at 3bn cf/day, has been slower given delays in securing gas supplies from ExxonMobil. “With respect to progress on the CPF, while work is ongoing on the Central and Western CPFs, progress on the Eastern CPF will depend on the certainty of gas supply sources,” Sam Ndukwe, general manager of gas pipelines and infrastructure at NNPC, told OBG.

NNPC is also planning to attract private investment for larger backbone pipelines, with the two key projects being the 395-km Calabar-Ajaokuta pipeline and the 740-km Ajaokuta-Kaduna-Kano pipeline, due for completion in 2017. “In our endeavour to attract third-party investment for the south-north gas pipeline, we will have to raise the gas transit price for the use of pipelines in order to ensure the project’s bankability,” Ndukwe said. “In this respect, NNPC is engaging with the Nigerian Electricity Regulatory Commission to reflect the revised pipeline tariff in future revisions of the multi-year tariff order for power pricing.” The current transit price of $0.30 per million scf of gas will need to be raised to between $0.80 and $1 to insure the project’s viability.

GSA: With a domestic tariff policy in place and infrastructure under development, the current priority is to establish long-term gas supply agreements (GSAs) for Nigeria’s power projects. “The GACN was established to manage the approved domestic GSAs of oil and gas producers,” Ndukwe explained. “It effectively mediates bilateral negotiations between the gas producer and the off-taker to ensure the final pricing complies with the government’s pricing framework. Beyond the domestic GSA volumes, oil and gas producers are free to sell and contract surplus volumes on a willing-seller, willing-buyer basis.”

To jumpstart the process, the World Bank extended its first partial risk-guarantee (PRG), worth $145m over 10 years, to Chevron’s GSA with the Egbin power plant in April 2013. In all, the World Bank has earmarked $400m for such PRGs on gas, although it expects such support will only be necessary for select projects as GACN establishes credit-worthiness. “PRGs will not be a necessary feature of all GSAs for the power generating plants,” Benjamin Ezra Dikki, director-general of the Bureau of Public Enterprises, told OBG.

With relatively lower gas prices abroad and growing domestic demand, 2013 is a crucial year for Nigeria’s gas revolution. Amid structural reforms, such as viable domestic off-take and significant infrastructure investments, timing will be key to allow for sufficient gas supplies for planned power generation, while the World Bank’s PRGs on both power off-take and select gas projects should help to build credibility as the system becomes established. After a series of false starts over the past two decades, the authorities’ new holistic approach to the gas-to-power conundrum stands a good chance of succeeding.