With a reform effort under way in its premier oil producer and with production climbing elsewhere in the region, Africa remains a prime target for international oil and gas investment. But deal structures are changing as national oil companies (NOCs) compete for opportunities and independent producers move into areas once considered realms of major international oil companies (IOCs).
Last year, Africa’s production of crude oil and condensate increased by an estimated 3.3%, making it the world’s second-fastest region for production growth behind Eastern Europe, including the Former Soviet Union, in OGJ’s Worldwide Production Report (OGJ, Dec. 24, 2007, p. 22). Africa’s production was 9.244 million b/d. Output rose in Angola, Sudan, and Tunisia but fell in region-leading Nigeria by 2.4% because of attacks on pipelines.
As it is elsewhere in the world, an emphasis on gas is gaining in Africa, which, according to some analysts, will account for 25% of LNG export capacity by 2010. Equatorial Guinea joined Algeria, Egypt, and Nigeria as an LNG exporter last May, and Angola hopes to deliver its first cargo in 2012. Nigeria has begun an aggressive program to increase natural gas production and revenues from it.
Independents and NOCs
Competition for African exploration and production rights has intensified with the influx of independents and NOCs.
High oil prices and attractive fiscal terms and incentives have attracted independent producers to frontier areas, such as Tullow Oil in Ghana and Uganda (see story, p. 22).
State-owned Chinese companies have acquired assets in Nigeria by offering soft loans, military supplies, and construction of transportation systems. These deals illustrate NOCs’ aggressive expansion strategies.
One independent producer based in London has moved into Nigeria by emphasizing local relations. A spokesman for Afren PLC told OGJ that its success in Nigeria, where it holds interests in seven offshore and onshore tracts, is that it is staffed by nationals and is therefore recognized as a local company.
“We have worked very hard to build community relations through scholarships and building schools,” he said. It also helps that, as a small company, Afren can make decisions quickly. The company is assessing domestic gas production and long-term LNG projects in partnership with E.ON Ruhrgas and African LNG.
In response to the competition, major companies are entering innovative deals.
Eni SPA, on May 19 reported a multifaceted agreement with Congo (Brazzaville) that it described as a “new integrated model of cooperation.” The deal calls for investment of $3 billion and covers development of an expected 150 million boe of equity production during 2008-11, including tar sands and biofuels. Eni also will build a 300-450 Mw gas-fired power station near the Djeno oil terminal and will help with Congo’s infant health-care program in rural areas.
The tar sands agreement provides for exploration and development of two areas called Tchikatanga and Tchikatanga-Makola covering a combined 1,790 sq km. Eni said preliminary study of a 100-sq-km area indicates potential recoverable oil volumes of 2.5 billion bbl unrisked and 500 million bbl risked.
The areas are near M’Boundi oil field, associated gas from which might supply a heavy-oil upgrading plant based on proprietary Eni technology.
For biofuels, Eni signed a memorandum of understanding for collaboration in the use of palm oil for production of biodiesel. The project involves palm-tree cultivation on 70,000 unfarmed hectares in the Niari region in the northwestern part of the country. It’s expected to produce 340,000 tonnes/year of crude palm oil for domestic food supply and production of 250,000 tonnes/year of biodiesel.
Eni’s power-plant deal includes development of 56 million boe of gas reserves and associated liquids, with production net to Eni’s interest of 22,000 boe/d.
Nigerian production
International attention on Nigeria’s oil production problems has tended to obscure the country’s reform efforts and new emphasis on gas. While real, those problems may be easing.
Nigeria’s oil output has fallen by 265,000 b/d because of work stoppages and attacks on oil facilities in the Niger Delta. Facilities in production averaged 1.85 million b/d, far short of the country’s Organization of Petroleum Exporting Countries quota of 2.16 million b/d of crude oil.
But high oil prices offset the economic effects of the disruptions. Goldman Sachs has predicted that Nigeria’s export revenues will surge to $92 billion in 2008, assuming production of 2 million b/d and an oil price of $150/bbl by yearend.
According to Emmanuel Uduaghan, executive governor of Delta state, operators have repaired equipment, and kidnapping of oil employees in his state has ceased. The state has implemented a development and security strategy to provide training opportunities and build transport systems and power generation via public and private partnerships.
“Oil workers are travelling by boat instead of airplanes, which shows that things have improved,” Uduaghan said. He urged oil companies to enlarge the local workforce to help Niger state residents benefit from petroleum development.
Nigerian gas plan
Although Nigeria has gas reserves estimated at 184 tcf, seventh highest in the world, and a gas resource estimated at 600 tcf, exploration oriented to gas has been rare. The government wants that to change, hoping to realize as much revenue from gas as it does from oil by 2010.
A “gas master plan” under development for 6 years offers operators new investment opportunities, responding to projections of 20-25% growth in domestic gas use driven by power generation and industrial development. The government has launched its Domestic Gas Supply Obligation (DGSO) with an immediate effect requiring operators to set aside gas production for local markets.
Emmanuel Odusina, Nigeria’s gas minister, told OGJ that the allocation varied among companies, depending on three variables: reserves, amount of gas used commercially, and amount of gas flared. Essentially, the company having the greatest volumes of gas would contribute the most to the domestic market.
Odusina is gathering comments from companies on their obligations in line with their supply plans. About 1 bcfd of gas is expected to be allocated to the market initially, growing to 4-5 bcfd over 5 years.
Nigeria is determined to develop its local, regional, and export markets concurrently, although preference to date has been given to exports. Expansion of Nigeria LNG to a seventh train is under development, and other projects such as Brass and OK LNG are being evaluated. One senior LNG executive said exports and domestic gas supplies were compatible goals. But more gas exploration will be needed.
David Ige, group general manager and senior technical advisor at Nigeria National Petroleum Corp. (NNPC), said the government wanted to make local, regional, and export markets equally attractive. By 2011 domestic gas prices should be on par with export values.
Nigeria has limited pipelines and processing facilities and has invited investors to spend $20-30 billion under its gas infrastructure blueprint (OGJ Online, May 6, 2008). Investors are to develop bid proposals by Dec. 15, 2008, for evaluation by the government in next year’s first quarter. Investments are expected to begin in April 2009.
Gas blueprint
Under the scheme envisioned by Nigeria’s gas blueprint, wet gas from oil fields in the Niger Delta will be processed in three central processing facilities (CPFs). Lean gas will be transported through a transmission line network to markets, and liquids will be stored for local use or exported.
The government is requesting CPFs in West Delta (Warri/Forcados area), Obiafu (North Port Harcourt), and the Akwa-Ibom/Calabar area. It also wants three gas pipeline transmission systems, including compressor stations:
- A 1,135-km, 48-in. diameter south-north pipeline between Akwa-Ibom in Calabar state and Kaduna via Abuja. It will have a capacity of 3 bcfd and will deliver gas to eastern, central, and northern Nigeria. This line also would carry about 2 bcfd of gas for the proposed Trans-Sahara Gas Pipeline. South Korean investors have committed $5 billion to building the 1,200-km Ajaokuta-Kano link as part of their acquisitions of the Oil Prospecting License 321 and 323 areas in 2006. Pipeline operations are expected to start in 2013. The government is looking for investors to construct the Calabar-Ajakuta leg.
- A 700-km, 42-in. western pipeline system that would link the existing Escravos-Lagos pipeline system to Shagamu with a 200-km offshore extension. The proposed capacity is 1.3 bcfd. The system would extend to Jebba with a spur serving the OK LNG plant.
- A 200-km Interconnector system between the Obiafu CPF and Ajaokuta to deliver gas from the east to the western and north-south transmission systems. It would have a capacity of 1.7 bcfd.
Ige told OGJ that, although NNPC was undergoing reform, it was also examining these gas opportunities and would invest as appropriate.
“There is no compulsion for investors to team with NNPC,” he said. “Our decisions will be commercial ones.”
But potential operators are worried about the effectiveness and independence of the proposed gas regulator under industry reforms.
Another issue is risk mitigation because supply would come from the troubled Niger Delta. The impact of Nigeria’s gas policy regime is still to be clarified for existing and proposed projects.
Tony Chukwueke, director of the Department Petroleum Resources (DPR), said third-party access was a major priority under the gas master plan and would be obtained through government-facilitated agreements. “Companies can get access to gas that is being flared, pay existing operators to produce gas on your behalf, or produce it yourself,” he said. The DPR and oil companies are discussing flaring targets.
Petroleum reforms
With changes starting in June, Nigeria’s revamp of its petroleum industry aims to improve efficiency and eliminate conflict of interests among agencies, said Emmanuel Egbogah, petroleum advisor to the president.
NNPC is often criticized for delaying projects due to bureaucracy and managers fearing blame if decisions backfire. The reforms are expected to take up to 2 years to fully implement.
The government is considering partially privatizing NNPC.
“We want to make ownership more spread out amongst Nigerians,” Egbogah said. “And the government would have no less than 40%. Then it would be a business enterprise with reduced interference by the government.”
A national energy council, chaired by the president, will be formed to set policy. Operators will answer to the Petroleum Inspectorate Commission, the technical and commercial regulator of the upstream business that would subsume the current DPR.
Egbogah told OGJ that a new National Petroleum Research Center comprising representatives from different oil companies would address specific industry problems, integrate technology development programs, and offer technical consultancy and laboratory services.
Under the reform, NNPC would become an operating company, named National Oil Co. (NAPCON), and would forgo its present regulatory and policy-making functions (OGJ Online, May 9, 2008).
“It will focus on how to make itself competitive both domestically and internationally with its own capital from international and local markets,” Egbogah said. Basic business units will be incorporated joint ventures instead of joint ventures. The change would enable NAPCON to secure funding from the market instead of relying on the government.
NNPC is looking for an additional $3.8 billion this year to meet its JV commitments. The government has provided $4.9 billion. On May 20, NNPC signed upstream finance deals with Total SA and Mobil Producing Nigeria (MPN) for a total of $3 billion. The loans will help the government reach its target for domestic gas needed for power projects and local industrial development.
According to the agreement with Total, NNPC will borrow $1 billion and pay back the loan with cash rather than crude oil as in the past. Similar terms were reached with Mobil, but the sum is $2 billion.
Angola’s growth
Elsewhere in Africa, Angola has overtaken Libya as the region’s second most prolific oil producer.
At 1.695 million b/d last year, the country’s output was up 20% from the 2006 level. Libya’s 2007 production was down slightly at 1.7 million b/d. In February, the latest month for which data are available, Angola’s production averaged 1.919 million b/d and Libya’s, 1.76 million b/d (OGJ, May 12, 2008, p. 62).
Angola’s production is predominantly from deep water, however, with thick salt layers and diapirs complicating technical problems.
At present, Angola has 21 deepwater fields on production. Start-ups within the last year include BP PLC’s Greater Plutonio complex on Block 18 and ExxonMobil Corp.’s Kizomba C on Block 15. Next year, Chevron Corp.’s Tombua and Landana fields on Block 14 are scheduled to start production, which will hit 100,000 b/d. And in 2011 Total SA’s Pazflor on Block 17 is expected to produce first oil.
Speaking at the Offshore Technology Conference in Houston, Graeme Stewart, the Resource Development Manager for BP in Angola, said seismic imaging, subsea acoustic monitoring, and real-time downhole data were key to successfully starting Greater Plutonio. The field has 43 wells: 20 producers, 20 water injectors, and 3 gas injectors.
Steward said “world-class seismic” provided “very clear imaging of the subsurface,” which he called “absolutely critical to targeting wells.”
The US Energy Information Administration expects Angolan oil production to peak at around 2.5 million b/d in 2011 and fall to 2.4 million b/d by 2013.
Analysts worry about how Angola’s joining OPEC at the beginning of 2007 will affect production.
Syanga Abilio, vice-president of state-owned oil company Sonangol, told OGJ: “We joined the institution that works to protect price, and it was important to be part of that. We were an observer at OPEC for a long time. We have a quota of 1.9 million b/d, but that does not bind us on further exploration and production. We had our oil infrastructure destroyed during our civil war, and there is nothing to fear with future investment.”
Spiraling costs are a major problem for operators in Angola. According to Chris Brown, West African analyst at Wood Mackenzie, Edinburgh, projects under development in Angola could, at $30-40 billion, be double the cost of those now on stream. Pointing out that Angolan production-sharing contracts are based on internal rate of return, Brown said, “Much of the upside is taken by the country; thus, if development costs are high, Sonangol will lose a higher percentage, but both company and country will lose out.”
Angola’s latest licensing round attracted interest from 200 oil companies in 10 blocks: the onshore Cabinda Centro Block in the Cabinda Centra basin and KON11 and KON12 in the Kwanza basin; shallow-water Block 9; deepwater Blocks 19, 20, and 21; and ultradeeepwater Blocks 46, 47, and 48. The government has prequalified 40 companies and suspended its block-proposal deadline while it evaluates applications by private Angolan companies.
Angolan LNG
Angola’s focus so far has been oil, but natural gas is also of growing importance with the development of Angola LNG and the formation of Sonangas, a subsidiary of Sonangol that will focus on gas development.
The Congo basin holds the best potential for gas. Sonangol’s Abilio said Sonangas is mapping and interpreting geological information and plans to drill a well by the end of the year.
Angola LNG will gather otherwise-flared gas to produce 5.2 million tonnes/year of LNG targeting the US Clean Energy terminal near Pascagoula, Miss., in 2012. Associated and nonassociated gas will come from Blocks 15 (ExxonMobil); 17 (Total); 18 (BP); and 0 and 14 (Chevron Corp.). The partners will also develop previously discovered nonassociated gas fields on Blocks 1 and 2 to supplement the gas produced with oil. The plant will also process 125 MMcfd of gas for industrial projects.