Encouraging though these developments are for Africa’s smaller economies, these nascent industries are dwarfed by the oil and gas sector of Nigeria. After more than 50 years of production, Nigeria – the tenth largest oil producer in the world – still has proven reserves of 37bn barrels, three times that of its nearest rival Angola. Its natural gas reserves are estimated to be in the region of 190tn cubic feet. The country produces up to 2.5m barrels per day of the sweet, light crude that fetches the highest prices on the world market.

But despite this untapped potential, Nigeria’s active international oil companies (IOCs) have waited five years for a licensing round. Investment in new infrastructure and growth in output have stagnated while the Federal Government and state administrations debate what promises to be one of the boldest pieces of legislation in the sector’s history: the Petroleum Industry Bill (PIB), drafted by the Petroleum Minister Diezani Alison-Madueke.

The PIB has several commendable aims. It seeks to introduce a new tax and royalty regime to increase the government’s take and redistribute more of the spoils to ordinary Nigerians. It aims to rationalise what is a notoriously cumbersome legal framework and to clarify the fiscal terms on which a foreign player can acquire concessions from and partner with the Nigerian National Petroleum Corporation (NNPC), the state-owned corporation that controls large stakes in the country’s major operations. It contains provisions for putting an expanded share of production into the hands of domestic firms. And it aims to improve the credibility of the NNPC, making it a commercially viable, profit-driven entity with greater independence from the government.

The history of Nigeria’s oil industry dates back to the colonial era. Even before the official consolidation in 1914 of the territory’s various states and ethnic groups, the Nigerian Bitumen Company and British Colonial Petroleum were exploring the Okitipupa region adjoining the Niger Delta. In 1938 the colonial administration granted the state-sponsored Shell (then Shell D’Arcy) complete monopoly over the exploration of all minerals and petroleum throughout the colony. Shell’s hegemony lasted until the late 1950s when Mobil, Texaco and Gulf began to establish themselves. In 1956 Shell made the first successful drill at Oloibiri in the Eastern Niger Delta. Nigeria’s first oil shipment followed two years later.

Exploration and production by foreign firms continued to expand after independence in 1960, and by the end of the decade total production had reached two million barrels per day. 1970 saw the first of the oil price hikes of the seventies, and in 1971 Nigeria joined the Organisation of Petroleum Exporting Countries (OPEC). In 1977 the NNPC was established to oversee the development of the growing sector. After a slump in production figures during the eighties, the Joint Venture Operating Agreement (JOA) came into force in 1991, making clear provisions for the respective stakes of investing companies and the government. By 2004 several large majors including Royal Dutch Shell, Chevron, Exxon-Mobil, ENI, ConocoPhillips and Total were firmly established, and daily production hit a record level of 2.5m barrels.

Oil now accounts for 40 percent of Nigeria’s GDP and yet the industry has faced persistent criticism for not distributing the gains more widely. A sense that ordinary people in the oil-producing regions have been left behind has led to periods of unrest, and for decades successive governments have come under attack for squandering the wealth at their disposal.

Compounding the issue, a chronic overreliance on upstream industry has hindered the development of domestic refining capacity, with the result that Nigeria is forced to import much of its fuel. Consumers have grown accustomed to being protected from this fundamental imbalance by generous state subsidies. President Goodluck Jonathan’s recent attempt to lift them was met with fierce opposition and had to be partially reversed.

The PIB offers hope of a solution to many of these problems, and while it has gone through several iterations there are still many in the industry who remain upbeat about its potential as the catalyst for a new era of investment. Fresh capital is surely needed. Uncertainty about the tax regime and regulatory environment is blocking billions of dollars’ worth of new exploration projects; the number of new wells being drilled each year has been steadily dwindling since 2005. The US, Nigeria’s second largest trading partner after India, is switching to its own supply of cheap shale oil.

More encouraging signs are appearing closer to home. Indigenous production accounts for a mere five percent of Nigeria’s total output, but dynamic firms such as the Lagos-based Seplat and the pan-African Oando are acquiring a growing number of concessions and are buying assets from the large IOCs. Technology is steadily improving, promising greater access to large offshore reserves.

Domestic operations are also on the rise in the downstream sector, where healthy competition is transforming the business landscape. Earlier this month, Dangote announced plans to invest $8bn in a new refinery with a capacity of 400,000 barrels per day. If other refining projects go ahead as planned, experts predict that Nigeria’s refining capacity could top 800,000 barrels per day by 2017, meaning an end to the fiscal conundrum of expensive imports and an economy based on extractive industry.

But for now, the vast potential of Nigeria’s fossil fuel reserves remains unrealised. The next licensing round, initially scheduled by Alison-Madueke for the first quarter of this year, has been postponed while her legislation is debated. Until it is passed, investors will simply watch and wait

New York’s main contract, light sweet crude for delivery in March gained 15 cents to USD 96.77 a barrel and Brent North Sea crude for March delivery increased 19 cents to USD 116.92.

“Markets are looking forward to the European Central Bank meetings and the release of Chinese trade data… for some directional indications,” said Sanjeev Gupta, head of Asia-Pacific Oil & Gas practice at Ernst & Young.

ECB policymakers are expected to decide on keeping interest rates unchanged during their meeting later Thursday despite worries about slow growth and the strengthening euro.

Investors are choosing “to stay on the sidelines ahead of a key European Central Bank policy meeting… where the spotlight will be on whether the recent strength in euro is sustainable for the weaker economies in the eurozone”, Phillip Futures said in a market commentary.

A stronger euro is supportive of oil prices because it makes the dollar-priced commodity cheaper.

A weaker euro makes oil more expensive for holders of the currency and is likely to dent demand.

Other analysts said investors will also be on the lookout for trade and inflation data from China due to be released Friday.

The closely-watched figures are the latest in a string of data expected to point to a recovery in the world’s second biggest economy.

China is the world’s biggest energy consumer and a strong economy bodes well for demand and prices

New York’s main contract, light sweet crude crude for December delivery, was up 30 cents to USD 86.37 a barrel, and Brent North Sea crude for December jumped eight cents to USD 109.84.

Traders were monitoring developments in oil-producing Libya after ousted former leader Gaddafi was killed; with a focus on how fast the country will restore production that was lost during the rebellion.

Libya was producing about 1.4 million barrels per day of mostly high-value light sweet crude before the uprising at the start of the year.

Around 85 per cent of Libyan output was exported to Europe, and the break in supply contributed to a surge in Brent.

However, Phillip Futures said in a report: “While North Sea production problems have been supportive to oil prices and Brent in particular, traders and analysts expect the return of Libyan oil exports to continue, unaffected by the death of Libya’s ousted leader Muammar Gaddafi.”

Oil cartel OPEC sees member Libya restoring production to one million barrels per day within six months, then attaining pre-conflict levels by the end of 2012.

Traders were also bracing for the outcome of European Union summits on Sunday and Wednesday.

EU leaders decided to hold a second summit on Wednesday as France and Germany continue to bicker over the best way to boost a support fund for troubled economies, hurting chances of an agreement on Sunday.

Analysts said investors were also monitoring a storm gathering in the Gulf of Mexico that threatens to disrupt oil supply in the southern United States.

New York’s main contract, light sweet crude for delivery in October, lost 18 cents to USD 88.75 per barrel.

Brent North Sea crude for October delivery dipped 17 cents to USD 114.12.

“The US jobs data is coming out tonight, and there is a likelihood that prices will stay in a tight range,” said Ker Chung Yang, a Singapore-based commodity analyst at Phillip Futures.

Markets remained jittery before the release of US nonfarm payrolls data later Friday, which will indicate whether the labour market in the world’s biggest economy is showing any signs of improvement.

Meanwhile, oil majors including BP, ExxonMobil and Royal Dutch Shell have started evacuating workers from their rigs in the Gulf of Mexico ahead of a storm that forecasters say has a 70 per cent chance of becoming a tropical cyclone.

OPEC said in its annual statistical bulletin that Venezuela’s proven crude oil reserves reached 296.5 billion barrels in 2010, up 40.4 per cent year-on-year and higher than Saudi Arabia’s 264.5 billion barrels.

However, doubts have been expressed over whether all of Venezuela’s heavy oil discoveries are actually viable economically.

It is also doubtful as to how economic Venezuelan reserves additions could be, as most come from the heavy and extra-heavy oil in the Orinoco Belt, which is difficult and expensive to extract.

Iraq and Iran’s proven reserves were also upgraded — by 24.4 per cent to 143.1 billion barrels and by 10.3 per cent to 151.2 billion barrels, respectively — roughly in line with the countries’ earlier disclosures.

The demand for OPEC crude in 2011 is estimated at 30.0 million barrels per day (mb/d), around 0.1 mb/d higher than in the previous report. This indicates a rise of 0.4 mb/d over the previous year.

In 2012, the initial forecasts for world oil demand, non-OPEC supply and OPEC NGLs indicate demand of 30.3 mb/d of OPEC crude, an increase of 0.3 mb/d over the current year.

However, these forecasts could be impacted by unforeseen events.

Venezuela, Iran and Iraq were part of a group that refused to hike output at the 8th June OPEC meeting.

Meanwhile, in its monthly oil report, OPEC said world oil demand is forecast to grow by 1.36 mb/d in 2011, slightly lower than it had earlier estimated, as the unsteady global economy has added risks to the forecast.

“In 2012, global oil demand is expected to grow at a slightly lower 1.32 mb/d. The global economic recovery has been facing challenges across the OECD, adding to the uncertainties to next year’s forecast. US gasoline demand is expected to be back in its normal growing mode; however, it will remain a major factor affecting oil demand projections. The disruption in nuclear power generation in Japan could also increase oil consumption in the coming year.”

KOGAS, the world’s largest LNG importer and the nation’s sole provider of LNG, is expanding the TongYoung Terminal and PyeongTaek LNG Terminal II to meet the rapidly growing demand for natural gas in the country. The terminals will serve several functions, including the receiving, storing and regasification of LNG, and will deliver vaporized natural gas via high-pressure transmission mains to gas users.

HPS’s Overall Management and Automation System, which includes the award-winning Experion® Process Knowledge System and Unisim®, offers KOGAS a complete process control system, which allows them to implement the latest safety measures such as emergency and process shutdown, disaster prevention, plant information, and operator training. An integrated Experion system, as well as on-the-ground simulation training provided by Honeywell, ensures that the terminals operate with maximum security and performance.

“We needed a partner who could integrate the different aspects of our system to guarantee a smooth process, from supply to supply chain management,” said a plant engineering team leader at KOGAS. “We chose HPS because they offered complete and proven automation solutions – providing us peace of mind as well as ensuring both the safety and efficiency of our operations. HPS’ dedication has resulted in a successful track record with our existing LNG terminals which has cemented our confidence.”

“In recent years, global demand for natural gas has risen sharply. With the implementation of HPS’ solutions, KOGAS can optimize the performance, security, and cost effectiveness of its terminals, and in doing so, achieve a significant competitive advantage in the expanding global LNG market,” said Kim HyounJoong, Lifecycle Service Leader, Honeywell Korea. “Our team is always ready to support KOGAS and ensure that the country’s natural gas needs are met efficiently and safely.”

India, which is 75 per cent import dependent to meet its crude oil needs, is building under-ground storages at Visakhapatnam in Andhra Pradesh and at Mangalore and Padur in Karnataka to store about 5.33 million tons of crude oil.

This is enough to meet nation’s oil requirement of 13-14 days.

The cost of storage at Visakhapatnam has been revised to Rs 1,038 crore from Rs 671.83 crore primarily due to increase in cavern capacity from 1 million tons to 1.33 million tons, an official statement issued after a meeting of the Cabinet Committee on Economic Affairs (CCEA), which approved the revised cost estimates, said.

“The enhanced storage capacity at Visakhapatnam will enable larger strategic storage of crude oil at a lower cost due to cost sharing while providing operating flexibility and cost savings,” it said.

State-owned Hindustan Petroleum Corp Ltd (HPCL) will take 0.3 million tons capacity at the Visakhapatnam stockpiles by paying at a proportionate cost of Rs 230 crore.

“The CCEA has approved the enhancement of cavern capacity, manner of utilisation and revised cost estimates of Strategic Crude Oil Storage cavern at Visakhapatnam,” the statement said.

The Visakhapatnam storage, being built by India Strategic Petroleum Reserves Ltd (ISPRL), is being targeted for completion by year end.

Huge underground cavities, almost ten storey tall and approximately 3.3 km long are to be built in Visakhapatnam.

A similar facility in Mangalore will have a capacity of 1.55 million tons and would be mechanically completed by November 2012. A 2.5 million tons storage at Padur, near Mangalore, would be completed by December 2012.

With this, India will join nations like the US, Japan and China which have strategic reserves.

These nations use the stockpiles not only as insurance against supply disruptions but also to buy and store oil when prices are low and release them to refiners when there is a spike in global rates.

However, the storage India is building is very small compared to the 90-day strategic stockpile in the US.

New Delhi was considering to raise the storage capacity to 15 million tons to cover for 45 days requirement but no decision has been taken as yet.

ISPRL is a wholly-owned subsidiary of Oil Industry Development Board (OIDB) – a government body that lends money to energy projects.

The cost of building the strategic stockpile is being provided by OIDB as equity to ISPRL.

The cost estimate does not include the cost of purchasing 5.3 million tons of crude oil.

“The crude procurement and how it will be managed will be the responsibility of the government,” an ISPRL official said.

Like the US, the government may buy crude oil when rates are low for stockpiling.

It may release it to refiners during times of spike in global crude rates like those witnessed in July 2008 when prices touched an all-time high of USD 147.

New York’s main contract, West Texas Intermediate (WTI) light sweet crude for July delivery, rose 48 cents to USD 95.29 a barrel.

Brent North Sea crude for delivery in August gained 99 cents to USD 114.00 on its first trading day.

Bargain-hunting traders were buying up crude after its overnight dip, said Victor Shum, a Singapore-based analyst at Purvin and Gertz international energy consultancy.

“Traders view this as a buying opportunity after oil prices tumbled,” he told.

WTI crude prices had dived more than USD 4.50 in late US trade on Wednesday, sinking below USD 95 as investors fretted about fresh signs of weakness in the US economy and tensions in Greece sent the dollar jumping.

Data from the US released Wednesday showed manufacturing conditions in New York falling into negative territory for the first time since November 2010 as inflation rates soared to their highest level in more than two-and-a-half years.

Markets had also been rattled by the failure of eurozone finance ministers to reach an accord in Brussels Tuesday on a second bailout package aimed at averting a Greek debt default, sending the dollar sharply higher against the euro.