Uncertainty remains over deepwater projects as Nigeria reviews PSCs

September 09, 2016 | Government & Regulations, Nigeria

Abuja, Nigeria |  – The ongoing review of the existing Production Sharing Contracts (PSC) by the Nigerian National Petroleum Corporation (NNPC) may have added to the uncertainty over proposed deepwater oil projects in the country amid the global drop in crude prices, Nigerian newspaper, The Punch reports.

Globally, many oil and gas companies have been forced to slash capital spending and suspend some projects as a result of the low oil price environment since 2014.

International Oil Companies including Shell, ExxonMobil and Chevron had, prior to the steep fall in crude oil prices, planned to develop deepwater projects in Nigeria, with Final Investment Decision yet to be taken on many of them.

The nation’s oil and gas production structure is majorly split between joint ventures onshore and in shallow water with foreign and local companies and PSC in deepwater offshore, to which many IOCs have shifted their focus in recent years.

The Energy Information Administration, the statistical arm of the US Energy Department, noted that several planned deepwater projects in Nigeria had been repeatedly pushed back because of regulatory uncertainty.

It said some draft versions of the Petroleum Industry Bill, which suffered setback in two consecutive legislative tenures, had prompted questions about the commercial viability of deepwater projects under the proposed changes to fiscal terms.

The EIA said, “Deepwater projects have typically included more favourable fiscal terms than onshore/shallow water projects, but the PIB, if passed into law, is expected to increase the government’s share of production revenue coming from deepwater projects.

“As a result of the uncertainty, IOCs have sanctioned (reached a final investment decision) on only one of eight planned deepwater oil projects.”

The Head of Energy Research, Ecobank Capital, Mr. Dolapo Oni, in a telephone interview with our correspondent, said, “I get where Nigeria is coming from. We need to get more revenue from oil. It depends on how they go about it. If they do it in such a way that the higher payments only kick in when there are higher prices, then it is possible.

“But if we do it in such a way as what is contained in the current PIB, where we just slam a flat rate across all fields, it may not work. If they include some sorts of flexibility in the review, I think it might work. We will get our higher revenue, but not when we want it. But at least, we know that we are going to get it when there are higher oil prices. But then again, those projects will still be able to carry out FID and go ahead.”

According to Oni, the IOCs may push the FID again if they realise that the prices are still not comfortable because some of those fields require above $50 oil for them to break even.

He said, “So, increasing the government’s share may actually push the break-even prices higher. Once the break-even prices go above $60, then those projects may never happen until oil prices recover to $100 or $80 at least.”

According to the EIA, both sanctioned and unsanctioned deepwater oil projects in the country have the potential to bring online almost 1.1 million barrels per day of new production over the next five or more years, however, only 200,000 bpd has reached the critical development milestone.

Projects without FID are Shell’s Bonga Southwest and Aparo (225,000bpd) and Bonga North (100,000bpd), Eni’s Zabazaba-Etan (120,000bpd), Chevron’s Nsiko (100,000bpd) and ExxonMobil’s Bosi (140,000bpd), Satellite Field Development Phase 2 (80,000bpd) and Uge (110,000).

“If global crude oil prices remain low, this will also exacerbate project delays in Nigeria,” the EIA said.

The NNPC, in its latest monthly report, said it was currently reviewing existing PSCs “to negotiate more favourable terms and improve the revenue base to the Federation”.

The EIA noted that the Federal Government took measures to attract investment in deepwater acreage in the 1990s to boost production capacity and to diversify the location of the country’s oil fields.

It said to encourage investments in deepwater areas, which involve higher capital and operating costs, the government offered PSCs in which IOCs received a greater share of revenue as the water depth increased.

The 125,000-bpd Usan deepwater field was the last major oil field to start production in Nigeria, which was in February 2012. Since then, there have been smaller start-ups that are extensions of Nigeria’s Bonga and Erha deepwater fields.

The 40,000-bpd Bonga North West field came online in August 2014, and the Bonga Phase 3 project started production in September 2015, which will eventually add 50,000 bpd, while the Erha North Phase 2 project came online in October 2015 and will eventually add 65,000 bpd.

The Minister of State for Petroleum Resources, Dr. Ibe Kachikwu, had in February hinted that the Federal Government was looking to review the commercial terms of deepwater PSCs in a bid to increase its share of revenue from the PSC production.

Kachikwu said the government was getting low revenues from deepwater PSC production due to its inability to effect review of the commercial terms since the commencement of production from Bonga Oil field in 2005 when oil price exceeded the $20 per barrel review threshold.

Highlighting the plan for the Nigerian oil and gas industry for the next three years, Kachikwu stated that there would be “adjusted government take in large deep offshore oil fields in line with the provisions of the Deep Offshore and Inland Basin Act.”

He added that the ambiguities and current impasse between PSC contractors and government in the interpretation of certain clauses of the Act would be addressed.

Some of the world’s largest energy companies are saddled with their highest debt levels ever as they struggle with low crude prices, raising worries about their ability to pay dividends and find new barrels, the Wall Street Journal reported last month.

Exxon Mobil Corporation, Royal Dutch Shell Plc, BP Plc and Chevron hold a combined net debt of $184bn – more than double their debt levels in 2014, when oil prices began a steep descent that eventually bottomed out at $27 a barrel earlier this year.

Executives at BP, Shell, Exxon and Chevron have assured investors that they will generate enough cash in 2017 to pay for new investments and dividends, but some shareholders are skeptical. In the first half of 2016, the companies fell short of that goal by $40 billion, according to a Wall Street Journal analysis of their numbers.

The debt is piling up despite cuts of billions of dollars on new projects and current operations. Repaying the loans could weigh the companies down for years, crimping their ability to make investments elsewhere and keep pumping ever more oil and gas.