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Nigeria targets local upstream players with marginal field round

Reinvigorating production on acreage abandoned by the majors could be a tough task

Nigeria's drive to open up its marginal acreage to indigenous players is set to intensify, as the Department of Petroleum Resources (DPR) prepares to launch a fresh licensing round in 2018 incorporating up to 46 fields, largely in and around the Niger Delta. However, which fields will be on offer and the timing remain uncertain.

This would be the first formal marginal field round for more than a decade. One proposed in 2013 came to nothing and the oil-price crash of 2014 ruled out a revival in the intervening years.

Several lists of onshore and offshore fields that could be included are circulating in Nigeria in the absence of an official announcement, but it looks likely that some promising prospects will be on offer. Eni is poised to contribute acreage to a marginal field round for the first time, while several blocks relinquished by the majors that have been offered before could be back on the table.

These include Chevron's Ruta and Oloye, ExxonMobil's Nkuku and Utine, Shell's Egbolom and Obuzo and Total's Mfoniso and Asasa West fields, which between them are estimated to hold around 1.4bn barrels of oil in place. The DPR will be hoping that, even allowing for conservative estimates of recovery rates, some of these fields will lure investors, especially where existing infrastructure is functional—and where relations with local communities are positive, given some of this acreage is in the heart of the most militant areas of the Niger Delta region.

The government will be hoping that the shake-up in administration of the oil sector and some success in quelling unrest in the Niger Delta will pique greater interest in developing marginal assets than has been the case to date. Higher global oil prices would also be a spur, of course, though sizeable increases look unlikely in the short-term.

The round has been mooted for months, but has been delayed by restructuring within the oil sector and the less than ideal investment conditions. However, there are good reasons for the government to push ahead with it this year. The benefits to the local economy of a successful round are clear—locally-based operators are more likely to employ local contractors than the IOCs, boosting employment in the sector. And the oil revenues raised would be welcome too, of course, at a time when the country's foreign exchange reserves are depleted.

Stricter bidding rules

Only firms at least 51% owned by Nigerian citizens will be eligible to participate in the forthcoming round, with no single shareholder allowed to own more than 25% of the bidding company, according to the DPR.

In the past, such acreage has sometimes been acquired by investors with little or no experience—or interest—in developing oil assets, with a view to sitting on them and selling them for a profit later to someone who does. To avoid that happening this time around, firms will be required to demonstrate their upstream oil and gas experience, showing technical capability to evaluate and develop the assets. Companies with little or no track record or experience will need to show their ability to attract a credible technical partner.

Only five companies can be assigned to a field and successful pre-qualified companies may not bid for more than three fields at once.

Private equity firms could be attracted by the lower valuations on offer

At the final stage of the bidding process, a selection committee comprising DPR representatives and the current leaseholder on the block will draw up more specific submission requirements.

Pre-qualified applicants would be required to submit both a technical and commercial proposal at this stage. Interested investors will be required to pay $50,000 each for a Competent Persons Report (CPR). The CPR will require bidders to provide details of their shareholding structure, audited financial statements and financial resources to bid and pay for the oil acreages. They will also need to make smaller payments totalling around $1,400 to cover application and processing.

After the CPR stage, investors will also need to pay $15,000 for access to relevant data on the awarded blocks. At this stage of the process, they will be given information on the size of the fields, seismic surveys, and past appraisals conducted by the international oil companies.

The DPR will then commence technical evaluation of submitted bids and then award the marginal fields to the winners. A joint operating agreement will be negotiated prior to the signing of a farm-out agreement between the awardee and the current leaseholder. A signature bonus of $300,000 per field will then be payable.

Room for improvement

Tight conditions for bidders are designed to weed out the time wasters, but the performance of the last major set of marginal fields awarded, in 2003-04, remains a cause for concern. Out of the 30 fields awarded, only nine are currently producing. The remaining 21 fields have all failed to achieve first oil over the intervening 14 years due to a variety of setbacks.

These include delays with licensing of the operators by the DPR and other organisations with responsibility for the sector, challenges in community relations inherited from the previous IOC owners, and limitations to the technical capabilities of the new owners.

Although many of the companies involved include management figures, with some experience in the oil and gas industry, most were set up specifically for the acquisition. So they could not demonstrate the track record needed to convince foreign financiers or original equipment manufacturers and oilfield service companies to participate in their projects.

Some fields also had major technical issues, ranging from geological challenges to well pressure problems, while some required extensive investments in pumps and lifts to enable maximum hydrocarbon recovery. Moving the oil was another issue, with some fields having been relinquished by IOCs in the first place because they had no infrastructure to transport it.

Even when other factors were propitious, disputes among the owners also prevented developments from getting off the ground. These revolved around the division of capital expenditure, failures to guarantee that payments would keep coming through field development, and the selection of contractors, among other reasons.

An election looms

Fresh challenges also need to be overcome. The approach of the country's next general election, due in February 2019, means there is a risk that the best fields could yet end up being used as bargaining chips to garner political favours. Analysts say this has been the case in the past. The president is still able to use his discretionary power to award acreage under the Petroleum Act of 2004, though this power is likely to be removed when the new Petroleum Industry Governance Bill (PIGB) is passed by the National Assembly—something that has yet to happen.

$50,000—Cost of a Competent Persons Report

Meanwhile, Nigeria's crude oil production has also been capped by Opec at 1.8m b/d—a figure that excludes condensates, which add another 0.4m b/d. That limit could potentially cap the ability of new producers to ramp up output until the restriction is lifted. But judging by the sector's history, it may take years for new operators to put pre-development financing and technical arrangements in place, so the Opec cap may well be a thing of the past before any production from new developments comes onstream.

Despite efforts to raise the calibre of field operators, financing marginal field developments is likely to remain a challenge too. Local banks are already over-exposed to the oil and gas industry and have been cutting lending to the sector in general and marginal field operators in particular—and with some reason. The combination of lower oil prices and a higher cost of production have prevented some marginal field operators from servicing their debts or even meeting operating expenses on their fields.

Private equity potential

This could potentially provide room for private equity and venture capital firms to step into the breach, attracted by the lower valuations on offer at a time of restrained oil prices. There have already been a few deals across Africa, in places such as Gabon, Tanzania and Egypt, but none have materialised in Nigeria yet.

Although Nigeria presents a challenging business environment, it also offers good prospects for bringing assets into production quickly, if the finance is available. Given the high debt exposure of most oil and gas firms, they are ripe for approach by private equity firms that can inject new equity to improve both liquidity and their ability to repay their debts.

Prospective marginal field bidders are also likely to be proactively seeking out private equity partners to compensate for limited debt capital on offer from local banks.

One side effect of a greater reliance on private equity could be an improvement in corporate governance among local oil companies, given the higher levels of accountability and transparency typically demanded by private equity firms.

All this would be a shift from the norm in Nigeria, where local oil companies have traditionally refused to give up equity in their business or open up their books for deeper scrutiny.

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