Marginal opportunities in tough times.
Companies can reduce exploration risk by acquiring known marginal fields, attendees said at a recent conference
By Ed Reed
The question of marginal fields and how to develop them lies at the heart of African development and production, particularly for smaller companies. While explorers may hope to strike it lucky with wildcat exploration, such a strategy relies on timing, opportunity – and above all, luck. Exploiting a field that is already known, but not developed for whatever reason, allows companies to move far quicker into starting up production, which opens up a range of doors, not least providing some certainty for investors and financiers. Defining a marginal field depends on location as much as anything – known resources around Africa have not been developed for a range of circumstances, not least because of perceptions of risk. “If you're paying your bills, this is the formula for success,” Africa Fortesa’s chairman, Rogers Beall, told the Africa Small and Marginal Oil Fields Conference, organised by Energy & Corporate Africa, last week in London.
“If you're paying your bills, this is the formula for success”
“They’re looking for impact reserves, they need to be looking at marginal reserves,” Beall said. “These are excellent companies, with excellent management and excellent technology, doing the best they can do, but they’re following the wrong plan – they’re not looking at marginal fields.” Other companies that have struggled are those working in countries where the government has failed to provide an economic regime sufficient to ensure production. Orca Exploration has 283 billion cubic feet (8 billion cubic metres) of gas in Tanzania “but the government is making the company sell that gas very cheaply in order to fuel the government power plant. They’re selling it at 25% of its value, so the government thinks it’s saving 75% [whereas] it’s actually stopping the development of the country.” Beall also noted the example of Harvest Natural Resources in Venezuela, which has been unable to make headway with its reserves because of punitive government terms. Companies that have managed to make progress with small finds, as gauged by share prices, include Aminex in Tanzania, San Leon Energy in Poland, Circle Oil in Morocco and Victoria Oil & Gas in Cameroon, Beall said. “Marginal fields are the answer.” Nigeria Perhaps the best known marginal fields of the continent, and where the most work by indigenous operators has been done, are the resources in Nigeria. The country is fairly well explored, given its history with the majors.
These large companies may have opted not to develop resources that fall below their commerciality threshold, but these smaller fields can still be extremely material for nimbler operators. For minnows, particularly indigenous ones, these can offer intriguing opportunities. The Nigerian government has made a concerted effort to drive its companies into picking up local assets, through a combination of tax breaks and by making it clear to sellers that indigenous companies must be given priority. A statement from the office of Nigerian President Muhammadu Buhari last week also stated a policy of supporting indigenous producers, both by the government and through the Nigerian 8National Petroleum Corp. (NNPC).
He picked out two factors as playing a key role for small companies: small fields and conditions conducive to their development. The industry has overlooked the opportunities offered by small fields, the Africa Fortesa executive continued, noting the reluctance of exploration managers for such work. Beall cited a number of examples of companies that had pursued high-risk, high-impact exploration and been unable to sustain share price value as a result. Chariot Oil & Gas and Petromaroc have struggled in this regard, he said, noting the large amounts of shareholder cash that had gone into these companies, to little outcome.
During the oil price boom, the range of companies working in this space proliferated, backed up by easy credit from local banks. Now, though, the squeeze is on and warnings have come from the Central Bank of Nigeria (CBN) that the financial sector is over-exposed. Consolidation seems likely, therefore, which should bring operating costs down and make Nigerian companies more competitive. The majors dominate Nigerian production, All Grace Energy’s chairman, Anthony Adegbulugbe, noted, and small companies are reliant on their infrastructure in order to move production to market. “There are 300 marginal fields in Nigeria”, Adegbulugbe said, that will remain undeveloped unless small companies can meet this challenge. “It is challenging to put marginal fields on stream at times of low oil prices,” he told the conference, noting the importance of co-operation among small companies in order to reduce costs, for instance by working collaboratively and through pooling human resources. There are 12 marginal fields producing in Nigeria, according to the Department of Petroleum Resources (DPR), with output of 62,667 barrels per day, ranging from 2,000 bpd to 35,000 bpd. The DPR’s assistant director of upstream operations, Emmanuel Bekee, told the conference attendees that there were a range of opportunities linked to the marginal fields, for instance in the refining sector, in addition to providing gas for local consumption. While Nigeria has taken steps to improve access to marginal fields for its companies, challenges remain.
Green Energy International’s Bunu Alaibe noted the difficulty posed by bureaucracy, saying that the “gestation period [to acquire a field] was six to 10 years”, with a range of interests being involved, including the government, partners, legacy interests and local communities. Companies, Alaibe said, must “work with communities to assist them so they become stakeholders, rather than just landlords who collect rent”. Other problems that may hamper operations include the higher cost of services required in order to conform to local content rules, a participant at the event noted. Stepping out While there is substantial appeal in lining up production from known shallow-water and onshore fields, there is also the potential for bolder steps, participants said. Cairn Energy drilled two wells offshore Senegal in 2014, in around 1,000 metres of water, finding oil at both of them. The discoveries were on trend with Africa Fortesa’s onshore holdings, Africa Fortesa’s Beall said, also noting Kosmos Energy’s find offshore Mauritania. “We can access all the rocks they’re drilling, [while] an offshore well costs US$100 million, we can drill those [targets] with a land rig, at a cost of around US$8 million. Marginal production can offset other costs, such as dry hole costs,” the executive said, while also providing insight into hydrocarbon systems. Africa Fortesa is working onshore in Senegal, with 10 wells producing gas as of mid-2013. While Africa Fortesa may be able to access plays similar to those found by Cairn and Kosmos at a lower cost, theremay also be a place to re-evaluate deepwater fields on a new basis of commerciality.
Given the rising price of services, finds in the deepwater need to be large – perhaps more than 200 million barrels in order to be developed economically, or so conventional wisdom suggests. Such an assessment suggests as many as 70% of discoveries in the offshore are too small for development, Atlantis Offshore’s CEO, Keith Millheim, even where exploration risk is effectively zero. There are also other complications that may discourage companies, such as if the oil is heavy. Millheim noted four discoveries in West Africa – Nigeria’s Chota field, Benin’s Kaba, Ghana’s Odum and Obo in the Nigeria-Sao Tome and Principe Joint Development Zone (JDZ) – that appear to be too small for development. These finds, though, should not be written off, he said. In order to develop these assets, speed is of the essence. Rather than taking four to 10 years to start up, Millheim said, the technology exists to bring them into production within 12 to 24 months, through the use of a floating production unit (FPU) and shuttle tankers. “What we invented was a system to get everything off the sea floor and get direct access to the existing well. This technology provides the ability to go into an existing well, with a subsea tree, in order to get early production. Nothing is on the seafloor apart from the anchors and the shut-off pipes, everything is retrievable and you don’t need heavy lift equipment,” Millheim said, with this technology having production capacity of 10,000-25,000 bpd. “The economics work at US$40 per barrel, the technology is within reach and small companies can do this. There is a perception of cost, <it’s not the actuality.”