Small local companies are nimble and flexible and can cut costs quickly.


In Nigeria, a push for earlier production

May 11, 2021

Ahonsi Unuigbe, CEO of Petralon Energy, talks to The Energy Year about challenges small local E&P players face, advice for new marginal field operators and the company’s plans for its asset base. Petralon Energy is a local E&P company that acquired the Dawes Island marginal offshore field in Nigeria’s latest bidding round.

How do the strategies employed by major IOCs and small local E&P players differ?
Indigenous marginal field producers have a lower-cost structure than IOCs, which gives them a competitive edge in costs. However, these companies do not have the capital, technical sophistication and financial capacity that major IOCs typically have; most indigenous marginal field producers are initially self- or privately funded.
Small local players must understand that the upstream sector is massively capital intensive. To drill a well you can easily spend USD 20 million-30 million, depending on the terrain. Expenses can easily increase by an additional USD 1 million a week for a project suffering challenges, with budgets consequently overshot by USD 10 million-30 million.
In addition to that, only about half of the financing required comes, or can typically be raised from, Nigerian banks. The rest comes from foreign investors who rightly insist on financial transparency, legal and regulatory compliance, lack of political exposure, strict reporting standards and adherence to environmental, health and safety principles. One must therefore be flexible and willing to give and take.
In addition to this, if the asset is not already producing, you are taking on an equity-type risk as a producer/operator. This requires at least 50% equity funding for any project, which equates to capital raising from investors, and this is not always a walk in the park.
That said, at an average crude price of USD 60-70 per barrel with a recoverable reserve pool of up to 100 million barrels, you can attain revenues of USD 6 billion-7 billion over the life of the asset. In this scenario, it is better to have a piece of the pie.
Indigenous companies rely on personal access to capital, which helps to cultivate a conservative attitude to expenditures. These companies thus tend to have a low-cost structure from the inception of their operations. Although this sounds like a disadvantage, it is always a blessing when oil prices dip as they seem to inevitably do. For instance, the oil price has occasionally traded lower than USD 40 per barrel in the last five years, and in such environments, you need to closely watch your costs and think twice about spending. Small local companies are nimble and flexible and can cut costs quickly.
Looking at the challenges experienced by indigenous players and the loss of revenues to the government due to delays in attaining first oil/oil production, I hope we learn from the mistakes made in the previous bidding round and start driving real investment into these fields to make oil flow sooner. DPR [Department of Petroleum Resources] has stipulated a maximum of five years to hit first oil, a departure from the previous rounds where some fields did not get to production even 10-15 years after being awarded. This is a positive sign and it will push the whole industry to earlier production and revenue.
As an indigenous company, our philosophy is based on keeping costs low and profits high. We recently completed a capital raise for the marginal field bidding process at an excess of USD 20 million in additional equity for the company. The purpose is the acquisition of assets, including signature bonuses. We did this on our own, while keeping our cost structure low as we are very self-sufficient.

How can smaller E&P firms cut costs when it comes to technology?
A lot of operators bet on industry leaders with brand names who have superior technology. However, these companies provide services with a hefty price tag. We have found some good indigenous service providers, as well as service providers that have similar technologies in the US, Europe and Angola; in Eastern Europe, for instance, they have similar technologies for a fraction of the cost. We find that one can engage these companies to operate in Nigeria on a milestone basis payment scheme as opposed to an upfront payment. Another alternative is payment of a percentage of revenue. These options are cost savers particularly in instances where there are delays. With these and cost in mind, Petralon’s strategy during the 2020 marginal fields bid round was to only bid on shallow-water assets where we can bring in the required expertise.


What advice would you give to integrated and downstream companies acquiring marginal fields?
Upstream is a completely different ball game that requires a different set of skills. In Nigeria, oil and gas is seen as one space, but in reality upstream and downstream are two different worlds. While downstream players receive a shipment and realise returns within a 90-day period, upstream companies receive a licence, and proceed to expend millions of dollars over a period of two to five or more years before they earn a single dollar. The upstream oil and gas sector requires a different level of grit, determination and patience and a minimum two-year wait for revenue. One must also consider the peculiarities of upstream operations such as drilling and operating fields where the targeted resources are thousands of feet deep, which has its attendant risks.
Downstream and integrated players should recognise that to succeed in developing an oilfield, one must either have experience or gather the know-how. This can be done in two ways: organic growth or acquisition. You can hire upstream experts from reputable and experienced upstream companies (both international and local) into your company, give them equity and devolve powers to them to develop your skillsets or you can partner with another company for complementary skills.

What challenges have you faced in setting up your first marginal field?
The Dawes Island marginal field is our current asset and a true pilot case for us. Out of 24 fields awarded in the last bidding round by President Obasanjo’s administration in 2003, only about seven or eight of those fields achieved oil production in spite of the fact that many fields could get to production with investments of only USD 20 million. We started Petralon to show that we could rapidly deploy capital and take assets to production.
Dawes Island was a test case to get a track record for subsequent marginal field bidding rounds, farm-in opportunities and IOC divestments. One must first prove oneself to the industry, capital providers and regulators. In this particular asset, we saw a potential of over 14 million barrels of reserves and a well drilled by Chevron in 1979. In 18 months, we tested the well’s flow rate, which beat our best expectations operationally but did not proceed as smoothly and as fast as we would have liked, for reasons other than production capacity.
A word of advice here: When you are farming into another entity and working with a group of people, there must be a degree of synergy. In our own case, we were not the operator at the time, but we provided funding. The diverse meetings and agreements between parties to reach common grounds/agreement, permits required from DPR [Department of Petroleum Resources], etc. are time-consuming processes; you need an equally sophisticated and committed counterparty to move at your fast pace.
One of the challenges current marginal fields face is the fact that strangers are forced to work together by the government when in reality firms have different business cultures, methods and motivations.
Again, other challenges unique to upstream oil and gas in Nigeria crop up the moment you deploy to certain locations, such as having to consider the local community.
I am optimistic about the current marginal field bid round. However, if a total of 40 out of the 57 fields do not hit production, it will be a loss for Nigeria. Every field belongs to the government, which collects revenue via royalties and profit tax and other levies like the NDDC levy and the Nigerian Content Development levy. It is in the government’s interest to make the process work and we hope they will. Nigeria has a habit of announcing lofty milestones that we do not achieve, like the 3-million-bopd benchmark set several years ago, Vision 2020, etc. We need to do things better and differently in the development of marginal fields and Petralon has learned some invaluable lessons along the way.

What was your reason for choosing these particular fields?
We had a clear strategy for the marginal field bidding round as we were familiar with the geology and region we wanted to be in. We narrowed our target to shallow-water fields for reasons of deployment of technological tools as I mentioned earlier, as well as an experiential knowledge that being at a shallow-water location will reduce disruption from communities and militancy. The region also has prolific geological potential and oil that is easy to evacuate.
Some of the fields in the region include the Ebok field in OML 67, which has produced over 80 million barrels; the Okono/Okpoho fields in OML 119, which at one point produced over 55,000 bopd; and of course the fields operated by Addax within OML 123 and 126. These fields are well known in terms of their geological capacity. As drilling takes a tremendous amount of effort, we prefer to drill in a place we know will be successful. We put in a bid for three fields in that region and were awarded one. Our plan is to partner with other companies that are awarded fields. To this end, we are in discussion with another entity that has one field in the same region. Our aim is to act as 100% funding partner in exchange for a majority equity stake in their company.
We do not believe that everyone the government awarded fields to has the financial capacity to fund these developments. With capital requirements ranging from USD 50 million to USD 150 million in two years, probably only a handful of indigenous companies can achieve this. Fortunately, Petralon has the financial capacity and ability to do so, with a financial commitment of USD 100 million in development funding.

What is Petralon Energy’s growth strategy?
Our assets will give us exponential growth. Once this materialises, we could consider listing. However, this would require having two or three prolific assets where gold-plated IOCs are present. This is part of our long-term strategy/goal.
Factoring in a three- to six-month delay, we aim to hit first oil in 18 months after the execution of farm-out agreements. We hope to have started well tests and produce about 7,500-12,000 bopd depending on the field.
Although our primary focus is Nigeria, if we hit production in two years and prove ourselves a success to our potential trading partners, we might be convinced to go to other potential markets in Africa, and we are already looking seriously at some countries, Angola in particular. However, our focus would only be on already producing assets or assets with near-term production. In 2016, we participated in a major bid in Gabon, where we put together a consortium and raised over USD 400 million in funding commitments.
Recently one of Shell’s divested assets went back up for sale, and we are currently participating in the sales process. Petralon is shortlisted and invited to a final stage of submitting binding offers, which will conclude by the end of June 2021. This asset has more than 150 million barrels of 2P reserves.

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