Crude oil provides more than 70 per cent of the revenue of Nigeria’s government at all levels and more than 90 percent of its foreign exchange. At a time when oil prices appear to be stabilising due to cuts by producers over demand uncertainty, ensuring an optimal take of government revenue from its hydrocarbon resources remains imperative. To address perennial issues bordering on accountability of oil receipts, triggered by accountability, FEMI ADEKOYA writes on the troubles with crude transportation and how governance structures can be used to check malpractices.
With about 2,616 wells accounting for Nigeria’s daily oil production, the Department of Petroleum Resources (DPR), in2016, unveiled the National Production Monitoring System (NPMS), a web-based oil, and gas production accounting, and monitoring platform for proper book-keeping amid arguments that the country did not know the quantity of oil and gas is produced, resulting in discrepancies in receipts.
The industry regulator equally warned that no company will operate if they are not on the NPMS platform, adding that compliance with the submission of the Maximum Efficient Rate (MER) test will be enforced, as no operator is expected to produce from any well without conducting the test.
The idea was to ensure that no-issuance of export permits, technical allowable and other statutory approvals and permits was done without compliance with extant rules in the industry.
The imperatives of the NPMS scheme cannot be over-emphasized, especially when viewed against the backdrop of persistent calls for a more efficient, accurate and robust surveillance of the nation’s oil production and export capabilities.
The underlying strength of the NPMS is to further ensure DPR’s ability to accurately determine the exact revenue accruing to Nigeria from the oil and gas sector. A key benefit is that it also provides modern and reliable technology for fiscalization of crude.
Like every other year, the Nigerian National Petroleum Corporation (NNPC) last year, disclosed that the nation lost about $750 million or N230.2billion to oil theft in 2019, mostly due to pipeline vandalisation, necessitating the deployment of different measures to check the activity of vandals.
Indeed, the committee set up to investigate theft from the miles of pipelines that snake through the country’s swampy, oil-rich Delta region, said the theft will only grow if the government does not take special action to combat it.
In addition to a legal task force, with dedicated courts, prosecution teams and specially trained judges, it also said oil pipeline maintenance and ownership needed to be restructured.
“The governance structure of the pipeline(s) is such today that no one is held accountable…when these losses occur,” the committee, chaired by Edo state governor Godwin Obaseki, had said in its report.
During the period, the four primary pipelines lost 22.5 million barrels of oil in six months – roughly 6% of Nigeria’s nearly two million barrels per day (bpd).
Oil theft via pipeline vandalisation and badges has been the perennial practice until the recent allegation that oil major admitted to theft in the country.
Indeed, the declaration unsettled the Department of Petroleum Resources (DPR), which had continued to reiterate that Nigeria can account for every molecule of oil sold daily in the international market.
The DPR said it became imperative to clarify that what is being referred to as admission of theft as a process and regulatory issue arising from disputes over the shared facility.
Already, Shell Production Development Company, through its spokesman, Bamidele Odugbesan, dismissed the report that the company admitted to under-reporting crude export from its terminal.
According to him, the report is without foundation and the annual reports of the DPR support this.
“SPDC and Shell companies in Nigeria conduct their operations in accordance with applicable laws and industry best practices”, he added.
According to DPR Director, Sarki Auwalu, the misconception about oil production accountability is often a result of what he described as technical allowable.
He had exclusively explained to The Guardian that oil production is managed through what is called Maximum Efficient Rating (MER), adding that for every well, the regulator checks for the efficiency of that well, so that from there, technical allowable are obtained, out of which production quota is given to every operator.
“You cannot produce any oil or gas without technical allowable. So we have a basis of getting the number, we have the basis of getting the daily volume and production because we know the technical allowable as we know the volume a field will produce; so we tally it and we do that every six months. So, we know for the next six months the total technical allowable going forward.
“We need to test every well, set the allowable and when we set that allowable the way we produce what we do currently from the well, it goes to the station and from the flow station it goes to the terminal. We have 26 terminals where five out of the 26 are land terminals while the remaining are offshore terminals.
“We have the national production monitoring system and what this system does is that all these terminals are connected to the system, and we get information right from the control room for each and every terminal and as they get the volume entering the terminal, we are getting same and in addition to validating that, we put a remote access router whereby independent of the volume that goes into their tanks, we have that information being transmitted to us directly to validate the volumes we receive.
“We give the production volume to be produced, we account for the volume that goes into the terminal, and we allow for every molecule that will leave the terminal. So, to us, we have the right figure. But some agencies will say let us account from wellheads, and from wellheads, it is not crude oil, but water, gas and crude oil”, he explained.
Auwalu noted that the country cannot account for what it cannot sell, adding that “when we get that volume of liquid it is reservoir fluid and you have to treat it and remember each well after we give the technical allowable which is only DPR that gives the allowable, not any other organisation.
“So they have to depend on that figure and without that benchmark, you cannot monitor the well and when it produces, you monitor the well so that it will not collapse or shut-in on daily basis. When you bring that reservoir fluid, it will go to the flow station where you separate the materials such as water, gas and crude. You grind the crude and send it to the terminal for export.
“What we account for is the volume that gets into the terminal because that is where the money comes from and the gas is where we now put flare meter, the gas utilised within, the gas we flare and even the water in MPS we know the water we produce. We account for the water separately, we account for the gas and crude separately as well. Somebody that does not have access to these, I do not think it is possible for the person to get the correct figure and the transparency is that these figures are there and we put it on our website”.
Lessons from the ICT sector on co-location
Crude transportation strategy is apparent in the ICT sector in the form of co-location, considering that operators cannot independently own pipelines and entire oil infrastructure if they have to remain competitive.
In Nigeria, Hydrocarbon is currently extracted from 323 developed fields located in both onshore and offshore terrains. These fields, which either contain Crude Oil, Condensates or Natural Gas reservoirs, are connected to 265 production processing stations, after which the stabilised Oil and Gas are exported via 31 export terminals.
The onshore processing infrastructures are linked to 8 crude oil/condensates and NGLs export terminals through pipelines that span 5,284 km. Some of these delivery pipelines connected to the five onshore export terminals are utilised by both the asset operators and third-party oil producers, for transportation, storage and lifting of Crude Oil blends through export or delivery to domestic refineries.
With concerns about production volume reconciliation, a simple analogy of the telecoms sector where the NCC resolves similar disputes over co-location among network service providers arising from origination and termination of services comes to mind.
Co-location involves moving or placing things together and is used to mean the provision of space for a customer’s telecommunications equipment on the service provider’s premises.
In the internet world, for example, a website or an ISP could place its network routers on the premises of the company offering switching services with other ISPs while in the GSM/Telephony world, an operator could decide to share facilities/sites for cost savings reasons. Co-location is sometimes provided by a third-party company that specializes in such services.
The cost of sharing facilities and co-locating is reasonable compared to the cost of building one’s own infrastructure hence a faster return on investment and an opportunity to focus more on the core business of the companies which is providing telecoms services.
In order to meet the increased communications infrastructures sites rollout demand, statutory requirements for infrastructure sharing and harness economic advantages derivable from co-location and sharing telecoms infrastructure, operators explore the possibility of site infrastructure co-location with other telecom operators.
Since telecommunications infrastructure is capital intensive from a business point of view, it becomes more difficult for ICT, PTOs and GSM companies in Nigeria to operate profitably and making expansion plans towards meeting subscribers’ growth even more difficult without co-location.
For the oil and gas sector, however, the idea of co-location becomes evident in upstream operations where many activities take place as a result of joint venture partnerships.
As a result, the venture partners according to equity holding share whatever decision/penalty prescribed by the regulator in the process of a transaction or dispute resolution.
DPR as an enabler
By leveraging automation, knowledge sharing, transparency and efficiency, the DPR hopes to generate and analyse data that would further help the industry address critical concerns.
According to Auwalu, the petroleum resource intelligent service portal is a portal that seeks to provide information to stakeholders on key decisions and operations.
Similarly, he noted that the Nigerian Oil and Gas Alternative Dispute Resolution Centre in DPR is designed to address issues among partners in a way to avoid unnecessary litigations.
“The industry has grown over the years from exploration licences granted to several companies to have strong national aspirations. We have nine basins that are critical to the nation, both for oil and gas. We have the technical capacity to produce 2.79mmb/d. About 200% of proven reserves produced in Nigeria in 1970 replaced by new reserves. The oil and gas sector remains critical in driving the economy.
“DPR’s licence remains an enabler of investments. We are also trying to ensure that standards are being followed through conformity assessment and technology adaptation”, he added.
He then urged operators to take advantage of the National Data Repository (NDR) to access industry data for their operations and investments.
