The rising demand in the global oil market and the associated strong prices provide ample opportunity for Nigeria to revive programmes for speedy realization of key growth aspirations in the petroleum industry, writes SOPURUCHI ONWUKA.
The market opportunities come as the country struggles to retain its position in the comity of world’s key oil producers at a time prevailing global economic recovery propels demand surge and a new petroleum law dismantles fiscal obstacles to commercial investments in exploration and development in the sector.
With clear fiscal climate in the local operating environment and strong price incentives in the export market, Nigeria must rapidly muster $70 billion in order to launch a new wave of deepwater field development projects that would confer her with capacity to compete for not just greater quota at OPEC but also bigger space in the export market.
Since early 2021, the Organization of Petroleum Exporting Countries (OPEC) and its allies hosted in the OPEC+ coalition have been working to boost global oil production to about 103 million barrels per day in order to meet projected average demand of about 101 million barrels per day for 2021. Demand for 2022 is envisaged to overshoot all predictions as global economy rebounds with intense verve.
Analysts are talking about crude oil reaching $100 per barrel before the year ends, indicating strong demand and demystifying predictions that global movement for energy transition from fossil fuels would kill oil and gas demand.
OPEC+ had earlier this year announced incremental supply of 400,000 bpd until global stock reaches the pre-pandemic levels.
However, the group’s resolution to boost production has exposed huge production capacity gaps in some countries like Nigeria, Ecuador and Venezuela where fiscal disputes with commercial investors had stalled investments in capacity development across years, leading to yawning production gaps as producing fields enter natural decline stages.
In Nigeria where key deepwater production fields, including Bonga, Erha, Agbami, Akpo and Usan are posting production declines; it has become difficult to meet output quota increases at OPEC+, pulling the group’s cumulative production down from projected levels.
Industry professional leader and strategy analyst, Mr Austin Avuru, said Nigeria’s low investments in field development account for the prevailing dip in production volumes. He also emphasised the need for renewed investments in production capacity.
Apart from production declines, pipeline outages in the Niger Delta and associated production shut-ins contributed to inability of Nigeria to meet its rising production quota at OPEC. The country’s output to the market has plummeted below 1.3 million barrels per day (mbpd), according to OPEC.
Valuechain reports that OPEC quota does not account for condensate production, explaining the wide disparity between its production figures and those of the Nigerian National Petroleum Company (NNPC) and the Central Bank of Nigeria (CBN). Thus, Nigeria’s condensate production volume of about 600,000 barrels per day builds its local production data to about 1.9 mbd, still a far cry from pre-2010 production capacity of some 2.7 mbpd.
Government’s economic aspiration for the petroleum industry envisages a production rise to 4 mbpd and crude oil reserves growth to 40 billion barrels. Both targets have proved largely unrealized for over 10 years, leading to regular shifts in delivery deadlines.
In the 2022 budget, government has advanced production target of 1.88 mbpd at benchmark price of $57 per barrel. The budget estimates represent an increase from oil production of 1.47 mbpd for 2022 at a price $40 a barrel. In its Medium-Term Expenditure Framework (MTEF), government projected daily crude production of 2.23 mbpd for 2023 and 2.22 mbpd for 2022. The outlook projects an average of 1.93 mbpd over the past few years.
Besides the budget estimates, principal officials of the Ministry of Petroleum Resources have declared government’s intention to revive upstream industry programmes for realization of policy targets in the industry.
Minister of State for Petroleum Resources, Chief Timipre Silva, stated that Nigeria would leverage on the newly passed Petroleum Industry Act (PIA) to drive programmes that would deliver the production targets. He inferred strongly that the country would increase oil production by 310 percent to 4 mbpd, build its reserves from current 37 billion barrels to 40 billion barrels, and enhance commercialization of some 203 trillion cubic feet of gas reserves.
Valuechain’s survey of development projects in the country shows that it would take about five new deepwater fields of the size of Total operated Egina to drive a new aspiration by government to increase the nation’s crude oil output to 3 million barrels per day in the next 10 years, and project financing estimates sum in the range of $70 billion under the current oil prices.
Records at the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) show that some key deepwater oil discoveries have already been approved for development by the government, but investment decisions were caught up in fiscal and operational disputes with operating companies.
The last deepwater development project on the Egina field carried initial budget of $16 billion, even though the company declared that development programme was realized on schedule and below budget.
Industry advisory consultancy group, Rystad Energy, estimates that Nigeria still has about 1.3 billion barrels of booked reserves for development and production investments. The industry investment advisory which has been pumping out gloomy notices to players stated that Nigerian deepwater projects demand a minimum oil price range of between $42 per barrel and $59 per barrel to make commercial sense.
Other International Oil Companies (IOCs) that hold substantial deepwater assets in the country’s petroleum industry are yet to take final investment decisions (FIDs) for a total of seven development projects that could confer Nigeria with additional production capacity of 875,000 barrels of light crude oil per day.
With the seven deepwater development projects already sanctioned, FID on them would entail capital importation of over $70 billion or N33.6 trillion and enable Nigeria pump additional 1.925 million barrels of crude oil and condensate daily from the deepwater province when they come on stream.
However, not all the approved deepwater development projects are in front burner and all of them are at risk of being caught up in energy transition, as most of the operating companies have committed to portfolio diversification in line with their pledge to emission reduction.
Some of the planned development projects currently expected to launch off with the passage of the PIA include the $10 billion Bonga Southwest-Aparo deepwater field operated by Shell in collaboration with Stardeep, the deepwater business arm of Chevron in Nigeria.
Bonga Southwest and Aparo development was originally sanctioned by the Ministry of Petroleum Resources to come online using a stand-alone floater with nameplate production capacity of 225,000 barrels per day. Development budget of between $10-12 billion or N3.6 trillion captures subsea facilities; risers; floating production, storage and offloading (FPSO) vessel; and single point mooring buoy (SBM).
According to Rystad Energy, the 630 million barrels Bonga Southwest-Aparo would need a market price of $58.75 per barrel to reach an investment decision.
Next is the Shell operated Bonga North field located northwards of Bonga Main in OML 118 in the deep offshore. Nameplate production capacity is estimated at 100,000 barrels per day and development budget is estimated to hover around $10 billion or N3.6 trillion if a separate floater would be required.
However, the estimate is to fall by over 50 percent if production from the new development is to be tied back via subsea flowlines to the Bonga Main FPSO which started production in 2005 and is already hosting additional output from Bonga Northwest.
However, the production vessel might still have space for Bonga North production if there is significant production drop from the maturing Bonga Main.
Our checks show that the Shell operated Bonga FPSO has never reached its nameplate production capacity since commissioning, making it a ready output host from proximate field developments in the deepwater block.
“Bonga Main is currently being regarded as brownfield asset,” a source at NNPC said, adding that natural production decline after 14 years of production pressure could create space for production from Bonga North.
“As we speak, we are not certain when Bonga North will start production; but I know it will not come ahead of Bonga Southwest,” he hinted.
Another source of new oil for Nigeria is the Zabazaba-Etan field operated by Nigeria Agip Exploration (NAE), the deepwater business unit of Eni in Nigeria. NAE operates the field in partnership with Shell; and the partners have determined the development budget to be in the range of $12-15 billion or N4.32 trillion.
The 510 million barrel Zabazaba-Etan deepwater field development, when commissioned, comes with nameplate production capacity for 250,000 barrels of light sweet crude oil per day; and the budget would require an average market price of $45.95 per barrel to achieve final investment decision, per calculations by Rystad Energy.
Also, Total which is optimizing production infrastructure at operated oil mining lease (OML) 130 deep offshore Niger Delta is working to develop the Porewei field in the oil block where bigger fields including Egina and Akpo are currently producing at full capacity.
The Porewei field development which is designed as quick win project that would tie-back subsea wellheads to any of the proximate FPSO vessels in the block is largely seen as an optimization project that would cut development cost by half. However, over $5 billion or N1.8 trillion is estimated for the project.
And despite the cost advantage of not needing separate floater to come online, development of the Porewei deepwater field with a reserve profile of 145 million barrels still needs market price average of $43.30 per barrel to make commercial sense, according to Rystad.
ExxonMobil is totally silent on FID for three deepwater development programmes with a combined capacity for producing 330,000 barrels per day.
The company which operates exclusively offshore assets in Nigeria holds cards for development
of Uge in OML 145, Bosi in OML 133 and a group of smaller satellite fields offshore Nigeria. All the development programmes have no visible budgets and project details, even though approvals have been secured from government regulators in the industry.
The Bosi field development holds prospect for nameplate production of 140,000 barrels per day when the FID is reached. Budget might hover around $10 billion or N3.6 trillion, given the possibility that an FPSO might be needed.
With the satellite fields which aggregate production from fields proximate to main production hubs, ExxonMobil plans to muster as much as additional 80,000 barrels per day. Budget is uncertain until full development details are worked out.
The American supermajor also intends to add 110,000 barrels per day from deepwater Uge field,
using shared floater with a third party producer in the marine vicinity located 113 kilometres offshore in water depths of between 800 and 2,000 metres.
Project budget is placed at $10 billion or N3.6 trillion according to industry deepwater cost templates. However, shared FPSO means that cost sharing will also beat down the figures for parties and government, as well as shore up commercial returns for stakeholders.
Lastly, Nigeria expects additional 100,000 barrels per day from the Nsiko field which was discovered in 2003 and is operated by Chevron’s local deepwater affiliate, Stardeep, which is yet to declare FID on the field.
Chevron and ExxonMobil are partners in the Uge field in OML 145, and the two American companies are already in discussion with other partners to unitize production with shared FPSO for both Nsiko and Uge. The arrangement also comes with cost sharing and lower budget for both development projects.
With the sanctioned projects yet to achieve FID and launch into project stages, the envisaged domestic economic stimulus expected from the projects and the associated local content quotient of the full investment values now dim the country’s economic outlook and worsen acute shortage of foreign exchange revenue.
Fiscal and operating issues that held down FID on the development projects border on the preservation of sanctity of existing contracts and encouragement of growth as the industry enters into a new regulatory regime.
To dismantle the obstacles, government and major multinational investors in the country reached novation and Head of Terms agreements to revive work programmes on operated assets, especially in the deepwater.
The resolutions, Valuechain reports, form part of the Petroleum Industry Act which would now govern commercial operations of the investors who hold oil and gas exploration and production licenses in the nation’s onshore, shallow water and deep offshore terrains.
With the new law accepted by all commercial investors in the upstream petroleum play, fresh waves of investments in exploration, development and production operations would now offer new patronage to hundreds of indigenous oilfield service companies that form the engines of Nigerian content development in the petroleum industry.
Executive Secretary of the Nigerian Content Development and Monitoring Board (NCDMB), Mr Simbi Wabote, declared in the agency’s 10 year plan that the upstream petroleum industry invests annual $20 billion, explaining that the agency’s 10 year plan would be realized on the upstream activity budget.
Secretary-General of OPEC, Dr. Mohamad Barkindo, has been relentless in warning that enhanced petroleum exploration and production investment remains crucial in sustaining human economic and social development in the immediate to long term.
He attributed to the prevailing energy crisis in the world and associated high oil and gas prices to low investments by multinational oil companies and indignation of global lenders to petroleum industry projects.
Chairman of AA Holding’s, an investment company, Mr Austin Avuru, stated that energy transition would not displace oil and gas in a hurry. He advised investors to stake funds in building capacity for rising demand expected from significant growth in global population and rapid urbanization.
He said renewable energy would continue to play supplementary role in the global energy mix in the foreseeable future until peak oil production compels eventual switch.
Group Managing Director of NNPC, Mallam Mele Kyari, told visiting Indian military delegation in Abuja that Nigeria would take advantage of supply disruptions in the international market to optimize its production capacity.
Although Mallam Kyari did not provide details of the processes that would yield additional production, the target and deadline correspond with time frames that exist for a number of deepwater development programmes announced by multinational operators.
Kyari said the country would deliver significant production increase to meet projected rise in demand, and that fears of drop in oil demand on projected peak oil by 2040 is allayed by increasing role of petroleum in the global energy mix.
He projected that crude oil demand would be very high even beyond 2040, adding that NNPC was determined to grow Nigeria’s production to 3 mbpd by 2023 and take advantage of the gap that exists in the demand-supply balance.