New PIB may stall $70 bn deepwater oil projects
The lingering dispute between government’s regulators and technocrats over the key fiscal components of the 2020 Petroleum Industry Bill might further jeopardize investment of over $70 billion or N33.6 trillion in new development of discovered reserves in the nation’s deepwater terrain.
It was gathered that despite years of ground shifting efforts at reconciling investors and government’s technocrats over fiscal provisions that form factors for investment returns, wide position gaps still pose bottlenecks in the ongoing campaign to push the 15 year old bill through legislation.
GMD NNPC, Mallam Mele Kyari addressing PIB issues at the National Assembly
Managing Director of ANOH Gas Processing Company Limited, Mr Okechukwu Mba, stated in a presentation that the new PIB, despite the provision updates, has failed to address over 70 percent of concerns raised by investors.
He said that a bad PIB could lead to acute fall in Nigeria’s oil production, pointing at possible 30 percent drop in actual crude oil production if new investments in new field development are not incentivized by fiscal provisions.
He said members of the Oil Producers Trade Section (OPTS) of the Organized Private Sector (OPS) are willing to activate a flurry of development activities with about $9.0 billion investments in the short term, with greater investment outlook in the medium term.
Reports have it that the disputes over fiscal conditions that will emerge in the expected Petroleum Industry Act will 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.
Exploration, development and production operations patronize 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.
The last deepwater development project on the Egina field carried initial budget of $16 billion eventhough the company declared that development programme was realized on schedule and below budget.
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 from the deepwater province by 2022.
However, not all the approved deepwater development projects are in front burner and all of them are at risk if the prevailing fiscal dispute lingers into the imminent plant decommissioning and battery powered transportation phase of energy transition.
Some of the planned development projects currently stalled by fiscal dispute include the $10 billion Bonga Southwest-Aparo deepwater field operated by Shell in collaboration with Stardeep, the deepwater business arm of Chevron in Nigeria.
Another is the controversial 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. The Zababzaba-Etan development project holds investment potential of about $12 billion or N4.32 trillion.
Also, Total which is optimizing production infrastructure at operated oil mining lease (OML) 130 deep offshore Niger Delta is yet 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 floating production vessels in the block is largely seen as optimization project that would cut development cost by half. However, over $5.0 billion or N1.8 trillion is estimated for the project.
Together, the three development projects and another gas project listed for Shell command estimated combined investment of over $30 billion or N14.4 trillion.
The projects fall into the list of many of Africa’s largest planned offshore projects that now stand the risk of delay because, according to Rystad Energy, prevailing oil prices fall below their breakeven costs.
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, pointing out that Nigeria still has about 1.3 billion barrels of booked reserves for development and production investments.
According to the company, the 630 million barrels Bonga Southwest-Aparo with estimated $10-12 billion development budget would need a market price of $58.75 per barrel to reach an investment decision.
The 510 million barrel Zabazaba-Etan with estimated $12-15 billion development budget would require an average market price of $45.95 per barrel to achieve final investment decision.
And despite the cost advantage of not needing separate gloater to come online, development of the Porewei deepwater field with reserves profile of 145 million barrels still needs market price average of $43.30 per barrels to make commercial sense.
According to documents available at the corporate planning division of the Nigerian National Petroleum Corporation (NNPC) the Bonga deepwater field development comes with production capacity growth for 225,000 barrels per day. Again the Zabazaba deepwater field development, when commissioned, comes with nameplate production capacity for 250,000 barrels of light sweet crude oil per day.
Bonga Southwest and Aparo development was originally sanctioned by Ministry of Petroleum
Resources to come online by this year using a stand-alone floater with nameplate production
capacity of 225,000 barrels per day. Development budget of about $10 billion or N3.6 trillion captures subsea facilities; risers; floating production, storage and offtake (FPSO) vessel; and single point mooring buoy (SBM).
Shell and partners including Chevron, Total, Eni and Sasol severally called off FID that was
expected to pave way for funding outlays and launch the field development into project stages. Although the partners have regularly restated their resolve to deliver the project, the operator still leads protests against fiscal provisions in the PIB.
Next is also the Shell operated Bonga North field also located northwards of Bonga Main in OML 118 in the deep offshore. The field was also scheduled to start producing 100,000 barrels per day by 2020 but the investment decision could not also be reached.
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. The Shell operated Bonga FPSO has never reached it nameplate production capacity, making it ready output host from proximate field developments in the deepwater block.
“Bonga Main is currently being regarded as brownfield asset,” our source 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.”
ExxonMobil is totally silent on FID for three deepwater development programmes with
combined capacity for producing 330,000 barrels per day.
The company which operates exclusively offshore assets in Nigeria holds cards for development
of three deepwater fields including 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.
Whereas the original 2020 production startup has been missed, Bosi field still 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, Chevron’s local deepwater affiliate, Stardeep, is yet to declare FID on operated Nsiko
field. Although production start up target for the field targeted for 2020 has been missed, Nigeria expects additional 100,000 barrels per day from the Nsiko field which was discovered in 2003.
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.
Unfortunately, the envisaged domestic economic stimulus expected from the projects and the associated local content quotient of the full investment values is becoming a mirage as commerciality of the proposed investments become subjects of protracted fiscal disputes.
Reports have it that with the shift in the delivery timeline, failed expectations from the planned deepwater projects would now dim the country’s economic outlook and worsen acute shortage of foreign exchange revenue.
The oil industry investors gathered under the auspices of OPTS and the Indigenous Petroleum Producers Group (IPPG) complain that Nigeria has one of the most stringent fiscal provisions for commercial investors in the world. The groups blamed low investments in the industry on myriad of direct and indirect taxes and levies that drain commercial returns.
According to a position paper by the OPTS, “current PIB 2020 does not improve the investment environment for new project FIDs to be taken. By 2025, we could see a ~38% reduction in Deepwater production compared to 2020 levels and over 30% of production potential could be lost by 2030. Production decline could partially be attributed to PSC assumptions.”
The group pointed out that while Nigeria has the highest investment risk level among 9 compared peer countries; it has lowest investor reward level. The group pointed that government, on the other hand, takes the highest revenue reward from the world’s least investment in resource exploitation.
The investors also blame government for long contracting processes, inability to secure the operating environment and imposition of about 23 different taxes and levies on industry operations.
According to the OPTS, whereas some Industry issues have been resolved in the PIB, important drivers of investor confidence and government revenues were yet addressed. The group explained that the OPTS and IPPG jointly raised 107 issues during PIB engagement with government, lamenting that only 12 percent of all issues were resolved. The situation leaves the industry in serious fiscal disputes.
The groups demand resolution of issues around preservation of sanctity of existing contracts and encouragement of growth as the industry enters into new regulatory regime.
