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Eunisell Explores Feasibility of Vendor Funded Early Production Facility for Barracuda Field

Eunisell Limited, the Nigerian owned provider of oilfield services and facilities, has entered into a non-binding collaboration agreement (CA) with ADM Energy, an upstream E&P company.

Under the terms of the CA, subject to the completion of certain due diligence, ADM and Eunisell will explore collaboration opportunities to carry out development of Barracuda Field in OML 141 and associated work-related activity in Nigeria.  It is the intention of both parties, together with the risk sharing consortium in respect of Barracuda Field, that a formal agreement will be entered into in advance of any work commencing.

The CA may be terminated by mutual consent.

“Eunisell has decades of experience in engineering, production, operations and enhanced production techniques within Nigeria and the Parties intend to work together to use their combined experience to accelerate production of oil and gas assets, initially concentrating initiating production at the Barracuda field in which ADM recently invested”, a press release stated.  “Activities under the intended scope of work may include early production facility supply, procurement, construction and commissioning of production facilities, extended well testing and laboratory services”.

Following discussions, Eunisell may consider providing vendor financing to achieve the scope of work to be agreed, subject to terms and conditions to be determined at the point of an award of contract.

Eunisell has been a key facilitator for the Nigerian oil and gas marketplace for many years, helping operators to reach their production goals faster and at less capital costs. We look forward to building a relationship and are excited by the potential of working alongside them to support the development of our investments such as the Barracuda Field in OML 141.”



Libya Hopes to Surpass Angola, Shoots for Africa’s Top Oil Producer

By Mohammed Jetutu, in Cairo

Libya’s National Oil Company (NOC) is hoping to add some 300,000Barrels of oil per day to its average December 2020 output by the end of 2021.

That brings total output to 1.6MMBOPD– a level not seen since 2008. Although security in Libya’s oilfield activities isn’t entirely guaranteed, the country has been ramping up output.

If Libya succeeds-against the odds of insecurity-It will surpass Angolan output which, even before COVID 19 happened, had struggled below 1.45MMBOPD.

In February 2021, Angola  exported 1.206MMBOPD, according to Africa Oil+Gas Report’s March/April 2021 edition, released last week.

Libya has bigger reserves (48Billion barrels) than Angola (8 Billion) and Nigeria (37Billion), but years of conflict and underinvestment have capped the growth of its hydrocarbon industry.

Oil production in Libya has undergone a rapid rebound of almost 1MMBOPD since mid-October 2020, after the UN-backed Government of National Accord and the self-styled Libyan National Army agreed a truce.

Crude and condensate loadings from Libya in December 2020 averaged 1.237MM BOPD compared with 1.07MMBOPD in November 2020, the Africa Oil+Gas Report reported last January.

NOC expects near-term gains from a “combination of workovers on existing wells, infill drilling, improved artificial lift capabilities, new power generation projects, repair of damaged tanks, maintenance and replacement of pipelines and reinstating damaged fields”

The key projects NOC is relying on include the 50,000BOPD Sinawin development, the Nafoora field expansion and the full re-start of the Dahra field.


It’s Done: Ugandan Oil Project Proceeds to Construction Stage

Fifteen years after a commercial sized discovery was made, the partners of the Lake Albert development project, the Ugandan basin wide crude oil development, have concluded the final agreements required to launch this major project.

The discovery of oil, via the drilling of Mputa 1 onshore Uganda, was made in 2006, a year before the well that led to Ghana’s first oil in 2010 was drilled. But the tyranny of geology (landlocked, waxy crude, over a thousand kilometres from the coast), and one of the industry’s most arduous regulatory processes (the Ugandan bureaucracy), stalled the development.

But it’s done now. At the State House in Entebbe, Uganda this week, Yoweri Museveni, President of the Republic of Uganda, Samia Suluhu Hassan, President of the United Republic of Tanzania, Patrick Pouyanné, Chairman and CEO of TOTAL, as well as representatives of China National Offshore Oil Corporation (CNOOC), Uganda National Oil Company (UNOC) and Tanzania Petroleum Development Corporation (TPDC, were all present at the signing of the Shareholders Agreement of East African Crude Oil Pipeline EACOP and the Tariff and Transportation Agreement between EACOP and the Lake Albert oil shippers.

The Lake Albert development encompasses Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. The Tilenga project, operated by TOTAL, and the Kingfisher project, operated by CNOOC, are expected to deliver a combined production of 230,000 barrels per day at plateau. The upstream partners are TOTAL (56.67%), CNOOC (28.33%) and UNOC (15%). The production will be transported from the oilfields in Uganda to the port of Tanga in Tanzania via EACOP cross-border pipeline, with TOTAL, UNOC, TPDC and CNOOC as shareholders.

These agreements open the way for the commencement of the Lake Albert development project. The main engineering, procurement and construction contracts will be awarded shortly, and construction will start.

First oil export is planned in early 2025.

All the partners are committed to implement these projects in an exemplary manner and taking into highest consideration the biodiversity and environmental stakes as well as the local communities’ rights and within the stringent environmental and social performance standards of the International Finance Corporation (IFC).

“The Tilenga development and EACOP pipeline project are major projects for TOTAL and are consistent with our strategy to focus on low breakeven oil projects while lowering the average carbon intensity of the Group’s upstream portfolio. These projects will create significant in-country value for both Uganda and Tanzania” said Patrick Pouyanné, Chairman and Chief Executive Officer of TOTAL. “TOTAL is also taking into the highest consideration the sensitive environmental context and social stakes of these onshore projects. Our commitment is to implement these projects in an exemplary and fully transparent manner”.


ENI’s New Angolan Find to Push Net Output Beyond 115,000BOEPD

By Sully Manope

ENI’s new discovery of oil in Cuica-1 in Angola’s CabaçaDevelopment Area in Block 15/06 takes the Italian player on course of topping up its 100,000Barrels of Oil Per Day (BOPD) net in the country.

The well-head location, intentionally placed close to the Armada Olombendo FPSO East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production, thus immediately creating value while extending the FPSO production plateau. It is expected that production will start within six months after discovery.

Cuica-1 encountered 80 metres total column of reservoir of light oil (38°API) in Miocene sandstones located in in a water depth of 500 metres, ENI says that this discovery translates to a size estimated between 200 and 250Million barrels of oil in place.

The company net 100,000BOPD (crude oil alone) in total export volume from Blocks O, 3/05. 3/05A, 14, 15 and 15/06 in February 2021, according to the Angolan regulatory agency, ANPG

The New Field Well (NFW) has been drilled as a deviated well by the Libongos drillship and reached a total vertical depth of 4100 metres, good petrophysical properties. The discovery well is going to be sidetracked updip to be placed in an optimal position as a producer well. “The result of the intensive data collection indicates an expected production capacity of around 10,000 barrels of oil per day”, ENI says in a statement.

“Cuica is the second significant oil discovery inside the existing Cabaça Development Area and confirms the Block 15/06 Joint Venture’s commitment to leverage the favorable legal framework on additional exploration activities within existing Development Areas, as promoted through the Presidential Legislative Decree No. 5/18 of 18 May 2018”, the company said.

“Pursuant to the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the re-launch of the exploration campaign post-2020 COVID-19 pandemic and the drop of oil price”. A three-year extension of the exploration period of Block 15/06 has been recently granted until November 2023.


ENI in Congo-We Don’t Agree We Are Guilty, But We’d Pay

ENI has decided to make a consideration of €11.8Million available as an agreed sanction in a corruption case involving one of its managers in the Republic of Congo (Congo Brazzaville).

The decision was taken “following the reduction of the alleged offence to undue inducement by the Court of Milan”, the company declared in a statement.

ENI has by so doing “adhered to the hypothesis of agreed sanctions submitted by the Public Prosecutor, and has submitted its request”.

The Giudice per le indagini preliminari (GIP, the judge in charge for preliminary investigations) accepted the proposal of agreed sanctions as submitted by the Public Prosecutor and which ENI adhered to.

Even then, the company says that the deal “does not represent an admission of guilt by the company in relation to the alleged offence but an initiative aimed at avoiding the continuation a judicial process that would entail further expenditure of resources from ENI and all the involved parties”, ENI insists in a statement, arguing further, that “the verdict also confirms the resilience of the company’s anti-bribery control systems”.




New FID Date for Africa’s Biggest Onshore Crude Oil Development in 20 Years

By Toyin Akinosho

A tripartite agreement involving the governments of Uganda and Tanzania and the French oil major TOTAL, is expected to be publicly signed at the State House, Entebbe, Uganda, on April 11, 2021.

The event was postponed from March 22, 2021, as a result of the March 17 death of Tanzanian President John Magufuli.

The agreement will signal the Final Investment Decision(FID) -and the launch-of the Tilenga Development Project (the upstream oilfield development) and East African Crude Oil Pipeline (the main midstream project).

With the entire 1.3Billion barrels (recoverable reserves) in the Ugandan side of the Lake Albert Basin at stake, and 230,000Barrels of Oil Per Day expected to be output at peak production, the Tilenga-Kingfisher project is the biggest onshore upstream crude oil development in Africa in 20 years.

The continent has witnessed only deep-water developments of this magnitude, since TOTAL operated Girassol field came onstream offshore Angola in 2001.

Libya and Algeria, sites of Africa’s largest onshore fields, have not developed anything close to a 230,000BOPD project anywhere since Girassol’s first oil.

The Tilenga project, located in the Buliisa and Nwoya districts in Lake Albert, is operated by TOTAL (56.6%), in partnership with CNOOC and the Ugandan National Oil Company (UNOC). It includes the development of six fields and the drilling of around 400 wells on 31 locations. Production will be delivered through buried pipelines to a treatment plant built in Kasenyi, for the separation and treatment of the fluids (oil, water, gas). All of the water produced will be reinjected into the fields and the gas will be used to produce the energy needed for the treatment process. Surplus electricity will be exported to the pipeline and the Ugandan grid.

The Kingfisher development, whose production and processing facilities are located on the Buhuka Flats at the shores of Lake Albert in the Kikuube district, is the second upstream project in the basinwide development. It is operated by CNOOC. Whereas Tilenga will deliver 190,000BOPD at peak, Kingfisher will do 40,000BOPD at peak.

The East African Crude Oil Pipeline is a transborder 1,443 kilometre crude oil export infrastructure that will ferry the waxy crude from Kabaale in Hoima district to the Chongoleani Peninsula in the Tanzanian port town of Tanga on the coast of the Indian Ocean. It comprises a 24-inch insulated buried pipeline, six pumping stations (two in Uganda, four in Tanzania) and a marine export terminal.

In Uganda, it will cover a distance of 296 kilometres through 10 districts (Hoima, Kakumiro, Kyankwanzi, Mubende, Gomba, Sembabule, Lwengo, Kyotera, Rakai, Kikuube) and 25 sub counties.

In Tanzania, it will cover a distance of 1, 147 kilometres, through eight regions (Kagera, Geita, Shiyanga, Tabora, Singida, Dodoma).

Government and IOC partners are currently working out the final details of the Shareholders’ Agreement (SHA), Tariff and Transport Agreement (TTA) Enabling Legislation (EACOP Bill) and Engineering, Procurement and Construction management (EPCm).

First oil from the Tilenga-Kingfisher project is expected by mid-2025.

Construction of the 60,000BOPD refinery is expected to begin in late 2023, with commissioning by 2026. The export project is, regardless of the wishes of the Ugandan government, the top priority.

ENI’s Victory in Milan Creates Two Conflicting Reactions in Abuja

There were two contradictory reactions to the ruling, by an Italian court in Milan, that ENI’s CEO Claudio Descalzi and members of his management had no case to answer for the payment the company made to acquire its stake in the Oil Prospecting Lease (OPL 245), ten years ago.

The case had run in the Milan court for three years and Mr. Descalzi, who has been ENI’s CEO since May 2014, and is on course of being the longest serving head of the company in 30 years, faced certain prospect of a jail term.

At the headquarters of Nigerian Agip, ENI’s local subsidiary in Abuja, “it was a huge relief, a big burden lifted off our backs”, company staff say.  ‘We were in the middle of preparation for a meeting with NNPC (on a different subject) to hold the following day (after the March 17 2021 ruling), and we knew that the ruling would drive positive sentiments in our favour”.

The Nigerian government responded differently, at least from the tone of its statement. “The Federal Republic of Nigeria is disappointed in today’s ruling in Milan”, it said on March 17, “but thanks the Italian prosecuting authorities for their tireless efforts.”

The country’s Economic and Financial Crimes Commission (EFCC) has maintained, in the Nigerian court system, “that a fraudulent settlement and resolution came under (President Goodluck) Jonathan’s government with Shell and ENI buying the oil block from Malabu in the sum of $1.1Billion”. It said its Investigations into the deal “revealed crimes that border on conspiracy, forgery of bank documents, bribery, corruption and money laundering, to the tune of over $1.2Billon against   Malabo Oil and Gas Ltd, Shell Nigeria Ultra deep (SNUD) Nigeria Agip Exploration (NAE) and their officials”.

As recently as January 28, 2021, the anti-graft agency was in a Federal High Court in Abuja, to continue its case against Bello Adoke, the Attorney-General of the Federation (AGF) under Goodluck Jonathan; Aliyu Abubakar, described as “an oil magnate”;  Rasky Gbinigie; Malabu Oil and Gas Limited; Nigeria Agip Exploration Limited; Shell Nigeria Extra Deep Limited and Shell Nigeria Exploration Production Company Limited.Commission (EFCC) “with a 42 -count criminal charges) on the OPL 245, otherwise known as Malabu Oil case”.

The EFCC did not respond to request to questions on its response to the Milan ruling, but it could be said that the Nigerian government’s statement covers for it.

At the Nigerian Agip headquarters in Abuja, however, the sense is that it is easier now to focus on the Zabazaba-Etan twin deepwater field development aimed at monetizing reservoirs located in 1,500 and 2,000metres below the seabed. Although AngloDutch Shell is a 50% partner, ENI is the operator.

Front end activities had been completed. EPC contractors were in view and the local content part of the development was being cleared when the Milan case increased the heat. In Nigeria, even as EFCC was going to court, other government agencies were going ahead with approvals for the project, a situation that suggested a lack of unity in vision.

The Field Development Plan calls for conversion of a Very Large Crude Carrier (VLCC) to a Floating Production Storage and Offloading (FPSO). Recoverable reserves for the two fields combined are in the region of 500Million barrels.

ENI has insisted on its innocence, both in court and in public. “During its indictment, in the absence of any evidence or tangible reference to the contents of the trial investigation, the (Milanese) Public Prosecutor has told a story based on suggestions and deductions as already developed during the investigation. This narrative ignores both the witnesses and the files presented within the two years long and more than 40 hearings proceeding, that have decisively denied the prosecutorial hypothesis”.

Descalzi joined ENI in 1981 as a young reservoir engineer. His career took off in 1994, when he was appointed Managing Director of the company’s subsidiary in Congo. Four years later he was Vice President & Managing Director of NAOC, a subsidiary of ENI in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the board of several ENI subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of the Exploration & Production Division in ENI. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer in the Exploration & Production Division of ENI. From 2010 to 2014 he held the position of Chairman of ENI UK.

The PIB Doesn’t Promise an Efficient NNPC

By Toyin Akinosho

Optimism abounds in the air about the likely impact of the passage of Nigeria’s Petroleum Industry Bill (PIB) on the country’s state hydrocarbon company.

The default position, it seems, is that, once the reform law is in place, the Nigerian National Petroleum Corporation (NNPC) will be much better run.

“Decision making and efficiency would greatly improve”, one top General Manager at the NNPC told me, “when the bureaucratic red tape strangulation is cut off, after the PIB is signed into law”.

I responded that the 252-page bill, currently in debate in the country’s parliament, doesn’t impose any obligation on NNPC to improve.

“It however removes all excuses for nonperformance”, my GM friend countered.

I was startled by the gentleman’s naivety.

Nothing in the PIB, I replied him, attempts to coax NNPC out of its chronic, value-destroying tendencies.

But am I being extremely cynical?

Let us see.

Other optimists have expressed the view that, by improving the regulatory climate in the industry, the bill allows operators freer room to operate without encountering NNPC’s toxicity. Let me use the words of one of them: “The PIB promises a structure that enables the private sector to do its business under proper regulation and transparency and NNPC to do its business under regulation and transparency”.

And here’s a stretch of the argument: If the PIB is passed in its current form and properly implemented, NNPC’s role will so shrink that “its role in the industry will hardy be noticeable”.

These opinions place too much faith in the self-propelling possibility of a piece of legislation, constructed to address the largest rentier sector in a fragile petrostate.

And comparisons between what the PIB could do to NNPC, with what the Nigerian telecoms reform did to NITEL, is extremely exaggerated.

The PIB admittedly declares that NNPC will no longer perform regulatory roles. But the contention that the company will become a “mere” sector player is overstated. It will still loom large in our lives, and that’s very problematic.

There is a clause in the new law that tinkers with NNPC’s monopoly of hydrocarbon pipelines. There’s another that places exploration of frontier basins under the remit of the Upstream regulatory commission. These are big deals.

But NNPC is in joint venture in acreages that produce 45% of the country’s crude, and will continue to be. It is also the Concessionaire in the Production Sharing Contract (PSC) arrangements, which deliver over 39% of the crude, according to the 2018 OIL and Gas Industry annual report by the Department of Petroleum Resources (DPR), the latest state sanctioned report on the Nigerian hydrocarbon industry..

And there is the matter of NPDC, the operating subsidiary of NNPC. It’s a massive, incompetent wrecking ball, which has been gifted joint venture participation in 10 Oil Mining Leases (OMLs), all of them producing.

In 2019 alone, the Nigerian Government added more to the cart: It approved the transfer of OMLs 11, 24 and 98, including the operatorship of OML 116, from Federation’s interest (NNPC) to NPDC.

NPDC is also the sole stakeholder in three producing OMLs and two non-producing OMLs (i.e. no Joint Venture with any company, no PSC relationship, just NPDC held). And this is where the point is: The worst performing assets in NPDC’s portfolio are those in which it is the sole stakeholder.

It’s important to highlight this point because NPDC is one of the shining stars in the NNPC firmament. Whenever you read an NNPC financial report, it is NPDC which performs best or near the top. But the degree of its performance is in direct proportion with the help it gets from its partnerships with private entities. On its own, its capacity is hollow.

Another stellar achiever in the NNPC group is the Integrated Data Services Limited (IDSL), which was created in 1988, this same year as NPDC, to be an industry provider of Geophysical, Geological, Reservoir Engineering and Data Storage and Management Services.

IDSL’s claim to profitability lies in forcing its rivals into partnership for jobs contracted out by E&P companies. IDSL’s technical capacity is not widely respected in the industry. But since the E&P companies who control these contracts are either operators of Joint Ventures with NNPC or answerable to NNPC as their PSC Concessionaire, they find themselves unable to escape contracting the jobs to “IDSL-XX Joint Ventures”. In these roles, IDSL is always merely fronting.

There’s nothing in the draft PIB that seeks to stop the bullying tendencies of the state hydrocarbon firm and its subsidiaries, especially since the entire industry has, over the last 30 years, largely been handed over to them.

The Petroleum Industry Bill, at least the draft that is currently being debated, does not call for the privatization of the NNPC. But it has nevertheless created an ongoing conversation in the international media about possible privatization because it says that “The Minister shall within six months from the commencement of this Act, cause to be incorporated under the Companies and Allied Matters Act, a limited liability company, which shall be called Nigerian National Petroleum Company Limited (NNPC Limited)”.

That media conversation is largely speculative, because NNPC Limited will also be entirely owned by government. The difference is that NNPC Limited, by law, will now be clearly a commercial entity. The Bill says that at the incorporation of NNPC Limited, the Minister of Petroleum will “consult with the Minister of Finance to determine the number and nominal value of the shares to be allotted, which shall form the initial paid-up share capital of NNPC Limited and the Government shall subscribe and pay cash for the shares. Ownership of all shares in NNPC Limited shall be vested in the Government at incorporation and held by the Ministry of Finance Incorporated on behalf of the Government. The Ministry of Finance Incorporated, in consultation with the Government, may increase the equity capital of NNPC Limited. Shares held by the Government in NNPC Limited are not transferable, including by way of sale, assignment, mortgage or pledge unless approved by the Government”.

I understand the argument that goes like this: “The PIB promises an industry structure that should create efficiency and transparency”. What I know to be wrong, is the thinking that once the new law comes to effect, and it is being rigorously implemented, “NNPC business will start to dwindle and nobody would notice”.

True, the PIB, as currently drafted, has benefitted from a lot of lessons learnt and it is addressing key issues including the future of gas, domestic energy security and transparency.

Laws, however don’t, on their own, foster efficiency. It is those who operate the entities, governed by the laws, that deliver efficiency, if they are keen. And laws can only work optimally with consistent testing.

It is the responsibility of not just the government, or the regulatory agencies, but also the many companies that make up the constituent parts of the industry, to be vigilant by testing this law in courts and in rigorous advocacy. Not by whispering their fears and anxieties to the media and leaving the advocacy to NGOs.

This piece was initially published in the December 2020 edition of the Africa Oil+Gas Report.




Oil markets May Last Much Longer, If Clean Energy Policies are Not Sustained-IEA

World oil markets have rebounded from the massive demand shock triggered by Covid-19 but still face a high degree of uncertainty that is testing the industry as never before, according to a a new IEA report.

The forecast for global oil demand has shifted lower, and demand could peak earlier than previously thought if a rising focus by governments on clean energy turns into stronger policies and behavioural changes induced by the pandemic become deeply rooted, according to Oil 2021, the IEA’s latest annual medium-term market report. But in the report’s base case, which reflects current policy settings, oil demand is set to rise to 104 million barrels a day (mb/d) by 2026, up 4% from 2019 levels.

What is clear in this report, in the view of Africa Oil+Gas Report, is that if the so called ‘rising focus’ by governments on energy policies don’t turn into stronger policies, peak oil demand is unlikely to come in the relatively short time frame that the IEA is pushing for.

“The COVID-19 crisis caused a historic decline in global oil demand – but not necessarily a lasting one. Achieving an orderly transition away from oil is essential to meet climate goals, but it will require major policy changes from governments as well as accelerated behavioural changes. Without that, global oil demand is set to increase every year between now and 2026,” said Fatih Birol (Ph.D),  the IEA’s Executive Director. “For the world’s oil demand to peak anytime soon, significant action is needed immediately to improve fuel efficiency standards, boost electric vehicle sales and curb oil use in the power sector.”

Those actions – combined with increased teleworking, greater recycling and reduced business travel – could reduce oil use by as much as 5.6Million barrels a day by 2026, which would mean that global oil demand never gets back to where it was before the pandemic.

Asia will continue to dominate growth in global oil demand, accounting for 90% of the increase between 2019 and 2026 in the IEA report’s base case. By contrast, demand in many advanced economies, where vehicle ownership and oil use per capita are much higher, is not expected to return to pre-crisis levels.

On the supply side, the heightened uncertainty over the outlook has created a dilemma for producers. Investment decisions made today could either bring on too much capacity that is left unused or too little oil to meet demand. Only a marginal rise in global upstream investment is expected this year after operators spent one-third less in 2020 than planned at the start of the year.

In the IEA report, the world’s oil production capacity is projected to increase by Five Million barrels per day (5MMBOPD) by 2026. At the same time, the historic collapse in demand has resulted in a spare production capacity cushion of a record 9 mb/d that could keep global markets comfortable in the near term.

To meet the growth in oil demand to 2026 in the IEA report’s base case, supply needs to rise by 10MMBOPD by 2026. The Middle East, led by Saudi Arabia, is expected to provide half that increase, largely from existing shut-in capacity. The region’s expanding market share would mark a dramatic shift from recent years when the United States dominated growth. Based on today’s policy settings, US supply growth is set to resume as investment and activity levels pick up, yet any increase is unlikely to match the lofty levels seen in recent years.

“No oil and gas company will be unaffected by clean energy transitions, so every part of the industry needs to consider how to respond as momentum builds behind the world’s drive for net-zero emissions,” said Dr Birol. “Minimising emissions from their core operations, notably methane, is an urgent priority. In addition, there are technologies vital to energy transitions that can be a match for oil and gas company capabilities, such as carbon capture, low-carbon hydrogen, biofuels and offshore wind. In many cases, these can help decarbonise sectors where emissions are hardest to tackle. It’s encouraging to see some oil and gas companies scaling up their commitments in these areas, but much more needs to be done.”

The global refining sector is struggling with excess capacity. Shutdowns of at least 6MMBOPD will be required to allow utilisation rates to return to normal levels. Meanwhile, China, the Middle East and India continue to drive new capacity growth. As a result, Asian crude oil imports are forecast to surge to 27MMBOPD by 2026, requiring record levels of Middle Eastern crude and Atlantic Basin production to fill the gap.

The petrochemical industry will continue to lead demand growth, with ethane, LPG and naphtha together accounting for 70% of the forecast increase in oil product demand to 2026. Gasoline demand may have peaked, though, as efficiency gains and the shift to electric vehicles offset mobility growth in emerging and developing economies.

Demand for aviation fuels, the area that was hardest hit by the pandemic, is forecast to gradually return to pre-crisis levels. But a shift to online meetings and conferences – along with persistent corporate efforts to cut costs and hesitation by some citizens to resume leisure travel – could permanently alter travel trends.


Six Highlights of the Petroleum Industry Bill

By Toyin Akinosho

The latest version of Nigeria’s Petroleum Industry Bill, the long-awaited reform legislation currently in debate at the National Assembly, is a regulator’s dream.

It whittles down the powers of the minister of petroleum and grants extensive responsibilities to two regulatory agencies.

One is the Nigerian Upstream Petroleum Regulatory Commission; the other is the Nigerian Midstream and Downstream Petroleum Regulatory Authority.

The minister is in charge of policy; s/he supervises the ministry, promotes an enabling environment for investment, attends the Federal Executive Council Meetings and speaks for the country’s Petroleum sector at the International fora. But the new law annuls discretionary allocations of acreage licences. The Nigerian Minister of Petroleum will no longer-on his own- be the authority to issue, modify, amend, extend, suspend, review, cancel, reissue, revoke and /or terminate upstream licences in the country.

In the new law, s/he grants Petroleum Prospecting Licences and Petroleum Mining Leases through the processes established in the law “upon the recommendation of the Commission”.

The Minister also, “upon the recommendation of the Commission, revokes and assigns interests in Petroleum Prospecting Licences and Petroleum Mining Leases”.

The minister “upon the recommendation of the Commission or the Authority, direct in writing the suspension of petroleum operations in any area…”

The Minister “upon the recommendation of the Commission or Authority approve the fees for services rendered by the Commission or Authority in Regulations”..

These agencies have lots of work to do and the law backs them, unlike the key regulatory agency in the extant law, the Department of Petroleum Resources (DPR), which essentially operates like the secretariat of the minister.  The DPR’s powers, in the extant law, derive from the Minister’s assignments.

The Regulatory Commission is proposed to be governed by a nine-man board comprised of a) a one non-executive chairman;

(b) two non-executive commissioners;

(c) the chief executive of the Commission (the “Commission Chief Executive”); two other executive commissioners who are responsible for Finance and Accounts and Exploration and Acreage Management;

(e) one representative of the Authority not below the rank of director;

(f) one representative of the Ministry not below the rank of director; and

(g) one representative of the Ministry of Finance not below the rank of director.

The Upstream Petroleum Regulatory Commission will be funded by appropriation through the National Assembly.

The Midstream and Downstream Petroleum Regulatory Authority is similarly constitutd and funded likewise.

The NNPC, No Longer Performing Regulatory Duties, Will Become Commercial, but entirely Government Owned

The Bill does not call for the privatization of the Nigeria National Petroleum Corporation (NNPC). But it has nevertheless created an ongoing conversation in the international media about possible privatization because it says that “The Minister shall within six months from the commencement of this Act, cause to be incorporated under the Companies and Allied Matters Act, a limited liability company, which shall be called Nigerian National Petroleum Company Limited (NNPC Limited)”.

That media conversation is largely speculative, because NNPC Limited is also entirely owned by government. The difference is that NNPC, by law, will now be clearly a commercial entity. The Bill says that at the incorporation of NNPC Limited, the Minister of Petroleum will “consult with the Minister of Finance to determine the number and nominal value of the shares to be allotted, which shall form the initial paid-up share capital of NNPC Limited and the Government shall subscribe and pay cash for the shares. Ownership of all shares in NNPC Limited shall be vested in the Government at incorporation and held by the Ministry of Finance Incorporated on behalf of the Government. The Ministry of Finance Incorporated in consultation with the Government, may increase the equity capital of NNPC Limited. Shares held by the Government in NNPC Limited are not transferable, including by way of sale, assignment, mortgage or pledge unless approved by the Government.

IJV Will Be Voluntary

Joint Ventures between Nigeria’s state hydrocarbon company NNPC and other parties in the country’s upstream sector can be converted into incorporated joint ventures if the parties so wish, in the eyes of the Petroleum Industry Bill (PIB).

In other words, the decision to incorporate the JVs is voluntary, if the bill is passed into a law in its current form.

“NNPC Limited and other parties to joint operating agreements in respect of upstream petroleum operations, may on a voluntary basis restructure their joint operating agreement as a joint venture carried out by way of a limited liability company, each referred to as an “incorporated joint venture

company” (IJV), based on the principles established in the Second Schedule to this Act”. The incorporated joint venture companies shall not be subject to the provisions of the Fiscal Responsibility

Act and the Public Procurement Act.

Principles of Negotiating Incorporated Joint Ventures- Part of the Second Schedule of the imminent law says  (1) An incorporated joint venture company may be created for an existing joint operating agreement. Each incorporated joint venture company shall be formed under the Companies and Allied Matters Act. NNPC Limited shall enter into negotiations with the other parties to such existing joint operating agreements with a view to, among other things- (a) agreeing and executing a shareholders’ agreement in respect of the applicable incorporated joint venture company; (b) agreeing the provisions of the memorandum and articles of association of the applicable incorporated joint venture company; and (c) incorporating the applicable incorporated joint venture company. (2) Prior to the incorporation of each incorporated joint venture company, the parties to each applicable joint operating agreement shall continue to carry out their obligations under such joint operating agreement in the ordinary course of business.

 Natural Gas is Big in the New Law

The Nigerian government has always wanted Natural Gas investment to take off. “A large share of the massive gas reserves of 203 Trillion Cubic Feet (Tcf) can be produced at reasonable cost”, Timipre Sylva, the minister of state for Petroleum, said at an investor’ dialogue in August 2020. “A significant network of additional gas pipelines needs to be constructed to connect all major economic centers of Nigeria to natural gas, he explained. “The development of an optimal framework for electricity generation based on natural gas will create a strong basis for providing electricity to all Nigerians”. This statement foreshadowed the September 29 2020 presentation of the PIB to the National Assembly.

The domestic base price, the price at which Nigerian gas producers are to sell to Power Plants, will be $3.2 per Million British Thermal Units (MMBtu), beginning from January 1, 2021, if the bill is passed into law in its current form. The draft legislation also stipulates that the price at which the gas-based industry, comprising companies which produce methanol, fertilizer (urea, ammonia), polypropylene, etc., will purchase natural gas, can be as low as $1.5 per MMbtu. That price is special and it is calculated from a formula. Gas users outside the power sector and the gas-based industry will pay at least $0.5 higher than $3.2 per MMbtu, and their cost of purchase will depend on negotiations with their suppliers.

The domestic base price -$3.2per MMBtu- which is specified in the third schedule of the bill, shall be increased every year by $ 0.05 per MMBtu until 2037, when a price of $ 4.00 per MMBtu will apply for that year and future years. The Midstream and Downstream Regulatory Authority, “may, by regulations, change the domestic base price and the yearly increase) to reflect changed market conditions and supply frameworks”, says the bill.

In the Midstream, the bill creates a big Parastatal: The Midstream Gas Infrastructure Fund, which shall be “(a) a body corporate with perpetual succession and a common seal”. The purpose of the Fund shall be to make equity investments of Government owned participating or shareholder interests in infrastructure related to midstream gas operations aimed at –

(a) increasing the domestic consumption of Natural Gas in Nigeria in projects which are financed in part by private investment; and (b) encouraging private investment.

For the Fund, the draft legislation creates a Transaction Advisor, “who shall be responsible for providing transaction advisory services, including technical and commercial evaluation of proposals, defining project screening criteria and profitability target for projects and any other duty as may be assigned by the Council on behalf of the Fund”.

Host communities will be adequately covered to foster sustainable prosperity

A passage that sticks out in the PIB is this statement: “Failure by any holder of a licence or lease to incorporate a trust for the benefit of the host communities in the licence area may be grounds for revocation of the licence or lease”. The law says that “aach settlor, where applicable through the operator, shall make an annual contribution to the applicable host community development trust fund of an amount equal to 2.5% of its actual operating expenditure in the immediately preceding calendar year in respect of all petroleum operations affecting the host communities for which the applicable host community development trust was established”, says the 252 page draft legislation.

Host community issues are some of the most intractable items in the development of Nigeria’s oil and gas industry. Some companies have robust Host Community plans while several do not.

In the PIB’s definition, a “settlor” is a holder of an interest in a petroleum prospecting licence or petroleum mining lease or a holder of an interest in a licence for midstream petroleum operations, whose area of operations is located in or appurtenant to any community or communities. “Where there is a collectivity of settlors operating under a joint operating agreement with respect to upstream petroleum operations, the operator appointed under the agreement shall be responsible for compliance with the law on behalf of the Settlors”.

The constitution of the host communities development trust shall contain provisions requiring the Board of Trustees to be set up by the settlor, who shall determine its membership and the criteria for their appointment. The Board of Trustees shall in each year  allocate from the host communities development trust fund, a sum equivalent -(a) 75% to the capital fund out of    which the Board of Trustees shall make disbursements for projects in each of the host community as may be determined by the management committee, provided that any sums not utilised in a given financial year shall be rolled over and utilized in subsequent year; (b) 20% to the reserve fund, which sums shall be invested for the utilisation of the host community development trust whenever there is a cessation in the contribution payable by the settlor; and (c) to an amount not exceeding 5% to be utilised solely for administrative cost of running the trust and special projects, which shall be entrusted by the Board of Trustee to the settlor. The law also says that host community development plan shall -(a) specify the community development initiatives required to respond to the findings and strategy identified in the host community needs assessment; (b) determine and specify the projects to implement the specified initiatives; (c) provide a detailed timeline for projects; (d) determine and prepare the budget of the host community development plan; (e) set out the reasons and objectives of each project as supported by the host community needs assessment; (f) conform with the Nigerian content requirements provided in the Nigerian Oil and Gas Industry Content Development Act; and (g) provide for ongoing review and reporting to the Commission.

The PIB does not relate this trust fund to the Niger Delta Development Commission (NDDC) which has the legal backing to receive 3% of the total yearly budget of any oil producing company operating onshore and offshore in the Niger Delta area.

Taxes Will Be Lower for Onshore and Shallow Water Licences

The draft law provides, for Taxation, Hydrocarbon Tax and Company Income Tax, which, combined, replaces the Petroleum Profit Tax of the extant law.

Chargeable Tax

The chargeable tax for any accounting period of a company shall be a percentage of the chargeable profit for that period aggregated and it shall be –

  • (a) 42.5% of the profit from crude oil for onshore areas for petroleum mining Leases selected pursuant to sections 93(6)(b) and 93(7)(b) of this Act;

(b) 37.5% of the profit from crude oil for shallow water areas for petroleum mining leases selected pursuant to sections 93(6)(b) and 93(7)(b) of this Act;

(c) 22.5% of profit from crude oil for onshore areas for new licences and leases granted after the commencement of this Act and for marginal fields in onshore areas;

(d) 20.0% of profit from crude oil for shallow water areas for new licences and leases granted after the commencement of this Act and for marginal fields in shallow water areas;

(e) 5% of the profit from crude oil from deep offshore areas for petroleum mining leases selected pursuant to sections 93(6)(b) and 93(7)(b) of this Act; and

(f) 10% of profit from crude oil for deep offshore areas for new licences and leases granted after the commencement of this Act.

Royalties based on production shall be calculated on a field basis.

(2) The royalty shall be at a rate per centum of the chargeable volume of the crude oil and condensates produced from the field area inthe relevant month on terrain basis as follows in –

(a) onshore areas 18 per cent

(b) shallow water (up to 200m water depth) 16 per cent

(c) deep offshore (greater than 200m waterdepth) 10 per cent

(d) frontier basins 7.5 per cent

(3) For deep offshore fields with a production during a month of not more than 15,000BOPD, the royalty rate shall be 7.5%.

Production above 15,000BOPD shall be at the royalty rate specified in subparagraph (2) of this paragraph. (4) Royalties for onshore fields and shallow water fields, including marginal fields, with crude oil and condensate production not more than 10,000BOPD during a month shall be at a rate per centum of the chargeable volume of the crude oil and condensates produced from the field area per production day during a month on tranched basis as follows – (a) for the first 5,000BOPD 5per cent (b) for the next 5,000BOPD 7.5 per cent Provided that fields with crude oil and condensate production more than 10,000BOPD.




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