All posts tagged featured

NNPC Applies the Brakes on Managers’ Retirement

Holds up onboarding of 500 new hires.

NNPC has held up the planned retirement of some of its Managers, a result of the combined collapse of crude oil prices and the surge in cases of the Coronavirus.

The Nigerian state hydrocarbon company’s retirement of 33 General Managers (GMs) and Group General Managers (GGMs) three weeks ago, was not followed by similar treatment to Managers, a fortnight ago, as scheduled.

All the 33 GMs and GGMs who were due for retirement within a year were asked to leave on Wednesday, March 11, 2020. Managers in the same situation (one year left to retirement) were to receive their own letters in the week of March 16, 2020, but that did not happen.

“The Human Resources Department realised that they had to keep us all safe, first and foremost”, one source said, referring to the surge in cases of the Coronavirus in Nigeria, which has gone past 90 cases (formal government figures).

Some 500 new hires, including graduate trainees and experienced hires were supposed to start work, but that process is also on hold.

The retirement project is part of a restructuring effort, which the Group Managing Director, Mele Kyari, christened Repositioning For Performance Excellence.

It had involved the movement of some Chief Operating Officers and an extensive promotion exercise as well as shuffling around of people in leadership positions. Some of the key appointment is in the “repositioning” exercise include that of Kennie Obateru as Group General Manager(GGM) Public Affairs, to replace Samson Makoji, who had served in acting capacity since the exit of Ndu Ughamadu, the Maikanti Baru-era GGM Public Affairs; Mohammed Ismail Usman as General Manager in charge of Asset Management at the Nigeria Petroleum Development Company NPDC; Martina Uzoamaka Atuchi as the new GM of Joint Venture at the National Petroleum Investment Management Service (NAPIMS); Marcel Amu Ogbonna AS GM Planning at NAPIMS; Muhammad Barwa Ahmad as GM in charge of Pipelines at the Nigerian Gas Company (NGC) and Isokariari Soibiton  Ngoji Kjo ,the new GM Processing, at NGC.


Rovuma Catches the Bug

ExxonMobil operated Rovuma LNG Project in Mozambique, has joined the victims of the Pandemic.

Concerns about the effects of the new Coronavirus has compelled the partners in the 15 Million Tonnes Per Annum (15MMTPA) project to postpone the Final Investment Decision (FID) indefinitely.

The two-train onshore LNG project, to utilize gas from deepwater Area 4, had been on the drawing board for over six years.

FID on Rovuma LNG was due in the first half of 2020.

Partners had announced offtakers for the project as far back as 2017.

But Rovuma LNG has come up on the list of those projects from which ExxonMobil is making significant cut in their capital expenditure as a result of a contraction in economic activity created by the virus.

Gas in Area 4 was discovered by ENI in 2011. The block holds an estimated 85Trillion cubic feet of natural gas (proven), deep below the Indian Ocean seabed.

Mozambique Rovuma Ventures, owners of Rovuma LNG, include ExxonMobil, ENI and the China National Petroleum Corporation, which together control 70% of the holding, with the remaining 30% split into equal parts between Portuguese group Galp Energia, South Korea’s Kogas and Mozambican state oil company ENH.


Equatorial Guinea Shortlists Investors for Refineries, Methanol Plant and Storage Tanks

Equatorial Guinea’s Ministry of Mines and Hydrocarbons (MMH) has announced the key companies shortlisted for the execution of its landmark projects under its ongoing Year of Investment.
At Punta Europa, where most of Equatorial Guinea’s gas and energy activities are currently located, the country plans to build a modular refinery, storage tanks and a methanol-to-derivatives plant.

Interested companies for the modular refinery include Marathon Oil, an American independent, Selquimica International with Engineering and Energy, a Spanish-Russian consortium and Rosslyn Energy of Britain.

The latter is also interested in the development of the Storage Tanks, along with British company Orange Resources Worldwide and the China Communications Construction Company.

Finally, the Methanol-to-Derivatives project has attracted the interest of South African company Pan African Energy, Nigerian company Bugabi Group, and Danish catalysis company Haldor Topsoe.

At Kogo South of the nation’s economic capital Bata, the second Modular Refinery project has attracted the interest of Egyptian company Petrojet, British company Rosslyn Energy, the Spanish-Russian consortium of Selquimica International with Engineering and Energy, and UAE-based SDLE International DMCC. Meanwhile, South African company Grindstone Resources and Omani company MSS LLC are both shortlisted for the gold refinery project and the Minerals Industrial Zone.

”While the MMH is still registering interest from additional players, including Chinese companies, these are the shortlisted potential investors for these projects so far”, the Ministry says in a statement.

Côte d’Ivoire Stimulates a Robust Domestic Market with Low Gas Reserves

Even with relatively low reserves of natural gas, Côte d’Ivoire is establishing an energy leadership in West Africa.

With just about 1 Trillion cubic feet, the 67th in the world, the country has taken several initiatives to monetize natural gas across power generation and public transport.

Two gas to power projects with combined 643MW capacity, have recently reached financial close.

And 150 buses will be running on Compressed Natural Gas by this time next year, a threefold increase from the 50 vehicles that were introduced for the pilot project in 2018.

Since January 2020, Côte d’Ivoire has secured key financing for its major gas-to-power projects, Azito and Atinkou. The former is a brownfield expansion of the existing Azito gas-to-power station, a 460MW plant owned and operated by Globeleq which uses natural gas supplied from Côte d’Ivoire’s offshore gas fields. Azito is being expanded by 253MW and its expansion project reached financial close in January 2020. Upon completion, the Azito plant will represent about 30 % of Côte d’Ivoire’s installed power generation capacity.  The expansion project relies on a debt financing package of EUR 264Million provided by several financial institutions such as the International Finance Corporation (IFC), the African Development Bank (AfDB); the West African Development Bank (BOAD); the OPEC Fund for International Development (OFID) and a pool of European Development Finance Institutions (EDFIs). Minister of Petroleum, Energy and Renewable Energies of Côte d’Ivoire, M. Abdourahmane Cisse, laid the foundation stone for Phase IV on March 7th, 2020 and first power is expected this year.

The latter, Atinkou or Ciprel V, is a project carried out by the Eranove Group, to develop a 390MW combined cycle gas-to-power station outside of Abidjan. A 20-year concession agreement was signed for the project in December 2018, and it just secured a financing package of EUR 303 million from the International Finance Corporation in March 2020. The full debt financing package was provided by several financial institutions such as the African Development Bank (AfDB), the Dutch entrepreneurial development bank FMO, Germany’s Deutsche Investitions- und Entwicklungsgesellschaft (DEG), the Emerging Africa Infrastructure Fund and the OPEC Fund for International Development (OPEC Fund).

The government is also enabling the right kind of business environment for the sector to thrive, notes African Chamber of Energy.

Four decrees were signed in the Council of Ministers on March 11th, 2020, to renew the exclusive exploitation authorization for the oil and gas fields of Foxtrot, Mahi, Manta and Marlin in Block CI-27. The decrees extend each authorization by 10 years, with the explicit goal of “ensuring the stable and continued supply of gas to the new power plants CIPREL 5 and AZITO 4 and guarantee national power supply sufficiency.”

Côte d’Ivoire’s transport company SOTRA (Abidjan’s Transport Company) has run 50 buses on compressed natural gas (CNG) since 2018. Following the successful trials, up to 150 CNG buses are expected to be driving on Abidjan’s roads by 2021.

Equatorial Guinea Grants Relief to Oilfield Service Companies

The country has acted to support its services industry and is engaging on an industry-wide dialogue to study other measures for upstream operators and ongoing midstream projects

The Ministry of Mines and Hydrocarbons (MMH) of the Republic of Equatorial Guinea decided on the waiving of its fees for service companies in the country.

The country says it is the first action to be taken to support oil & gas service companies in Equatorial Guinea in the wake of the oil price drop caused by the coronavirus pandemic. Oil prices currently remain at around $20 a barrel, a historically low level since prices broke the magic $25 in the early 2000s

“The Ministry of Mines and Hydrocarbons took the unanimous decision to waive its fees for services companies for a duration of three months,” declared Gabriel Mbaga Obiang Lima, the Minister of Mines and Hydrocarbons. “We recognize that the oil sector continues to be the largest private sector employer in the country and want to give our local service companies the means to weather the storm and avoid any jobs being lost. While it is important to let market forces determine the future, the government does have a role to play in stimulating the market and creating an environment for these companies to stay strong, continue investing and create opportunities for our citizens,” he added.

Jobs security and the safety of Equatorial Guinea’s citizens have been put at the top of priorities for the MMH, which has further pledged to keep engaging with local and international companies to create the right kind of enabling environment for the sector to operate and grow despite current circumstances.

International operators will need to keep complying with local content requirements in Equatorial Guinea throughout the downturn, and make sure to work with the local services industry to adapt to new market dynamics. This is the first such measure to be taken in Equatorial Guinea, which will consider additional action to bring relief to its oil & gas sector.

The statement added: “The ongoing coronavirus pandemic has brought the world economy to a halt and critically affected oil demand. As a result, prices have been brought to one of their lowest levels in a long time, which brings considerable instability to African oil producers in the Gulf of Guinea.

GMoU Is Widely Praised in Nigeria’s Oil Communities, but It’s Not the Cure All

Among oil rich local communities in Nigeria’s Niger Delta region, the GMoU is widely perceived as the most effective strategy for benefit transfer.

The arrangement is, however, burdened with too many expectations and its provisions are non-legally binding, with reported violations in several cases, according to a new report.

“This Global Memorandum of Understanding is a participatory development planning process initiated by oil companies and this exists for a lot of communities in the Niger Delta” , says Ken Henshaw, author of Local Impacts, one of the 12 sub reports in the latest Benchmarking Exercise Report (BER 2019), of the Nigeria Natural Resource Charter. “The communities consider this a very key process for delivering development”.

The BER is a biennial exercise which reviews the entire Nigerian petroleum sector and its linkages to the wider economy through a set of principles framed around how best the government and the citizenry have harnessed the opportunities created by the country’s petroleum endowment.

The audience at the launch of the BER 2019 in Abuja

“You cannot sue an oil company for violating a GMoU and in the course of our research, we did see a lot of cases where GMoUs were violated”, Henshaw argues.

Ken Henshaw serves as Executive Director of the Centre for Social Studies and Development (CSSD), one of the several Civil Society organisations engaged by the NNRC to research and write up the report. “Agreements were violated and oil communities took to the streets to protest”. He is concerned that the expectations which communities have of oil companies are far, far higher than what “the real mandates” of oil companies are. “When you go into a community, they expect the oil companies to build primary schools, build secondary schools, even build Churches. In Eket, Ibeno specifically, it is expected that Mobil should renovate the Qua Iboe Church. The community has queued behind that expectation and it’s currently causing friction. There’re unrealistic expectations being placed on oil companies”.

The government hasn’t done much in managing these expectations, in the opinion of the researcher.

Henshaw gives two examples of what he calls ‘unrealistic expectations’.

Ken Henshaw: Government has not managed expectations

“The first is construction of Modular Refineries. When in 2016, the government first went to the market with that idea, in the Niger Delta, artisanal refiners, oil thieves basically came together and formed unions. They started forming clusters to establish modular refineries. The government didn’t do well in managing those expectations because people in the region thought that modular refineries would be like installing boreholes to overhead tanks and every family would own one. That was the expectation, the government didn’t do much to manage this expectation. The next one is the re-allocation of oil blocks. The government said that it will take communities into consideration for the reallocation of oil blocks. It says so in the National Petroleum Policy Document. That is an expectation that was not properly managed because the perception in the minds of the communities simply means that every family where a pipeline passes through should have some kind of block. When expectations aren’t properly fulfilled, it fuels anger, it leads to suspicion which leads to crisis”.

Henshaw says that the communities have largely not benefitted from the utilization of the state sponsored intervention schemes, including 13% Derivation, Statutory Allocation, Ministry of Niger Delta Affairs, NNDC (Niger Delta Development Commission).

“The community is totally not involved in how this 13% Derivation Fund is utilised, so the only thing that gets the community involved or the community feels a sense of belonging to, as we speak, is still the GMoU”.

“So, either way we look at it, it’s still the only mechanism that has a situation where some people in the community would come to give actual contribution as regards to needs within the community. I think it has worked to a large extent. How we can develop it further should be what we should be looking into”.

Nigeria’s EIAs Are Toothless, With Focus on Compensation than Deterrence, Report Says

By Foluso Ogunsan

Regulations on Environmental Impact Assessments (EIAs) in  Nigeria  look good in the books, but the extent to which the government integrates this process into decision making on resource projects is extremely limited, a new report has shown.

“There are several gaps in governments’ monitoring and control of the EIA process to the extent that it is possible for it to be circumvented by resource companies that desire to do so”, according to the report, which looked at environmental social and economic effects of hydrocarbon extraction on communities  at all stages of a project cycle. “Government agencies responsible for approving oil and gas sector projects lack the technical and financial capacity to monitor and enforce compliance”, the report argues.

One substantial claim in the report is the contention that the Nigerian government does not use environmental and socioeconomic impact assessments (SIAs) before deciding to open an area to exploration and production activities.

But the government, it says, actually makes some attempt to use  these assessments at other stages of resource extraction.This focus on environment and social impacts of natural resource projects is one of the 12 sub reports in the latest, (ie 2019 version) Benchmarking Exercise Report (BER)  of the Nigeria Natural Resource Charter

The biennial Benchmarking Exercise Report (BER) of the Nigerian Natural Resource Charter (NNRC) looks at the entire Nigerian petroleum sector and its linkages to the wider economy through a set of principles framed around how best the government and the citizenry have harnessed the opportunities created by the country’s petroleum endowment.

The charter identifies 12 broad precepts, covering the main decisions required to transform assets under the ground into development above ground.

“There are no defined, deliberate, and enforceable frameworks created by any tier of government with the goal of ensuring that affected communities participate meaningfully in decision making on resource projects”, contends the report, specifically titled Local Impacts. “This has meant that the free, prior, and informed consent of communities is not sought or obtained. Where efforts are made in this regard, they are discretionary and ‘after the fact’.

“EIA requirements and the Land Use Act do not reasonably prioritise consultation with communities. The Host Communities component of Petroleum Industry Governance Bill (PIGB), which could have addressed these gaps and increased trust, did not make much progress in the period under review. Similarly, the National Petroleum Policy (NPP), which articulates the government’s vision in the petroleum sector and promises to increase the participation of affected communities, did not take widespread effect in the period.

At the two different launches of the Benchmarking Exercise Report, in Lags and Abuja, Ken Henshaw, Executive Director of the  Centre for Social Studies and Development (CSSD), which authored the Precept 5, focused on  Local Impacts, harped on two issues: the seeming cluelessness of regulatory authorities which encourages lax accountability of licence holders to world class environmental  housekeeping  and (2), the sheer alienation in Host Communities created by break down of trust.

“In the requirement for EIA, communities are not specifically mentioned”, Henshaw told the packed halls at the launch of the report, in late February and early Mach 2020. “It talks about a broader perspectives of citizens in general, people, consultations, but not with the communities specifically mentioned. If communities were mentioned, I believe they would have created a nexus that requires that EIA documents be interpreted in a such a way that communities understand it and can make useful inputs. In the course of my research, I saw EIA reports clearly plagiarised from other places. In the course of my research, I saw EIA reports that were conducted in faraway regions as Brazil. EIA reports that talked about plant species that according to National Geographic exists only in South America. They were EIA reports for projects in the Niger Delta region. Also we noticed in the course of the report, projects that had started and gone halfway before EIA reports were released. Our conclusion in this regards is that there’s no requirement that EIA reports are integrated into serious decision-making on resource development.”

The report itself declares:

  • In the period under review, two critical pieces of legislation that could have strengthened the ability of government agencies to enforce regulations were denied assent by the President of Nigeria—PIGB and the National Oil Spill Detection and Response Agency (NOSDRA) Amendment Bill. PIGB recommended the establishment of a new regulator, the NPRC, charged with regulating the entire industry, effectively replacing the current Depatment of Paetroleum Resources (DPR); while the NOSDRA Amendment Bill emphasised increased enforcement of fines and penalties for polluters, as well as giving NOSDRA the power to enforce these penalties and fines and to inspect and monitor the decommissioning of oil facilities.

Henshaw said there was an opportunity created in the year 2017 when the Federal Executive Council developed the National Petroleum Policy. “That policy actually creates very far-reaching frameworks that ensures participation of local communities, unfortunately we haven’t seen it in the period under review take off”.


“While Nigeria’s EIA Act requires that project proponents present plans for mitigating adverse impacts of their proposed projects, there is no strong evidence indicating that, in taking decisions over resource projects, the government prefers the option of preventing costs over compensation and minimisation of such negative costs.

“In at least one instance (that of routine gas flaring), the government seems more inclined to impose fines and extend flare-out targets than to enforce its own flare-out dates. The capacity of government regulatory agencies to enforce sanctions and carry out their functions appropriately is grossly limited, principally on account of capacity and funding constraints.

In Northwest Africa, You Don’t Always Get What is Promised

By Toyin Akinosho, Publisher

Exploration in the Northwest African Margin has been a bumpy ride for wildcatters since the discovery of the Sangomar oil field in November 2014.

What you get in these deepwaters on the edge of Mauritania, Senegal, The Gambia, Guinea-Bissau, and Guinea-Conakry is not always as golden as the headline media stories promise.

The Sangomar discovery drew explorers to the MSGBC basin like ants to open, wet sugar.

New York listed Kosmos Energy encountered sizeable tanks of natural gas with the Tortue-1 well, drilled off Mauritania six months after Cairn Energy’s Sangomar find. The company made more gas discoveries after Tortue-1; in Guembeul-1 off Senegal, in Ahmeyin-2, off Mauritania, Terranga-1 and Marsouin-1.

Having found so much gas, and constructed an elaborate plan to valorize the resource through a Floating LNG development, Kosmos set out to look for crude oil in the same acreages where it had found gas, by interrogating the geologic trends it had mapped and refining its charge model in order to define the prospectivity of the deeper waters. But it never succeeded in encountering liquid hydrocarbons.

The second exploration phase, as it was called, threw up three dry holes out of four wells. The only discovery in that phase was the Yakar gas discovery, which Kosmos quickly moved to declare as the “industry’s largest hydrocarbon discovery of 2017”.

Elsewhere in the MSGBC, meanwhile, other operators had their issues.

In October 2018, the Australian minnow, FAR, announced that Samo-1, drilled in block A2 offshore The Gambia, was a dry hole. It was the first exploration well in the country in 40 years. But FAR, a small company without any hydrocarbon production to its name, has been talking things up. It is claiming it will drill another well in the vicinity of Samo-1 before the end of 2021.

TOTAL moved the drillship Pacific Santa Ana to drill the wildcat JAMM-1X, in 2,400metres of water offshore Senegal in April 2019. Some difficulty with the BOP (Blow Out Preventer) led to a break in drilling operations around the third week of June. The well was finalized in mid-August 2019, with minor oil shows. The French supermajor quietly licked its wound. The depressing story barely made it into the news.

TOTAL harvested a more disappointing result in the next well, the Richat-1 well located offshore Mauritania, further north of JAMM-1X. The prospect on the flanks of a large diapir structure, sitting close to the continent / ocean boundary, was drilled, in 1,500metre water depth, with the same Pacific Santa Ana.

Richat-1, was burdened with a lot of expectations: its primary objectives were prognosed to be submarine fan / channel sands at a distal location on a late Cretaceous delta / fan system, where the Nouakchott (Cenomanian-Santonian) and Nouadhibou (Campanian-Maastrichtian) systems overlap. The prospect lies along trend, with a likely similar stratigraphic setting to the giant Yakaar gas discovery and Requien Tigre prospect on the Senegal fan.

But it was dry.

Explorers haven’t exactly nailed a formula for the MSGBC basin, the way they have come to understand the Tano basin, a sub basin of the West African Transform Margin.

Remember how we got here.

In 2001, thirteen years before the Sangomar field was discovered, Woodside Energy announced Northwest Africa to the world, with the discovery of the Chinguetti field, located in 1,000metre water depth, 90kilometres west of Nouakchott, the Mauritanian capital. The company originally claimed 120Million barrels of oil as estimated recoverable reserves, and planned the $750Million field development on the basis of these reserves estimates, deploying a 1.6Million barrel capacity FPSO to drain the reservoirs. First oil came out in February of 2006. Nine months later, however, the Australian operator issued a statement reducing the field’s Proven and Probable (2P) reserves to 53Million barrels. At the end of 2007, 2P reserves were put at 34Million barrels.

Nor have the other fields discovered by Woodside in the neighbourhood of Chinguetti fared well either.

Plans to develop the Banda field for a gas to power project have suffered a still birth, as have the proposals to tie the Tiof gas field to Chinguetti’s development.

With such a history, it is instructive that deepwater Northwest Africa remains a magnet especially for majors.

TOTAL took 90% of Senegal’s Rufisque Offshore Profond blockn May 2017, with Société Nationale des Pétroles du Sénégal (Petrosen), holding the remaining 10%. The company signed into Blocks C15 and C31, sited off Mauritania, in December 2018, adding to the three blocks (C7, C9 and C18), it already had interest in. These were following after the agreement it had, a full year earlier, with the National Office of Petroleum of Guinea, for Technical Evaluation Agreement to study deep and ultra-deep offshore areas located off the coast of Guinea Conakry.

ExxonMobil initiated acquisition of its largest-ever proprietary seismic survey-anywhere in the world- over Mauritania’s blocks C-14, C-17, and C-22, in October 2018, covering more than 6,500 kilometers of two dimensional (2D) and nearly 21,000 square kilometers of 3D seismic data. The acreages are located in water depths ranging from 1,000metres to 3,500 metres.

BP had moved forcefully into MSGBC earlier than TOTAL and ExxonMobil, taking up 62% participating interest in Kosmos Energy held C-6, C-8, C-12 and C-13 exploration blocks in Mauritania and a 60% participating interest in the Cayar Profond and St Louis Profond exploration blocks in Senegal.

As operator of these assets the British supermajor is leading the Floating LNG project scheduled to deliver first gas by 2022. And plans are ahead to for the expanded phase of the project.

In November, BP announced that three appraisal wells drilled in 2019, GTA-1, Yakaar-2 and Orca-1, targeted a total of nine hydrocarbon-bearing zones. The wells encountered gas in high quality reservoirs in all nine zones, the company said.

So, it is quite a mixed grill in the MSGBC.

Woodside’s return to the region is a story that signifies the complexity of events in Northwest Africa.

Australia’s largest oil company bought into the Sangomar oil field development project and became operator, as if, despite its withdrawal from Chinguetti, nine years earlier, it could not bear to witness any other company take the glory of operating the first oil field in the region since then.

The field development has been sanctioned. Phase 1 of the Sangomar FDP will target an estimated 231 MMbbl of oil resources from the lower, less complex reservoirs, and an initial pilot phase in the upper reservoirs. Woodside has executed the purchase contract for the FPSO facility and issued full notices to proceed for the drilling and subsea construction and installation contracts, including to MODEC, Inc. for the purchase of an FPSO with an oil processing capacity of 100,000 bbl/day, to Subsea Integration Alliance for the construction and installation of the integrated subsea production systems and subsea umbilicals, risers and flowlines and Diamond Offshore for two well-based contracts for the drill rigs Ocean BlackRhino and Ocean BlackHawk.

All seems set, such that, by 2024, offshore Senegal and Mauritania would likely be hosting two floaters; an FPSO producing, mainly, crude oil and an FLNG exporting natural gas.

That would be 10 years after the discovery of Sangomar.

This article was initially published in the January-February 2020 issue of Africa Oil+Gas Report, the monthly journal.

Insecurity and No Diversity of Supply

By Gerard Kreeft

Security and Diversity of Supply: Two golden rules of the energy sector, have been dashed.

The new credo is ‘Insecurity and No Diversity of Supply’.

What started as an oil war between Saudi Arabia and Russia to gain or maintain market share has produced uncertainty and destabilization across the entire energy sector. Add the corona virus to the mix and you have the perfect storm.

How long will traders and end users tolerate such a situation? Yes, traders on the spot market can gain a few windfall moments but in the long term this disruption could herald an established entry for renewables. End users want stability and more now than ever are willing to pay a small premium to ensure stability of their fuel supply.

How will this volatility affect Africa? Here’s a place where the oil majors have key assets and control major portions of the value chain; where little attention has been given to renewable energy.

Here’s a continent which the World Energy Outlook 2019 forecasts to have unprecedented growth in the next 20 years.

In its “Stated Policies ScenarioThe World Energy Outlook 2019 declares that energy demands woud rise by 1% per year to 2040. Low-carbon sources led by solar photovoltaics (PV) supply more than half of the growth, and natural gas, boosted by rising trade in LNG accounts for another third. Oil demands flatten by the 2030s and coal use edges lower. The key is “the momentum behind clean energy technologies is not enough to offset the effects of an expanding global economy and growing population. The rise in emissions slows but with no peak before 2040, the world falls short of shared sustainable goals.”

A second scenario entitled “Sustainable Development Scenario” maps out a way to meet sustainable energy goals in full, requiring rapid and widespread changes across all part of the energy system. These scenarios are fully aligned with the Paris Agreement by holding the rise in global temperatures to well below 2 0C and pursuing efforts to limit it to 1.5 0C.

Back to the Future

Prior to the ensuing energy dispute, the “Sustainable Development Scenario” might have sounded like a birthday wish. Something to give you a feeling that your good intentions will indeed save the planet. And then get on with the business on hand. Now the future has arrived and in harsh terms. Do we really think that the oil majors will act as a white knight and come to the rescue? Pursuing projects with the hope of adding on some symbolic renewable energy projects? The real fear is not changing from fossil-based fuels to renewables. Rather it is the fear of not being to see or totally fathom how a renewable future will look. We should have no illusion about the state of paralysis of the oil and gas sector.

According to a recent study by the Institute for Energy Economics and Financial Analysis the largest oil and gas companies for years have lived beyond their means and paid more money to investors than they can reasonably afford. Analysis found that the five largest Big Oil majors — Exxon Mobil, Chevron, Royal Dutch Shell, BP and TOTAL— spent $536Billion on shareholder dividends and stock buybacks since 2010 while bringing in just $329Billion in free cash flow.

“The oil majors are consistently under-performing the market and may believe that shareholders won’t notice, as long as they receive generous dividends,” said Tom Sanzillo, co-author of the report and director of finance for the institute, a think tank that supports renewable energy. “As these companies continue to sell off assets and acquire more debt, they reveal a sector in disarray.”

This study covers the period of the last oil bust from 2014 to 2017, when a lot of companies limited their reductions in dividends in buybacks — as revenues fell more sharply — to stop investors from abandoning their firms. BP also was a shrinking company during most of the last decade, selling off many assets after the 2010 Deepwater Horizon tragedy in the Gulf of Mexico.

Rystad is predicting that if the price of oil remains at the $30 level this could lead to cuts of $100Billion production and exploration budgets. In 2021 there could possibly be cuts of another $150Billion, leading to bankruptcies in the oilfield sector.

Africa’s Requirements

The World Energy Outlook 2019 notes that under “the Stated Policies Scenario”, the rise in Africa’s oil consumption to 2040 is larger than that of China, while the continent also sees a major expansion in natural gas use.

WEO-2019 continues:” The big open question for Africa remains the speed at which solar PV will grow. To date, a continent with the richest solar resources in the world has installed only around 5 gigawatts (GW) of solar PV, less than 1% of the global total. Solar PV would provide the cheapest source of electricity for many of the 600Million people across Africa without electricity access today.”

By 2040 Africa’s urban population is slated to grow by more than half a Billion, much higher than the growth seen in China’s urban population between 1990 and 2010. China’s production of steel and cement sky rocketed. Africa’s infrastructure will probably not follow this course but the energy implications for the urban growth will be profound. For example, air conditioning or other cooling services.

Total external debt for sub-Saharan Africa jumped nearly 150% to $583Billion in 2018 from $238Billion ten years earlier, according to the World Bank. This could become unsustainable as the average public debt increased from 2010-2018 to 59% GDP up from 40%.

The World Bank has operations of some $20Billion on the continent, while the African Development Bank has commitments of some $10Billion. Both banks have a wide variety of financing tools at their disposal for a variety of projects: be that wind, solar, or geo-thermal. Yet the problem is not one of financial engineering nor technical competence. Both banks have these resources available.

Rather what is required is the vision and strategy to create an African Energy Transition Roadmap coordinated by the World Bank, African Development, IMF and Africa’s national governments. Such a roadmap should also include public-private partnerships in order to leverage project economics, Instead of a Joseph’s coat of many colours in which only regional, national or project interests are featured. Such a roadmap should meet the criteria of the “Sustainable Development Scenario” set out by WEO 19. Certainly when the energy value chain is being totally re-invented its time to make the quantum jump to bring Africa to the frontline where economic innovation and technical breakthroughs are being done.

Gerard Kreeft,  BA ( Calvin University, Grand Rapids, Michigan, USA ) and  MA (Carleton University, Ottawa, Ontario, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. He writes on a regular basis for Africa Oil+Gas Report.

OB-OB: First Gas Flow Pushed to 1st Quarter 2021

The schedule for completion of Obiafu-Obrikom to Oben (OB3) gas pipeline has been pushed further again, as a crucial part of the construction has been taken from one of the key contractors and handed over to others, who now have a global pandemic to deal with.

The 127 kilometre facility, under construction in Nigeria since 2013, is an important, grid length evacuation infrastructure, meant to deliver gas from the rich reservoirs in the eastern Niger Delta to the established markets in the west of Nigeria. On completion, it will enable the first major outline of a national gas grid.

Nestoil’s inability to run a 48 inch pipeline in a 60 inch hole under a riverbed spanning 2.8 kilometres, compelled the Nigerian Gas Transmission Company NGTC, the state firm sponsoring the project, to hand over that aspect of the operations to China Petroleum Pipeline Construction Company (CPPCC) and Brentex Petroeum Services, which is primarily a manufacturer of pipes.

Over the course of a full year between late 2018 and 2019 Nestoil attempted five times to run the fat pipeline under the riverbed, and for those five times, the formation collapsed. The mode of operation is ‘Directional boring’, also referred to as’ horizontal directional drilling (HDD)’, a minimal impact trenchless method of installing underground utilities.

The CPP has since imported equipment for the job, but the material had been held up in the Lags Ports for over three weeks, with Port officials unwilling to allow evacuation of the material, citing Coronavirus concerns.

All of which means that the target of completing the OB3 in June 2020 has failed, as other commissioning operations have to take place after the river crossing part of the project is done.

Nestoil was contracted to construct the 48” x 64.5 kilometre section of the OB3 pipeline from Omoku in Rivers State, to Umukwata in Delta State. The company said, in January 2019, that the project was 90% complete, and that it was looking to deliver it before the end of the year. But Nestoil has also lamented that its scope on the project spans the most challenging terrain of the pipeline. “Most of our 64.5 kilometre length runs through seasonal swamps, which are virtually impassable during the rainy season. In the past few years, average rainfall recorded in the Southern parts of Nigeria has increased steadily, resulting in unprecedented floods, especially in Rivers and Delta States”, Ernest Azudialu, Nestoil’s Chief Executive, told Africa Oil+Gas Report. “These flooded areas makes it almost impossible for appreciable work to be done during the rainy season”.

Engineering sources close to the project tell Africa Oi+Gas Report that Nestoil could invest more effort and tools in delivering the project and that NGTC could have exerted more oversight on the company’s operations. The depth of boring the HDD equipment, the sources argue, could have been deeper tan Nestoil appeared willing to go, and the contractor could have been targeting more compacted formations that would not readily break apart. Again, there have been observations that there were not always alternative rigs at the ready when one failed. Azudialo’s contention is that Nestoil is “constantly investing and improving our lot”.

The success or failure of the OB3 has ramifications for expansion of the domestic gas market in Nigeria.

In fact, its completion was a condition precedent for Final Investment Decision of some Domgas projects. It also provides alternative links to the Nigerian Southwest, whenever the crucial Escravos Lagos Pipeline system fails, as it often does.

This story is an updated version of the article that was published in the December 2019 edition of the Africa Oil+Gas Report, the monthly journal.

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