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Plain Luck or Sheer Grit? Tony Attah Leaves NLNG After Construction Starts on Train 7

Section: Petroleum People · July 21, 2021 · 1 comment |

Tony Attah leaves the Nigeria Liquefied Natural Gas Ltd at the end of August 2021, close to two years after having delivered on the most crucial item on his to-do list; leading the company to a Final Investment Decision (FID) on the seventh LNG Plant (Train).

He is handing over the reins of the Chief Executive Officer job to Phillip Mshelbila, the former GM Gas at Shell Nigeria, who is currently rounding up a cross posting and experience broadening term as Managing Director of the Atlantic LNG Company of Trinidad and Tobago.

The NLNG Train 7, as the project is called, will produce 8Million Metric Tonnes Per Annum Per Year for the global market. It will increase Nigeria’s total LNG capacity to 30Million Metric Tonnes Per Year (30MMTPA). Groundbreaking ceremony for the construction was celebrated on June 15, 2021, and completion is expected by late 2024 or early 2025.

Attah, a mechanical engineer by training, who was previously Managing Director of Shell Nigeria Exploration Producing Company SNEPCo, is the only CEO from an IOC background, working in Nigeria, who has delivered a project of that magnitude in the country last five years. The cost of Train 7 is around $10Billion. Attah is, first and last, a Shell employee, who was seconded to the AngloDutch major’s third largest Liquefication Plant in the world. (Shell’s 26.5% equity in NLNG Ltd, translated to an entitlement of 5.3MMTPA from the company in 2020, which in turn meant 15% of Shell’s total 35.6MMTPA for the year).

To get at 8MMTPA, the NLNG Ltd will liquefy around 1.1Billion standard cubic feet of gas every day. That is one-seventh of Nigeria’s entire natural gas output. The NLNG’s extant 22MMTPA capacity valourises 3Billion standard cubic feet of gas per day, or 42% of the country’s total gas production.

Tony Attah took the reins of NLNG Ltd, nine years after the last Liquefaction Plant (Train 6) came on stream. Before him, two Chef Executives had worked to get Train 7 project off the ground, with some traction, but not visible success.

There were issues to do with the several options before the NNPC, the government’s 49% investor in the project. As of 2008, the cash strapped state hydrocarbon company was considering investments in two other LNG projects: the 5MMTPA Brass LNG and the 10MMTPA Olokola NLNG. By 2012, the government was zeroing in on Brass LNG, while NLNG’s Train 7 had quietly rolled off the burner. In 2015, a new government, formed by a new political party, came to power and looked far more favourably at Train 7.

“I have just received the key, that key will unlock Train-7. Train-7 will be real,” Attah said at the formal hand-over ceremony between him and his predecessor, Babs Omotowa, in September 2016. It was a loud affirmation, expressed, not in the closed, if cozy, confines of the boardroom, but in the public space.

Still the project had to be financed, even if the government was keen. “NNPC is on the average about 57% of the JV upstream”, Attah told Africa Oil+Gas Report’s Kish Onwunali in the NLNG Ltd’s office in Abuja, in September 2018. And as all the major gas supply partners (Shell, TOTALEnergies, and ENI) were junior partners to NNPC upstream, “the funding challenges were really around the equity funding of the NNPC element because the IOCs are responding”, he said. “In order not to allow anything stop us, we have come up with a framework to work with the government to look at possibilities that would include perhaps, a forward sale payment and go into agreement with government to just be sure that the supply is properly financed. And I think we are not far off. We recently signed an MOU with NNPC on funding but overall, the project itself will have to be financed and the NLNG Ltd side of it is never the issue because that will rise on our balance sheet”.

Fast forward, a full year and four months after that conversation: FEED is done, finance is ready, Local content compliance ticked off; more suppliers signed on than the current four (Shell, TOTALEnerigies, ENI, Niger Delta E&P), now including Sunlink and Oando; more LPG production committed to the local market; some LNG volume committed to domestic off-takers and yes, FID is taken.

A year and six months after FID, Attah superintends the kickstart of construction of the largest midstream hydrocarbon project in West Africa and a month later, the board of NLNG announces his exit. It’s the stuff of a dream.

PIB: 3% of Nigeria’s Oil Industry OPEX, around $500Million, is Adequate for Hostcom Development, Say Oil Industry Leaders

Section: In the news · July 16, 2021 · No comments |

By Fred Akanni, in Warri

Nigerian oil Industry leaders are reacting to agitations that 3% of Operating Expenses (OPEX) of companies licenced to operate on any hydrocarbon acreage be paid into a Host Community Trust Fund for the communities around the subject acreage, as mandated in the current draft of the Petroleum Industry Bill, is too low.

“I believe there is too much uninformed noise”, says Joseph Nwakwue, retired ExxonMobil Petroleum Engineer, former President of the Society of Petroleum Engineers (SPE), and former special assistant to the Minister of State for Petroleum Resources. “This provision is to provide direct benefits to the host community. It needs to be at a level that does not significantly increase the unit OPEX. We had estimated the impact on cost of operations and hence profitability of the upstream. I really believe 2.5% would work”.

The Petroleum Industry Bill (PIB) is close to final passage at both the House of Representatives and the Senate. But whereas the Senate has passed “the conference committee report in which 3% of companies OPEX in the last calendar year is retained for Host Community Trust Fund”, the House of Representatives stepped down the bill after an hour long, rowdy closed-door session assessing the committee report, as lawmakers from Bayelsa, Delta, and Rivers States, the country’s largest hydrocarbon producers, opposed what they consider a low contribution into Host Community Development.

Elected legislators representing the Niger Delta region at the House of Representatives, are championing 5% of the total operating expenses (OPEX) over 3%. The Niger Delta hosts over 99.9% of all hydrocarbon currently produced. The Dahomey basin, located in the country’s southwest, produces less than 1% of the nation’s output. No other sedimentary basin has contributed to the national production since first oil in 1958.

But those who routinely pay close attention to value creation in oil and gas activity, have a nuanced view.

“3% of OPEX, currently being paid to the Niger Delta Development Commission (NDDC) for the region’s development is estimated at about $500Million annually”, says Taiwo Oyedele, Fiscal Policy Partner and Africa Tax Leader at PwC, the global firm of consultants. “Unfortunately, this has not had any meaningful impact due to mismanagement. My view is that 3% of OPEX for host community development is a fair percentage given the need to make investment in the sector attractive and viable”, Oyedele explains. “I expect that the governance structure as proposed under the PIB will ensure that the funds deliver concrete results and if this is sustained, the amounts available will increase as more investments are attracted. It may also provide a compelling basis for NDDC to be scrapped and the contributions added to the Host Communities”.

The governance structure for Host Community Fund that Oyedele refers to in the PIB, is fairly rigorous. Unlike the payment to NDDC, the PIB mandates clear guidelines on governance of the funds, which, unlike NDDC, are to be locally applied, not granted “globally” to state governments. The draft of the PIB says that the Board of Trustees of Host Community Trust Fund, to be set up by the oil company/ies “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 oil ompany/ies; 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 oil company/ies. 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 assessments”.

Oyedele says: “I do not think the agitation (for 5% or even more of the OPEX) is warranted. More focus should be on the judicious utilisation of the 3% for Host Community in addition to 3% for NDDC and 13% Derivation for the oil producing states. All together these funds are capable of transforming the region and providing opportunities for the people”.

Africa Oil+Gas Report asked five Chief Executives of indigenous companies, all of them demanding not to be named. Two did not respond. Two of them nodded in preference of 3% of OPEX for the Host Community Trust Fund. The third said he could live with 5%.

Still, there is one industry leader who supports even higher percentages of OPEX than the two bands that members of the National Assembly are bickering about. “Beyond a 10% OPEX allocation, I would support a 10% equity participation in the lease”, argues Nedo Osanyande, a widely respected geoscientist, former General Manager of Sustainable Development and Community Relations at Shell Nigeria, and fellow of the prestigious Nigerian Association of Petroleum Explorationists (NAPE). “In the absence of equity participation, I’d support a 10% OPEX allocation”, he says. “Importantly, a sizeable part of this must be spent (at least initially) in community capacity development in managing this fund. Currently, the social organisation capacity is lacking. This is the reason the funds allocation so far – however inadequate – has not been judiciously utilized”.

Mr. Osanyande says that “with the right social organization capacity, financial resources captured by elites, strong men, and the like would be reduced. Thus far, such capture results in the funds not being invested in the communities”. Arguing that everyone one gains if the communities are happy, he concludes that “hydrocarbon production could easily double, and OPEX costs halved if the hydrocarbon producing communities are happy”.

But Mr. Osayande’s figures are not popular among his colleagues.

Says a consultant geoscientist who has worked on virtually every draft of the Petroleum Industry Bill since 2008: “Actually the 3, 5 or 10% would have been unnecessary if prior initiatives (13% Derivation, 3% NDDC, 8% Littoral State Allowance, Amnesty payments as well as Niger Delta Ministry mandates) have worked half as expected. They all have not worked because of implementation failures. Some of them are even now being copied as best practice in other countries where they are well implemented”.

Mozambique Ready to Receive Southern African Troops in Cabo Delgado

Section: Gas Monetization · July 16, 2021 · No comments |

Jaime Neto, Mozambique’s minister of National Defence, says that everything is ready to receive the troops of the Southern African Development Commission (SADC), who are expected in the country to help fight terrorism in the gas rich province of Cabo Delgado.

Islamic insurgents have killed hundreds of people and turned thousands to refugees in the towns and villages located in the province and close to the Afungi Peninsula, where the TOTALEnergies operated 13 Million Metric Tonnes Per Annum Liquefied Natural Gas project is sited.

In late March 2021, just when TOTALEnergies’ workers returned to site in Afungi to continue construction, Islamic insurgents made their most sweeping attack on the neighbouring Palma town.

“They want to intimidate us”, President Filipe Nyusi, Moazmbique’s head of state, and government said in a speech two weeks after the incident, declaring war. “Following the attack on the town of Palma, the situation in Cabo Delgado has received a lot of national and international attention. All of this attention is legitimate,” the President said. “This town and the adjacent Afungi peninsula are close to the natural gas deposits. It is in this region where the foundations for the exploitation of this resource so important to our economy are being laid. The town serves as the basis for construction works and provides logistical support for works underway in Afungi. So it is that Palma has, in recent years, experienced a rapid evolution in terms of infrastructure, including hotels, banks, and service providers. The Afungi peninsula is also the locus of various other constructions, such as camps and residential areas with access roads and its own aerodrome.”

TOTALEnergies pulled out its workers after that attack and Mozambique has since been looking for a way to permanently root out renewed attacks. Part of the effort was to call on member countries of the Southern African Development Commission (SADC) to provide military assistance.

Mr. Neto, the Defence minister, denies information about the postponement of the arrival of the regional force, due to alleged procedural issues on the part of Mozambique.

“There are already officials in Mozambique who are dealing with the arrival of this SADC intervention force”, the minister explains.

The journal Club of Mozambique quotes Neto as saying that there is no reason, from Mozambique’s point of view not to have the military intervention. “We are prepared”.

Egypt’s Red Sea Resort to Generate 5MW from Solar PVs

Section: ENERGY TRANSITION · July 14, 2021 · No comments |

The management of Soma Bay, a holiday Resort on the Red Sea in Egypt, has inked a set of agreements with TAQA Power to install solar photovoltaic (PV) facility on the resort.

The first part is a PPA (Power Purchase Agreement); stipulating TAQA Power to invest in building and operating a PV station with the capacity of 3.8 MW, over the course of a 9-month period, and on the land owned by Somabay.

Subsequently, TAQA Power is entitled to a concession management agreement of the solar power station for 30 years. The second part of the agreement is an EPC Contract “Engineering, procurement, and construction”; where in TAQAPower is to design, deliver and install another PV station, with a 1.2 MW capacity, and then transfer its management to Abu Soma Touristic Development (ASDC). The total contracted capacity of both stations is up to 5 MW.”

“TAQA Power’s agreement with Abu Soma Touristic Development counts as a model for utilizing renewable energy and capitalizing on its economic value,” says Samy Abdelqader, TAQA Power’s Cheief Executive officer.

Somabay is one of Red Sea’s most prominent coastal destinationand one of Africa’s most sought-after tourist sites. The 10 million square metre peninsula south of Hurghada, which harbors an exquisite recreational sandy beach along its 11KM coastline, says a statement on the website of Abu Soma Touristic Development, which manages the bay. “Our primary objective is to generate the power required using solar energy to reduce electricity and water desalination cost, thereby closing the gap between our consumption and distribution demands.”

The Greening of BP- Phase 2: Becoming an Investment Vehicle?

Section: ENERGY TRANSITION · July 13, 2021 · No comments |

Helge Lund, BP’s Chairman of the Board, is perhaps ideally suited to take BP to its next challenge: the first super-major to become an investment vehicle which is both green and can guarantee shareholders a handsome return on investment.

Lund is a veteran of oil and gas politics, having served as Equinor’s CEO for 10 years, and CEO of British Gas before it was taken over by Shell. As Board Chairman of BP, he is chartering BP’s green future. Not only has he overseen the company’s transformation to becoming greener, he is in the process building an investment structure, which now requires only a few skilled accountants. The company has either sacked employees or will be delegating BP’s headcount to its joint ventures. The goal is becoming lean and mean, reducing costs and hopefully increasing margins. What to

date has happened?

What BP Promised

In 2020, BP painted a glowing portrait for its shareholders of how it would reach the promised green land:• An underlying EBIDA (Earnings before interest, depreciation and amortization) of between 5% – 6% per year through to 2025 with returns in the range of 12% – 14% in 2025 – up from around 9% today.• After allowing for the impact of divestments, and reflecting the expected share buyback commitment, EBIDA per share is expected to grow by 7%- 9% per year through to 2025.• From 2025 onwards, when its low carbon projects start to kick in, expect growth of between 12%- 14% to be maintained.• BP has announced it wants to reduce its oil production by 2030 by 40%. • According to BP, its $25Billion divestment will provide the basis for up-scaling its low-carbon business. A pipeline of 25 oil and gas projects, and additional 18 projects in the pipeline are also key

factors.• BP also announced that it would be spending $5Billion per year to green itself and

by 2030 will have 50GW of net regenerating capacity. To date the company has a planned pipeline of 20GW of green generating capacity.

To date, BP has taken the following green steps:

BP and Ørsted announced that they will jointly develop a full-scale green hydrogen project at BP’s Lingen refinery in Germany. The two firms intend to build an initial 50MW electrolyser and associated infrastructure, which will be powered by renewable energy generated by an Ørsted offshore ‎wind farm in the North Sea and the hydrogen produced will be used in the refinery.‎

BP and Equinor revealed that BP would become a 50% partner, of the non-operated assets Empire Wind(Offshore New York State) and Beacon Wind (Offshore Massachusetts). BP and Equinor will jointly develop four assets in two existing offshore wind leases located offshore New York and Massachusetts that together have the potential to generate power for more than two million homes. BP is to pay Equinor $1.1 billion for interests in the existing US offshore developments and to form astrategic partnership to pursue other offshore opportunities together in the fast-growing US market.

Most recently, BP joined Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership – in which BP, Statkraft and Aker Offshore Wind will each hold a 33.3% share – will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area. According to the consortium SN2’s favourable location provides power export access to local and adjacent markets. The consortium also intends to explore opportunities to provide clean power to electrify offshore oil and gas facilities.

BP is to purchase 9GW of solar development projects in the US from independent US solar developer 7X Energy. The acquisition represents a significant step towards developing its net renewable generating capacity to 20GW by 2025 and to 50GW by 2030.

Finally, BP and ENI have stated that they will be merging their assets in Angola into a joint venture, possibly with a view to also bringing in other African assets. This could include:

Algeria, where BP has helped to deliver two major gas developments at Salah Gas and In Amenas, both of which are joint ventures with Sonatrach and Equinor.

BP currently produces, with its partners, close to 60% of Egypt’s gas production through the joint ventures the Pharaonic Petroleum Company (PhPC) and Petrobel (IEOC JV) in the East Nile Delta as well as through BP’s operated West Nile Delta fields.

In Mauritania and Senegal, BP and its partners are developing the Greater Tortue Ahmeyim gas field with a 30-year production potential. The field has an estimated 15Trillion cubic feet of gas and is forecast to be a significant source of domestic energy and revenue.

What will happen to BP’s 20% share in Russia’s Rosneft which comprises three oil and gas joint ventures? Maintaining a presence in Russia could be very strategic, given the country’s oil and gas assets and the fact that a green strategy is still waiting to be discovered.

The New Energy Players

The speed with which BP has unveiled its strategy indicates that it wants a seat at the green table,occupied by the new energy elite-Engie, Enel, E-on,Iberdrola, Ørsted, RWE, and Vattenfall- who have pole positions in determining the direction of the global renewables market. Is BP’s $5Billion per year investment to green itself and its goal of 50GW net regenerating capacity by 2030 enough to warrant it a place at the green poker table? Perhaps a starting position, but hardly enough to be classified a heavy-weight, green poker player! Consider the competition:• Engie: in 2021 will spend €11-12Billion on investments across a broad swath of sectors including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and will have 33GW of global renewable installed capacity by 2021.• Enel: strategic plan outlines total investments of €190Billion by 2030 and tripling renewable capacity to 145GW. • Ørsted: by 2030 will have installed capacity of 50 GW. • Iberdrola: in the period 2020-2025, will be spending €75Billion on renewable energy and has a pending target of 95GW of installed wind capacity.• RWE: by 2022 RWE will have 28.7 GW of installed wind and solar capacity.• Vattenfall: In the Nordic countries Vattenfall has low emissions with practically 100% of the electricity produced based on renewable hydro-power and low-emitting nuclear energy.

Then there is the paradigm that BP and the other majors have to face: an oil company becoming an energy company. The oil company strategy: high risk = high returns being replaced by high risk= low/no returns.

New energy companies by contrast- Engie, Enel, Iberdrola, Ørsted, RWE and Vattenfall- all are low risk: their dividends are competitive with the oil majors. Iberdrola has a 5% dividend planned for 2021, and Enel paid 5.15% in 2020, and Engie 4.77% in 2019. Their stock prices are steady and positive. Their green strategy has been delivered, in place and accepted by the investor community.

It should not be surprising that the investor community is wondering how a transformed BP can become an energy company promising to deliver results that other energy companies can only dream about: an EBIDA per share of between 7%- 9% per year through to 2025 and from 2025 onwards when low carbon projects start to kick in growth of between 12%- 14%.

Answers may start to appear more quickly than we realize.

Charles Donovan, Director of the Centre for Climate Finance and Investment at Imperial College and lead author of a recent study released by Imperial College and the IEA (International Energy Agency) found that renewable energy investments are delivering massively better returns than fossil fuels. The study(May 2020) analyzed stock market data to determine the rate of return on energy investments over a five-and 10-year period.

Renewables investments in Germany and France yielded returns of 178.2% over a five year period, compared with -20.7% for fossil fuel investments. In the UK, also over five years, investments in green energy generated returns of 75.4% compared to just 8.8% for fossil fuels. In the US renewables yielded 200.3% returns versus 97.2% for fossil fuels.

Green energy stocks were also less volatile across the board than fossil fuels, with such portfolios holding up well during the turmoil caused by the pandemic, while oil and gas collapsed. Yet in the US which provided the largest data set, the average market cap in the green energy portfolio analyzed came to less than a quarter of the average market cap for the fossil fuel portfolio—$9.89Billion for the hydrocarbons versus $2.42Billion for renewables.

Speaking to Forbes.com, Donovan said “The conventional wisdom says that investing in fossil fuels is more profitable than investing in renewable power. The conventional wisdom is wrong.”

Conclusions

That BP has taken the step of becoming an investment vehicle is a bold and radical step and could create a number of exciting investments. BP’s strategy is in place. Now the implementation.

The various joint ventures could provide new possible investment options, given the decentralized decision-making and shorter lines of communication.

BP’s strategy is one being developed and watched by the other majors. How long can the other majors including ENI, Equinor, Shell, and TOTALEnergies continue to balance the various investment balls in the air, hoping to fund both their exploration and development assets and their renewables? This can continue for a short time but ultimately more strategic decisions have to be made. More crossovers between the oil majors and the new energy players. Also, more mergers downstream. In short, a total revamp of the energy value chain.

The oil majors have helped propagate their own myth that fossil fuels yields are indeed better than renewables. With BP proclaiming it is now an energy company the company may have a lot of explaining to do to convince its shareholders that their return on investment and their golden dividend can be guaranteed.

Is not BP’s strategy to become a partner with Equinor in its US offshore wind projects, and their decision to partner with Ørsted at BP’s Lingen refinery in Germany to produce hydrogen the most visible evidence that the energy value chain is starting to produce new alliances?

In Africa, the BP-ENI joint venture could set off a series of mergers and acquisitions among the other majors and national oil companies. Perhaps with a new strategy in place renewable energy in Africa headed by the majors may become a serious part of the mix.

Finally, do not be surprised that the BP’s Net Zero Scenario of reducing fossil fuels to 20% of today’s share of primary energy by 2050 becomes a reality. The urgency of the task ahead is virtually a guarantee that this BP scenario will happen sooner rather than later. 2030 and not 2050 could become BP’s new deadline to become CO₂ neutral.

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

IFC Provides $20Million For Solar Hybrid Systems in Nigeria

Section: ENERGY TRANSITION · July 12, 2021 · No comments |

The International Finance Corporation (IFC), is providing $20Million in financing for Daystar Power’s expansion project in Nigeria. The company installs solar hybrid systems for commercial and industrial customers.

Half of the money is a loan from the IFC-Canada Renewable Energy for Africa Programme. The other $10Million of the funding is being provided as a local currency (naira) loan directly by the IFC.

Lagos-based Daystar Power installs hybrid solar systems for commercial and industrial customers. These installations allow companies to have electricity, despite load shedding. These small hybrid solar power plants also allow its beneficiaries to reduce their dependence on generators, which are often the only alternative to the instability of Nigeria’s national power grid.

With this particular funding, Daystar says of the $20Million, “we are gaining more than just capital. IFC brings a deep understanding of renewable energy projects and project financing in emerging markets,” says Jasper Graf von Hardenberg, CEO and co-founder of Daystar Power.

In January 2021, Daystar Power raised $38Million from the French fund STOA Infra & Energy, Proparco, the subsidiary of the French Development Agency (AFD) group, and the American bank Morgan Stanley. The solar hybrid system provider also received $4Million from the German Investment Corporation (DEG) for its Ghanaian subsidiary. In all, Daystar Power has raised $62 million since the beginning of the year for its expansion in sub-Saharan Africa.

ENI Signs on Plans to Produce Hydrogen in Egypt

Section: ENERGY TRANSITION · July 12, 2021 · No comments |

Italian explorer ENI has signed an agreement with the Egyptian Electricity Holding Company (EEHC) and the Egyptian Natural Gas Holding Company (EGAS) to assess the technical and commercial feasibility of projects for the production of hydrogen in the country.

The parties will conduct a study into joint projects to produce green hydrogen, using electricity generated from renewables, and blue hydrogen, through the storage of CO2 in depleted natural gas fields.

The study will also analyze the potential local market consumption of hydrogen and export opportunities. In addition, possible development and business schemes will be evaluated to implement the selected projects.

The agreement is “part of the path that ENI has undertaken to reach the target of eliminating Scopes 1, 2 and 3 net emissions (Net GHG Lifecycle Emissions) and cancelling out the relative emission intensity (Net Carbon Intensity) by 2050, referring to the entire life cycle of the energy products sold”, the company says in a release. “It comes in the framework of Egypt’s strategy for energy transition, diversifying energy mix and developing hydrogen projects in cooperation with major international companies.

ENI is the largest hydrocarbon producer n Egypt. It has been present in the country since 1954 and operates through the subsidiary IEOC Production.

ENI’s Latest Ghanaian Discovery: Eban will Reach First Oil Before Pecan Field

Section: In the news · July 10, 2021 · No comments |

Italian explorer ENI has said it will fast-track the development of its latest discovery in Ghana by hooking it up to a Floating Production Storage and Offloading (FPSO) vessel, located eight kilometres away.

On July 6, 2021, ENI announced Eban, its second discovery on the CTP Block 4 since the Akoma discovery, made in May 2019, and declared that “due to its proximity to existing infrastructure” the Eban-Akoma complex“ can be fast-tracked to production with a subsea tie-in to the John Agyekum Kufuor (JAK) FPSO, with the aim to extend its production plateau and increase production”.

The JAK FPSO is producing 56,000Barrels of Oil Per day and 130Million standard cubic feet of gas from the Sankofa-Nyame, located in the Offshore Cape Three Points (OCTP) block. “The Eban discovery is a testimony to the success of the infrastructure-led exploration strategy that Eni is carrying out in its core assets worldwide”, ENI says.

ENI has preliminarily estimated the potential of the Eban–Akoma complex between 500 and 700Million barrels of oil equivalent in place. The Eban – 1X well is sited approximately eight (8)kilometres Northwest of Sankofa Hub, where the JAK FPSO is located. It was drilled by the Saipem 10000 drillship in a water depth of 545 meters and reached a total depth of 4179 metres(measured depth). Eban – 1X proved a single light oil column of approximately 80metres in a thick sandstone reservoir interval of Cenomanian age with hydrocarbons encountered down to 3949metres (true vertical depth).

If the complex is hooked up as indicated, even if that takes 24 months, its crude and gas will reach the market before the peak of development of the Pecan field, an ultra-deep-water project operated by Aker Energy, which has been in fast-track mode since 2019. The Pecan field, which lies in 2,400 metre water depth in Deepwater Tano Cape Three Points (DWT/CT) block), was earlier held by HessCorp., an American explorer. It was acquired by Aker Energy in June 2018. First oil from the field was expected in the fourth quarter of 2021, but the consequences of COVID-19 has thrown the plans overboard.

ENI says that its new discovery has been assessed “following comprehensive analysis of extensive three dimensional (3D) seismic datasets and well data acquisition including pressure measurements, fluid sampling, and intelligent formation testing with state-of-the-art technology”. The company explains that its “acquired pressure and fluid data (oil density and Gas-to-Oil Ratio) and reservoir properties are consistent with the previous discovery of Akoma and nearby Sankofa field”, and “the production testing data show a well deliverability potential estimated at 5,000BOPD, similar to the wells already in production from Sankofa Field.

“The estimated hydrocarbon in place between the Sankofa field and the Eban-Akoma complex is now in excess of 1.1 Billion BOE and further oil in place upside could be confirmed with an additional appraisal well”, the European major explains. The Joint Venture of CTP Block 4 is operated by Eni (42.469%), on behalf of partners Vitol (33.975%), GNPC (10%), Woodfields (9,556%), GNPC Explorco (4,00%).

South Sudan Launches First Oil and Gas Bid Round

Section: Farm in, Farm Out · June 23, 2021 · 4 comments |

By Foluso Ogunsan, Upstream Correspondent

South Sudan has announced the launch of its first Oil Licensing Round, aiming “to welcome back experienced partners and operators following significant progress in returning to peace and stability”, the country’s Ministry of Petroleum says in a release.

With new data, analysis, and government mechanisms, the Ministry seeks to attract high-quality investors and partners.

“Potential investors are now able to request all relevant information from the Ministry of Petroleum until August 23^rd 2021, by expressing their interest and providing contact details online at www.southsudanlicensinground.com”, the statement explains.

“Once the expression of interest process is concluded, the Ministry of Petroleum will host a virtual series of data presentations, followed by an international roadshow”.

There are thirteen open acreages, in the country, out of a total of 21, but this particular round is offering five (5) tracts, namely A2, A5, B1, B4 and D2, with areal sizes ranging between 4,000 and 25,000km², and most comprising between 15,000 and 20,000 km². This means there eight (8) “free” acreages, but the Ministry doesn’t say whether these could be negotiated for, even if they are not in the round.

“This bidding round is for a number of selected blocks, which will be facilitated and evaluated based on set criteria by the MoP”, the Ministry says.

South Sudan’s upstream hydrocarbon activity has been dominated by Asian companies, notably China National Petroleum Corporation and Petronas, respectively from China and Malaysia. They produced, in partnership with South Sudan’s government owned Nile Petroleum, about 139,000Barrels of Oil Per Day in 2019, according to the BP Review of Statistics, the industry bible for country-level oil and gas production figures. As these firms themselves are state hydrocarbon companies, South Sudan can certainly do with private and publicly listed companies from the West and the Middle East.

Below are further details from the South Sudan’s Ministry of Petroleum regarding the bid round:

Currently there are three consortiums operating producing blocks in South Sudan, with another four oil exploration companies having acquired production sharing contracts.

1. Producing Blocks:

• Block 3 and 7 – DAR Petroleum Operating Company: China National Petroleum Corporation, Petronas, Nile Petroleum Corporation (8% equity)

• Block 1, 2 & 4 – Greater Pioneer Operating Company: China National Petroleum Corporation, Petronas, Nile Petroleum Corporation (5% equity)

• Block 5A – Sudd Petroleum Operating Company: Petronas, Nile Petroleum Corporation (8% equity)

2. Awarded Exploration Blocks:

• Block B3 – Oranto Petroleum, Nile Petroleum Corporation (10% equity)

• Block 5B – Ascom, Nile Petroleum Corporation (10% equity)

• Block B2- Strategic Fuel Fund, Nile Petroleum Corporation (10% equity)

3. Free Blocks:

• Blocks: A1, A2, A3, A4, A5, A6

• Blocks: B1, B4• Blocks: C1, C2

• Blocks: D1, D2• Blocks: E1, E24.

First Licensing Round:• Blocks A2, A5, B1, B4, D2

Potential investors are now able to request all relevant information from the Ministry of Petroleum until August 23^rd 2021, by expressing their interest and providing contact details online at www.southsudanlicensinground.com

They can also contact directly:
For information about data access and purchase:
Pawel Ulatowski
Director, ZDS
southsudan@zebradata.com

For information about geoscience:
Dr. Omar B. Abu-elbashar
MD, Petro-Tec
petrotec@hotmail.com
petrotec@petrotec-int.com

“After years of instability and conflict, lasting peace is finally gaining a foothold in the country following the establishment of the Transitional Government of National Unity (TGNU) in February 2020, and the follow-up agreement over governance of the country’s states. South Sudan is now firmly back on a positive developmental path and is expected to continue as one of Africa’s fastest-growing countries in the foreseeable future”.

Tim Woodall Walks Out on FAR

Section: Petroleum People · June 21, 2021 · No comments |

FAR has announced Timothy Woodall’s resignation from its Board, one day to his proposed re-election as a director.

The exit, announced by the company June 21, 2021, was “effective immediately”.

Mr. Woodall has been a Director since August 2017 and an Executive Director since September 2019.

He was FAR’s commercial director, overseeing the company’s upstream asset sales and purchases and overall deal making.

Prior to taking executive role at FAR, Woodall, an Australian national, was managing director of Miro Advisors for six years, chief executive of oil and gas technical consulting firm RISC and chief financial officer of New Orleans based intermediate E&P company, Energy Partners.

His resume says he has worked as an executive director in the energy division at UBS’ London offices and spent three years in the Credit Suisse oil and gas team in New York. He was also head of corporate development at Woodside Energy, Australia’s largest E&P firm.

FAR said of Woodall’s decision to quit: “As a result of Mr.Woodall’s resignation, the resolution to re-elect Mr. Woodall as a director (Resolution 2) to be voted on by shareholders at the Company’s Annual General Meeting has been withdrawn. The Annual General Meeting will be held tomorrow, 22 June 2021. FAR advised on 7 May 2021 and in the Notice of Meeting dated 21 May 2021 that Mr. Woodall’s executive role would cease on 2 July 2021”.

Construction Starts on Mozambique’s Cuamba Solar-Battery Project

Section: ENERGY TRANSITION · June 17, 2021 · No comments |

United Kingdom-based Globeleq has commenced construction on the 19MWp/15MWac Cuamba Solar PV plant with 2MW/7MWh battery storage in the Tetereane district of Cuamba, Niassa province, Mozambique.

Source Capital, the private equity firm is involved in the $32Million project. So is the Electricidade de Moçambique (EdM). The project is aimed at bolstering the country’s northern grid, including upgrading the existing Cuamba substation.

Cuamba will be the first independent power producer in Mozambique to use energy storage.

Power will be sold through a 25-year power purchase agreement signed with EdM in September 2020.

The project is being strongly backed by the Private Infrastructure Development Group (PIDG)’s Emerging Africa Infrastructure Fund, which is looking to provide $19Million debt and the project will also receive a $7Million viability gap funding grant from PIDG and a $1Million grant from CDC Plus to reduce the tariff and finance the storage system.

Spain’s TSK is the engineering, procurement and construction contractor. Globeleq will oversee construction and operations of the plant.

Jubilee, TEN Deliver 120MMscf/d of Gas to Ghana’s Atuabo Plant

Section: Gas Monetization, Others · June 17, 2021 · No comments |

By John Ankromah, in Tema

Tullow Oil has announced that its oilfield production performance in Ghana “continues to be supported by reliable gas offtake from the Government of Ghana”.

That offtake, from Jubilee field and the TEN cluster of fields, “is regularly averaging between 110 – 130MMscf/d”, the company says in its latest operational statement.

This is a far more upbeat news about gas production than Tullow has had in the last two years.

It suggests that the Ghanaian economy is absorbing an increasing volume of natural gas. In late 2019, Tullow had lamented that “Gas export from both fields has been limited in 2019 due to low demand from the Ghana National Petroleum Company (GNPC)”, which is the offtaker.

“Discussions on increasing gas offtake are ongoing with GNPC with an increase anticipated towards end of 2019. Sustaining increased levels of gas offtake will reduce the amount of gas being reinjected into the fields, improving oil production over time”, the operator explained.

The gas that Tullow supplies to the Ghanaian government is delivered unprocessed from the two FPSOs (Kwame Krumah for Jubilee and John Atta Mills for TEN) through 12-inchpipelines to the Ghana National Gas Corporation (GNGC) controlled Atuabo plant, which has a processing capacity of 150MMscf/d. Processed gas is evacuated from Atuabo plant through a 20-inch 111km pipeline to (primarily) Volta River Authority’s Thermal Power Stations.

Nigeria’s Producers Are Generally Non-Compliant with Oil Spill Regulations, Data Shows

Section: HEALTH, Others, SAFETY AND ENVIRONMENT · June 17, 2021 · 1 comment |

By Bunmi Christiana Aduloju

NAREP Fellow

Since oil was first discovered in Oloibiri, in Nigeria’s Bayelsa State in 1956, communities hosting the hydrocarbon reservoirs in the Niger Delta have had to put up with devastating oil spills. Biodiversity has suffered from harm done to it by the continual flowing oil in the region.

An integral part of oil spill clean-up and remediation is oil stoppage. This practice aims to close off oil spills as early as possible. The faster the response to oil spills, the likelier the cushioning of its effects and so ideally, the journey to oil spill clean-up should begin in twenty-four (24) hours.

In Nigeria, under the law, oil spills must be stopped by thefacility operators within 24 hours of being notified of the oil spill, whether the spill was caused by the company’s activities or third-party action. In other words, it is the duty of facility operators to ensure that oil flow is closed off as soon as it is detected.

NEGLIGENCE

However, there are shortfalls in the discontinuation of oil spills at the appropriate time by oil companies, according to data obtained from the National Oil Spill Detection and Response Agency (NOSDRA), the Federal Government oil spill monitoring agency in Nigeria.

An Africa Oil+Gas Report analysis of data obtained from NOSDRA, indicate that a total of 494 oil spill incidents occurred from January 2020 till May 2021.

A further analysis of the time between oil spill incidence and the oil spill stop showed that in 2020 alone, there were about 373 incidents of oil spill.

At the time of filing this report, from January 2020 till May 2021, oil companies failed to stop oil spill within 24 hours of the incident in 110 cases and in 133 cases, oil companies stopped oil spill within 24 hours. In 251 cases, due to missing data in NOSDRA’s dataset, it was not specified when the oil spill was closed off.

Within this timeframe, a total of 26178.34 barrels of oil was spilled by 26 oil companies.

The Shell Petroleum Development Company (SPDC) was the highest offender within this period. In 80 cases, it failed to stop oil spill within 24 hours and in 82 cases it stopped oil spill in 24 hours. Also, SPDC tops the list with the longest response time to oil spill during this period. It stopped an oil spill after 185 days in an incident that occurred due to sabotage at the 28” Bomu-Bonny Trunckline at Alaskiri, Rivers State on the 28th of January, 2020. The oil spill was stopped on the 31st of July, 2020. The impact of the spill was labelled, “Non-leaking and no impact on the environment.”

However, criss-crossing NOSDRA’s data with SPDC’s oil spill report showed that the company did not report this incident in its January 2020 report.

In another occurrence, on the 23^rd of March 2021, which is the second slowest response to oil spill stoppage in the analysed period of January 2020 to May 2021, Shell Petroleum Development Company (SPDC) responded to an oil spill in 20days. The oil spill was caused by corrosion and it affected 3” Imo River Well63T at the Owaza community, Etche Local Government, Rivers State. The impact was labelled, “Dripped of crude oil within right of way.” It was stopped on the 12^th of April, 2020. However, in SPDC’s March 2021 oil spill report, this incident was recorded to have occurred on the 24^th of March, 2021. Additional information by SPDC on the oil spill event attributed the delay to “security concerns.”

The third slowest response to oil spill stop, brought off by Nigerian Agip Oil Company (NAOC), was 16 days, according to NOSDRA. The incident was caused by sabotage at the 16” Tuomo Ogbainbiri Delivery Gas Line at Ayamasa, at EkeremorLocal Government, Bayelsa and the impact was labelled, “Gaseous Emission (Condensate).”

The oil companies who complied fully with the oil spill stoppage timeline of 24 hours from January 2020 till May 2021 are KAMLIK Nigeria Limited, Pipelines and Products Marketing Company (PPMC), PPMC (NPSC) and TOTALUpstream Nigeria (TUPNI), according to NOSDRA’s data.

The companies with missing data during this period are Mobil Producing Nigeria Limited (MPN), National Petroleum Development Company (NPDC), Heritage Energy Operational Service Limited, Enageed Resources Limited, Platform Petroleum Limited, Infravision Ltd Company, Esso Exploration and Production and Production Nigeria Limited, First Hydrocarbon Nigeria, ND Western, Midwestern Oil & Gas Corporation, Neconde and Pan Ocean Oil Corporation Nigeria Limited (POOCN).

CLEANING-UP OIL

Out of the 494 incidents of oil spill recorded from January 2020 till May 2021 by NOSDRA, oil spill clean-up data was recorded scantily for only 40 incidents. First Hydrocarbon Nigeria started cleaning an oil spill after 13 months and 10 days, accounting for the longest response time in the 40 incidents recorded. The incident, caused by sabotage, happened at Isoko-North, Delta State at the NPDC OGINI – Eriemu 10” Delivery Line at Eniagbedhi Owhe on the 23^rd of February, 2021. It started cleaning the oil spill on the 10^th of March, 2021 and ended the clean-up process on the 22^nd of April, 2021.

The fastest clean up response was carried out by NAOC from January 2020 till May 2021. On three occasions, on the 9th of January, 2020, 11th of January, 2020 and the 30th of January, 2020 at the Ebocha 9l Flowline at Mgbede, Rivers State and the 10” Clough Creek/Tebidaba Pipeline at Gbaraun, Bayelsa State, oil spill clean-up was achieved in 24 hours.

SHELL AND ENI

In 2018, Amnesty International, an international human rights organisation, published a report that accused Shell and Nigerian Agip Oil Company (NAOC), subsidiaries of Shell Petroleum Development Company (SPDC) and ENI respectively, of being negligent with oil spill clean-up. Long delays in conducting the Joint Investigative Visit (JIV) to ascertain the extent of damage of the oil spill to the environment, slow response to shutting off the flow of oil, and contradicting evidence pointing to their activities instead of recorded oil spill caused by “third party interference”, are some of the issues raised by the international NGO.

The 2011 United Nations Environment Programme (UNEP) report on Ogoniland reiterated that, “Any delay in cleaning up an oil spill will lead to oil being washed away by rainwater, traversing communities and farmland and almost always ending up in the creeks.”

As with Ogoniland, in Nigeria, communities are at the receiving end of oil spills. Even when Shell Petroleum Development Company, in keeping with the polluter-pays principle, accepted liability for the clean-up of Ogoniland 11 years after the oil spill, the UNEP study revealed that cleaning up Ogoniland could take about 30 years.

OIL SPILL COMPENSATION

According to NOSDRA, sabotage and theft is the highest cause of oil spill in oil producing states.

Consequently, if an oil spill is not caused by the company’s activities, compensation would not be paid to the affected communities. Stakeholders Democracy Network (SDN), a watchdog organisation, in one of its publications titled, International Compensation Systems for Oil Spills in Relation to Reform in Nigeria, stated that the compensation structure for oil spill in Nigeria doesn’t measure up to international standards, as they come with “highly variable rates of compensation and high legal costs.”

Also, it stated that because oil spills instigated by third parties are not compensated in Nigeria, “many communities are blighted by the illegal actions of the few.”

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism. Aduloju is a reporter with Africa Oil+Gas Report.

How OPEC+ Cuts Have Sliced Deep into Nigerian Crude Output

Section: In the news · June 17, 2021 · No comments |

By Bunmi Christiana Aduloju

NAPREP Fellow

The COVID-19 pandemic roiled global markets for most of 2020, and kept down demand for crude oil in the earlier part of the year, nudging the price per barrel of the commodity to as low as $-37.63 on April 20th, 2020, (West Texas Intermediate, an international oil benchmark), for the first time in history.

OPEC+ AGREEMENT

As the demand collapse held up, the Organisation of Petroleum Exporting Countries (OPEC) and its allies, OPEC+, an intergovernmental cartel, reached an agreement on the 9^th of April, 2020, to reduce their crude oil production output in order to rebalance the international oil market. This was the beginning of a journey to periodic cuts of crude oil by member states of OPEC and its allies.

On the 12^th of April, 2020, they finalised the agreement and decided to reduce oil output to 9.7Million barrels per day(9.7MMBOPD) from May 1, 2020 to June 30, 2020. From July 1, 2020 to December 31, 2020, 7.7MMBOPD and a 5.8MMBOPD cut in output from January 1, 2021 to April 30, 2022. The reference point for the calculation of the cut down was the oil production for October 2018.

OPEC is on familiar grounds whenever it takes a decision to modify crude oil production output. According to a Reuters report, the cartel has changed production output 34 times – often exempting some of its member countries from these cuts – from 1998 to 2018.

But this particular cut which started in May 2020 was referred to as the “single largest output cut in history.” With this cut, the oil production in OPEC member countries sank to the lowest in almost 20 years, in the first month of the curtailment.

Prior to this agreement, there had been a price war between Russia and Saudi Arabia which instigated a major oil price crashing the global market. Nigeria, Africa’s giant, being a member country of OPEC, joined in the production cuts.

OPEC+ CUTS AND NIGERIA

In fulfilment of the OPEC+ decision, Nigeria agreed to cut its production to 1.412MMBOPD for May to June 2020, 1.495MMBOPD for July to December 2020 and 1.579MMBOPD for January 2021 to April 2022, based on the reference production of October 2018 of 1.829MMBOPD. These production cuts exclude condensate production which is exempt from OPEC’s output cuts.

These periodical cuts have proven to be an effective mechanism for cushioning the oil glut that pervaded the international oil market in the early months of 2020.

Oil prices skyrocketed with the OPEC cuts. Brent crude oil futures, an international oil benchmark, jumped from as low as $26 on April 20^th, 2020 to as high as $71.49 on June 7, 2021 and WTI price, from as low as $-37.63 on the 20^th of April, 2020 to as high as $69.23 on June 7, 2021.

Oil prices may have increased with the OPEC+ cuts, which is an advantage for oil revenue generation in terms of FX, but “the rising oil prices could also be a curse for Nigeria as it has to pay more because of an operating cost of about $40,” notes Bamidele Samuel, a senior research analyst with one of the big four accounting firms in Lagos.

Compliance or Non-compliance

Nigeria started on a discordant note, in the first month of the curtailment, by complying only partially with its agreed portion of the cut. The country overproduced crude oil in May 2020, with about 1.61MMBOPD, accounting for about 52% compliance.

However, Nigeria promised to make up for the non-compliance by the end of June 2020 or no later than mid-July 2020.

As OPEC+ alliance extended the 9.7Million barrels oil production cut – which was supposed to end in June 2020 – into July 2020 to further rebalance the oil market, again, Nigeria overproduced oil at 1. 49MMBOPD, against its promised 1.41MMBOPD production for July, according to OPEC monthly oil market report.

In the following months until the end of the year, OPEC recorded that Nigeria was mostly compliant with its designated quota of crude oil production.

The country recorded the lowest production output for 2020 at 1.42MMBOPD in December, which was the lowest production level since August 2016, according to OPEC’s report. This was largely due to disruption in production at ten terminals including Yoho, Agbami, Pennington, Qua Iboe and Erha terminals.

OIL PRODUCTION IN NIGERIA

On one hand, Nigeria promised to make up for the OPEC cuts loopholes with condensates, which is not part of the OPEC+ curtailment. Timipre Sylva Minister of State, Petroleum, reiterated that through the respective periods of the OPEC+ cuts, Nigeria would add “condensate production of between 360-460 KBOPD.”

In November 2020, Nigeria urged OPEC to reconsider the oil production cuts designated to Nigeria due to the confusion over the categorisation of Agbami field as condensate or as crude oil.

However, OPEC declined Nigeria’s request with a comment that the production cuts was in the best interest of the international oil market.

With these cuts and other production challenges, Nigeria’s overall oil and condensate production slumped drastically in 2020 to around 1.66MMBOPD in 2020 from 2.04MMBOPD in 2019, according to an S&P Platts analysis, a UK-based market intelligence firm. This was its lowest annual output figure since 2016 when militancy in the Niger Delta pushed output to as low as 1.60MMBOPD.

According to data obtained from the NNPC Annual Statistics Bulletin, total crude oil and condensate production for the year 2019 was 735,244,080 barrels of oil and the daily average production was 2.01MMBOPD. In 2020, however, Nigeria produced 643,938,257 barrels of oil and condensate, the lowest ever produced since 1990, when the production figure was 630,245,500 barrels of oil and condensates.

In January 2020, Nigeria produced 64,260,394 barrels of oil and condensate, representing an average daily production of 2.07Million barrels, the highest in the year and in December 2020, it produced 44,018,411 barrels of crude oil and condensate, with an average daily production of 1.42Million barrels, accounting for the lowest.

Mr. Bamidele Samuel regards the operating cost to the upstream sector – which is around $40 – as a major shortfall for oil exploration and production in Nigeria.

2021 PRODUCTION CUTS

In December 2020, the OPEC+ alliance agreed to increase production by 500,000BOPD, from January 2021. This brought the total production cut for OPEC+ in January to 7.2MMBOPD. This production cut decreased gradually to 7.13MMBOPD in February and 7.05MMBOPD in March 2021 through April 2021. Saudi Arabia, OPEC kingpin, stepped in with a voluntary cut of 1MMBOPD from February 2021 till April 2021.

On April 1, 2020, OPEC+ alliance decided to ease cuts to 5.8mb/d spanning from May 2021 till July 2021.

Some analysts believe that the OPEC+ cuts would continue to go down the slope until April 2022 as the world recovers from coronavirus and the oil glut that accompanied it.

According to OPEC monthly crude oil production data obtained from its secondary sources, in 2021, Nigeria’s crude oil production figures stood at 1.34MMBOPD in January, 1.49MMBOPD in February, 1.48MMBOPD in March 2021 and 1.56MMBOPD in April 2021.

“The fact that Nigeria cannot do as much as an average capacity of 1.9MMBOPD is a challenge, especially with oil prices trading above $70 per barrels,” Bamidele Samuel argues.

“If we are producing more, that is more revenue for the government to stimulate the economy on the part of recovery,” he added.

Russia and Saudi Arabia keep disagreeing on the change in production output. While Russia has been pushing for increase in OPEC+ production output, Saudi Arabia has been more conservative, contending that another wave of coronavirus in India and other parts of Asia, is capable of assaulting demand for crude oil.

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.

FAR Will Spud its Second Well in The Gambia in 4Q 2021

Section: Oil patch Sub-Sahara · June 16, 2021 · No comments |

Australian explorer FAR Limited, says it has locked in the timetable for drilling the Bambo-1 well offshore The Gambia by executing a contract with Stena Drillmax Ice Limited to commence drilling operations in the fourth quarter of 2021.

The Bambo-1 well in Block A2 offshore The Gambia, is designed to drill into three prospects with a total estimated recoverable, prospective resource of 1,118MMBbls (arithmetic sum of the Best Estimates, 559MMBbls net to FAR) and the chance of geological success for the various horizons range from 7% to 37%, FAR says in an extensively detailed release.

“These target reservoirs are: 1. Soloo – The extension of the hydrocarbon-bearing reservoirs in the adjacent Sangomar Oil Field, offshore Senegal. 2. Bambo and Soloo Deep – two additional prospects, not drilled during the Senegal drilling campaigns”, the company reports.

These two prospects carry a lower chance of success but higher volume of hydrocarbons, FAR explains. “The technical assessment of the Bambo Prospect has greatly benefited from FAR’s extensive database and experience in the region and learnings from FAR’s involvement in the 11 successful wells in Senegal and the Samo-1 well drilled in 2018”.

FAR is Operator with a 50% working interest in the A2 and A5 permits with its joint venture partner, PC Gambia Ltd, a subsidiary of Petroliam Nasional Berhad (PETRONAS).

If successful, a discovery could result in a standalone development which would be The Gambia’s first oil production.

Tullow Oil Shifts Focus from Exploration to Production

Section: In the news · June 16, 2021 · No comments |

Tullow Oil will now focus on producing all the oil it has discovered, as well as invest spare cash in hub size, near-term crude oil discoveries, rather than foraging for new oil anywhere.

The Irish company no longer wants to be seen as a leading wildcatter in Africa’s frontier, a description that it wore like a badge up until a few years ago.

“We have shifted our focus away from exploration and development and long-cycle capital commitments to a production focused company with a robust, cash generative business plan”, Rahul Dhir, the Chief Executive Officer, says in a pre-Annual General Meeting statement.

The company’s cash cow remains the assets in Ghana. From January 2021, Tullow is implementing a 10-year business plan “which focuses over 90% of our capital investment in our high margin production assets in West Africa”, Dhir says.

For ‘West Africa’, read ‘Ghana’, as Tullow has sold its stakes in Equatorial Guinea and most of Gabon.

The London listed junior started a multi-year drilling campaign in Ghana, planning to drill four wells in total in 2021, consisting of two production and one water injection well on its flagship Jubilee field and one gas injector well on the relatively less prolific TEN field.

“We have successfully drilled the first Jubilee production well and the Jubilee water injector well, and the reservoirs encountered are in line with expectations. The rig will now carry out the completion of these two wells with tie-in and start-up of both wells expected in the third quarter of 2021”.

The business plan, Mr. Dhir says, “will generate material cashflow to self-fund high return, fast payback investment opportunities and reduce debt – even at low oil prices”.

Dhir’s plan proposes:

• Reducing our cost base: we are delivering cost savings across the business including annual G&A cash savings of $125Million. We are becoming a performance focused organisation where every barrel matters and every dollar counts.

• Improving operational performance: our ongoing operational turnaround is delivering more reliable and consistent operating performance with 98% average uptime year-to-date at Jubilee and TEN and better utilisation of our existing infrastructure.

• Rigorous capital allocation: we are focusing on high return and fast payback investments in our production assets and have significantly reduced capital allocation to long-cycle projects.

• Reducing our debt: We have sold our interests in Uganda, Equatorial Guinea and the Dussafu Marin permit in Gabon, raising over $700 million in proceeds. This asset sale programme puts us well on the way to realizing c.$1Billion over two years through assets sales and cost reductions.

• Simplifying our capital structure: we recently completed a comprehensive debt refinancing which gives us the financial stability to deliver our business plan.

• Strong ESG focus: we announced in March that we aim to become Net Zero (Scope 1 & 2) by 2030 as part of our commitment to sustainability. In addition, we maintain our commitment to social investment and developing local content.

Group production to the end of May 2021 averaged c.62,000 Barrels of Oil Per Day(BOPD), which, Dhir says, is in line with expectations.

“This figure reflects the completion of the sale of our Equatorial Guinea interests on March 31, 2021, with no production from these assets recorded past the first quarter. On June 9, 2021, we announced the sale completion of the Dussafu Marin permit in Gabon and we will adjust our full year guidance to reflect both these divestments in our upcoming Trading Statement on 14 July 2021.

“In Ghana, our operational improvement plan is delivering results with 98% average uptime year-to-date across both the Jubilee and TEN FPSOs. As we have previously stated, reliable gas offtake and water injection are an important part of our strategy to optimise reservoir performance and address production decline”.

A Hybrid Solar and Battery Plant to go up on the Sukari Gold Mine

Section: ENERGY TRANSITION · June 6, 2021 · No comments |

PARTNER CONTENT

Centamin has awarded juwi and Giza Systems the contract to construct the world’s largest solar hybrid project at an off-grid mine for the Sukari Gold Mine in Egypt.

The 36 MW solar farm and a 7.5 MW battery-energy storage system will tangibly reduce CO2 emissions of existing diesel power station. It will also reduce the cost of power, juwi says in a release.

The total project Capital Expense is $37Million but it will lead to between $9-13Million annual savings in diesel cost, Centamin says in a briefing.

juwi is a German renewables energy developer. Giza systems is an Egyptian civil works contractor.

The solar system designed by juwi will maximise generation with bifacial solar PV modules and a single axis tracking system, taking advantage of the high irradiance at site, the developer explains. Juwi Hybrid IQ micro-grid technology will enable the integration of the solar and battery system into the existing off-grid network and support the operation of the existing power station.

The benefits of the hybrid power solution at Sukari include:

• Reducing diesel consumption by an estimated 22Millionlitres-e per year;

• Lowering carbon emissions by an estimated 60,000 tCO₂-e per every year;

• Reduction of all in sustaining costs;

• Reduced exposure to fuel price volatility;

• Increased reliability of the power system.

“The mining industry accounts for 10% of the global energy consumption and many minerals play a vital role for the energy transition. We are glad to support the resource industry on their de-carbonisation pathway with our dependable solar, wind and battery solutions”, juwi adds,

Egypt’s Bus Owners Can Apply for Natural Gas Vehicle Swap

Section: Gas Monetization · June 6, 2021 · No comments |

By Toyin Akinosho

Owners of intercity and intracity buses in Egypt will be able to swap their gasoline powered minibuses for natural gas powered ones, in the first phase of the government’s natural gas vehicle swap scheme starting July, 2021.

A key requirement for this phase is that the vehicles must be older than 20 years old. The scheme will initially be rolled out in Cairo, Giza, Qalyubia, Alexandria, Suez, Port Said, and the Red Sea.

The vehicle swap programme entails private transport companies getting brand new natural gas-powered vehicles for their old mini buses.

The government has also announced that 2,300 Public Buses (owned by governorates and municipalitities) in Cairo and Alexandria will be converted to run on natural gas at a total cost of $77Million (or EGP 1.2Billion), under a joint agreement signed between the ministries of petroleum, local development and military production as well as the public transport authorities of both cities.

Egypt’s plan to displace gasoline and diesel with natural gas, as the country’s default fuel of transportation, had initially scheduled 15,000 minibuses (Egypt’s equivalent of Kenya’s Matatus and Nigeria’s Danfos).

But outside the pulic transport system, the government has now scaled up the planed number of cars to be converted to run on natural gas by 2023, from 250,000 to 450,000 cars.

Egypt’s finance ministry is backing the effort of Taqa Arabia, the country’s largest private sector energy distribution company, in the natural gas conversion scheme. The company, last week, announced the receipt of a $58Million loan from the National Bank of Egypt to help finance the construction of natural gas filling stations. Master Gas, a subsidiary of Taqa Arabia, will use the finance to build 40 new filling stations in a number of governorates, to support the growing shift to natural gas vehicles. Taqa Arabia has indicated it would invest $231Million (or EGP 3.6Billion) in expanding its number of natural gas stations to 180 by 2023. The company says it will spend $51 (EGP 800Million) to construct 40 stations in 2021, $77Million (or EGP 1.2Billion) on 60 stations in 2022 and $102Million (or EGP 1.6Billion) on 80 stations in 2023. Taqa currently operates 23 natural gas stations.

Lekan ‘Remains CEO of Lekoil Nigeria’, Fights Termination by Lekoil Cayman

Section: Others, Petroleum People · June 3, 2021 · No comments |

Lekoil Nigeria, has reacted to the termination of Lekan Akinyanmi’s contract as Chief Executive of Lekoil Limited, the AIM listed company which is actually Lekoil Cayman.

It says that the decision, announced June 3, 2021, is the culmination of the efforts of the consortium led by Metallon Corporation to take control of Lekoil Cayman as foreshadowed in the circular to shareholders of Lekoil Cayman dated 11 December 2020.

Lekoil Cayman had said that the sack of Lekan Akinyanmi, with immediate effect, was due to a corporate governance breach. “The Company will commence a search for a new CEO and, in the interim period, Anthony Hawkins will act as interim Executive Chairman of the Company”.

But Lekoil Nigeria Limited declares, in a counter release: ”Mr. (Lekan)Akinyanmi remains on the Board of Lekoil Nigeria Limited and also its Chief Executive Officer. Mr. Akinyanmi created and executed the vision of an independent indigenous Nigerian energy company that is Lekoil, for this generation and in this emerging market and he has always worked with the best interest of Lekoil shareholders in mind”. It then says that “Lekoil Nigeria remains committed to the vision of developing Nigeria’s energy sector’.

Does it look complicated?

Lekoil Cayman is the investment vehicle which raises money on the Alternative Investment Market (AIM) of the London Stock Exchange, for the property acquired by Lekoil Nigeria. Lekoil Nigeria owns the assets, the more substantial of which are, 40% of the Otakikpo Field onshore (producing roughly 5,500 Barrels of Oi Per Day gross) and 17% equity in the undeveloped Ogo field, in shallow to deep water Benin Basin offshore Lagos. The estimated reserves, unproven is stated as in excess of 500 Million Barrels of Oil Equivalent. Lekoil Cayman has 10% of Lekoil Nigeria in equity, but may have up to 90% of the economic interest. This part is not clear.

Back to the issue at hand.

Lekoil Cayman’s notice of termination had added that Anthony Hawkins became interim non-executive chair only in April 2021, after Michael Ajukwu resigned, after having been in the chair since January 2021.

But Lekoil Nigeria’s response argues that “recent additions to the board of Lekoil Cayman by Metallon Corporation and its collaborators should have been vetted (as is the practice of LekoilCayman) and due diligenced as required by the AIM Rules and as would be normal for listed companies”.

It notes that “seasoned oil sector executives such as George Maxwell, and former directors with deep knowledge of the continent, such as Mark Simmonds, have resigned and been replaced with directors lacking industry expertise, knowledge of the continent, impartiality and objectivity and appointed to secure for Metallon Corporation and its collaborators, the full takeover of Lekoil Cayman”.

Lekoil Nigeria contends that “the procedure leading to the termination of Mr. Akinyanmi’s service is not compliant with the company’s corporate governance policies. Together with the appointment of unvetted new appointments to the board of Lekoil Cayman by the Metallon Corporation consortium, it is clear that the majority of the board of Lekoil Cayman is failing persistently to comply with its corporate governance code, yet the board of Lekoil Cayman determines on this ground to terminate the service of Mr Akinyanmi”.

Conclusion, for now, by Lekoil Nigeria: “While we take legal counsel regarding this decision by Lekoil Cayman, we wish to assure our numerous stakeholders, especially the Nigerian people that the strategic national assets under our purview will be protected by all legitimate means available to us”

Conclusion, for now, by Lekoil Cayman: “Lekoil is the lender under a loan agreement with Mr. Akinyanmi, of which outstanding balance, as of May 31 2021, was approximately $1.5Million. The company will commence proceedings to recover the Loan”.

Dorothy Thompson Eased out of Tullow’s Chair

Section: Petroleum People · June 3, 2021 · No comments |

Tullow Oil plc announced, June 3, 2021, that Dorothy Thompson CBE, Non-Executive Chair, had decided to step down from the company’s board of directors.

She hadn’t spent three years on the seat; having joined the Tullow Board in April 2018 and become Chair in September of the same year.

So, was she eased out or did she leave on her own?

The former, more likely, although Tullow didn’t respond to our query.

At the time of her appointment, Tullow had noted that Ms. Thompson was bringing executive leadership to the table, as well as public company governance and leadership, investor relations, corporate finance, accounting and audit, business development, risk management, technology and innovation.

15 months into her tenure, in December 2019, the company experienced a headlong crash in stock price as a result of poorly managed perception around production challenges in its Ghanaian assets, the jewel in the Tullow crown.

Tullow Board, under Ms. Thompson, saw off the company’s Chief Executive and its ‘legendary’ exploration director, then turned to the shareholders, pleading that the company had failed the market, with hardly any upbeat tone in the messaging.

The statement made too much fuss of the gas offtake in Ghana, which is not one of Tullow’s main revenue earners; it expressed too much worry about Tullow’s debts, which had not yet reached unmanageable territory (no near-term debt maturities), and most crucially, it struggled to show that what had happened in the course of the second to third quarter operations were very minor slips in an otherwise smooth journey. Tullow’s story was far better than was painted in the December 9, 2019 statement. Ms.Thompson had acted, at the time, like someone deeply uncomfortable with the day-to-day risks of the E&P game.

In the view of Africa Oil+Gas Report, the sharp crash in stock price came about as a result of an unnecessary own goal.

Admittedly, Ms. Thompson has done a lot of work in the last one year on strategy. Tullow is laser focused on Ghana now; it plans to invest $2Billion into operations in the country over the next 10 years, hoping to reach peak production of 275,000 Barrels of Oil Per Day (close to double current production) and 150Million standard cubic feet per day from the investment. But the mistakes of 2019 were so expensive and had rattled the company badly. They had also been ill timed: happening unfortunately just before the year of the great crash.

A search process to find a new Chair has been launched and is expected to conclude towards the end of the summer. Ms. Thompson will remain Chair of Tullow until the new Chair is appointed and an appropriate handover has taken place.

Online Conferences on Industrial Valves and Components Come to an End

Section: PARTNER CONTENT · May 31, 2021 · No comments |

PARTNER CONTENT

Over a thousand experts and industry professionals have gathered from all over the world during fifteen online conferences, waiting to meet live at IVS 2022.

Bergamo, 27th May 2021 – IVS WARM UP, the two-day event of technical and scientific conferences featuring the players in the global supply chain of industrial valves and components in virtual meetings, to discuss the most topical and innovative issues in the international debate, has ended.

The epicentre of the digital conferences was the city of Bergamo, where the fourth edition of IVS – Industrial Valve Summit will be held on 25th and 26th May 2022.

Twenty-five speakers, representing as many companies and research centres, led the fifteen conferences of the event attracting, «remotely», over a thousand operators and experts from all continents to Bergamo.

These numbers confirm the centrality that the Industrial Valve Summit represents within the supply chain dedicated to the industrial valve and flow control solutions. The event, promoted by the organisers Confindustria Bergamo and Ente Fiera Promoberg, was organised in collaboration with Valve Campus that has always been the scientific partner of reference of IVS.

”The success of IVS WARM-UP confirms the importance of creating connections and stimulating scientific discussion and insights, maintaining the attention on a key event that promotes a supply chain of excellence, an international point of reference for quality production” says Paolo Piantoni, General Manager of Confindustria Bergamo.

“The conferences have confirmed the value of IVS as a place to exchange knowledge and know-how, even in the digital edition”.

Over the years” Mr. Piantoni explains, “IVS has been an important driver of innovation for the sector, embodying the identity of a territory oriented towards development and projected onto the future. We are already working on the 2022 edition of IVS that will be held at the Exhibition centre at last, a great opportunity to revitalise the industry”.

Fabio Sannino, President of Ente Fiera Promoberg, concurs: “We are satisfied with the results of IVS WARM-UP”, he testifies. “The success of the digital conferences gives us hope for the success of the actual physical event in 2022. Over the years, the summit has positioned itself as our most international and visited event. To open the doors of the Fiera di Bergamo to IVS once again is a crucial step for the relaunch of the entire trade fair system, for Bergamo and for its industrial fabric. Confirming the numbers recorded in the last editions means generating considerable linked activities in favour of the territory, also in terms of visibility»”.

Four different debates marked the event’s programme. Wednesday morning (May 26, 2021), was dedicated to innovation in valve design, control, manufacturing, and materials. In the afternoon, the discussion moved to the management of fugitive emissions and developments in sealing technology. On Thursday, (May 27, 2021), the focus was on actuators and control systems, followed by a discussion on the international standards. At the end, IVS WARM-UP hosted a panel discussion shedding light on the evolution of the global demand for industrial valves and their components in the medium term. On this occasion, participants analysed the influence of the energy transition and new strategies following the pandemic scenario.

In view of IVS 2022, the aim of the Organizers is to continue the growth path of the exhibition as witnessed by the increasing number of visitors, exhibitors and traffic on communication channels. The third edition of the summit attracted over 250 companies and about 11,000 visitors to Bergamo, numbers 36% higher than the 8,000 registered in the 2017 edition and tripled compared to the 3,500 registered in 2015. Access to the fair’s website quadrupled in the months leading up to the exhibition, moving from 70,000 in 2017 to 300,000 in 2019.

The First Storage Project for A Renewable Energy Farm in West Africa.

Section: ENERGY TRANSITION · May 31, 2021 · No comments |

By Femi Adeniyi Taylor

Lekela Power, the independent power producer (IPP), has selected DNV to carry out the feasibility study for its electricity storage project at the Taiba N’Diaye wind farm in Senegal.

DNV has six months to deliver on the study, as Lekela plans to start construction of the electricity storage system in 2022. The Taiba N’Diaye wind farm, which was also developed by Lekela, started feeding electricity into the Senelec grid in 2020. The facility consists of 46 wind turbines capable of delivering 158.7 MW of power. The wind farm contributes 15% of the electricity produced in Senegal.

Lekela is a joint venture between UK investment fund Actis and Mainstream Renewable Power. DNV, a Norwegian firm, will also provide risk management and insurance expertise, supported by a grant from the US Trade and Development Agency (USTDA). DNV will “help develop the technical specifications of the battery storage system to ensure a successful technical solution that will provide services to the grid during its operational life of up to 20 years”, Lekela says in a statement. DNV will also be involved in negotiating the power purchase agreement (PPA) for the storage system between the Senegalese national electricity company (Senelec) and Lekela. This will be the first PPA for storage in Senegal, and potentially in West Africa.

Pending the results of the study, Lekela plans to build a system capable of storing 40 MW of power. The batteries will be housed in 45 40-foot (21 m) shipping containers. These containers will be stored next to the wind farm. The storage system will provide 175 MWh of electricity, enough to stabilisethe national grid.

Oil Majors Won’t Lead Africa’s Transition into Renewables

Section: ENERGY TRANSITION · May 31, 2021 · 1 comment |

By Toyin Akinosho

The oil industry’s major companies are playing a key role in new energy investment around the world.

Anglo Dutch Shell, United States’ Exxon Mobil and Chevron, the UK’s BP, France’s TOTALEnergies,

Italy’s ENI and Norway’s Equinor are all prioritizing their investments in various technologies in the energy mix, even as they reel from the results of hydrocarbon demand destruction wrought by the COVID-19 pandemic.

The majors will construct huge wind farms offshore Europe, install thousands of solar powered turbines in Asia and the Middle east and establish more Biofuel refineries in the Americas, but they won’t do more than a little of these in Africa.

The neglect of investments in renewables in Africa has as much to do with the unwillingness of these large, transnational corporations to get into non-extractive projects whose deliverables are purchased in local currency at the retail-level, as it is to do with the low expectations, minuscule ambitions and little mindedness of the ruling elite on the continent.

The notion that a company like TOTAL, now renamed TOTALEnergies, which is leading in new investments in fossil fuels development in Africa, will also turbocharge its investment in Africa’s Energy Transition, is way over extended.

True, TOTALEnergies is the only oil major which has competed, albeit in an indirect way, in a bid round for renewable energy projects anywhere in Africa. In 2013, its affiliate, the NASDAQ listed SunPower, was selected as the preferred bidder for an 75Megawatt-peak (MWp) ground-mounted solar power project by South Africa’s Department of Energy (DoE). TOTALEnergies owns 27% of the project, along with five partners, while SunPower waschosen to provide Engineering, Procurement, Construction (EPC) services and long-term Operation and Maintenance for the plant, located in Prieska, in the province of Northern Cape. SunPower has also installed two photovoltaic power plants, totaling 33MW, near Douglas, also in the Northern Cape. TOTALEnergies itself is a partner in decentralized rural electrification programmes through Kukhanya Energy Services (KES) in the KwaZulu Natal province. Impressive as they sound, these projects are far shy of 150MW in total capacity and TOTAL’s equity in them is even far less. Plus: SunPower is not exactly a subsidiary of TOTALEnergies. However, SunPower’s contribution in South Africa is significant: it runs a solar manufacturing plant in the country, producing up to 160 megawatts solar panels per year.

As European majors go, ENI compares with TOTALEnergies as a keen explorer and producer of hydrocarbon in Africa’s frontier, but it is hardly excited about investing in future energy in this region.

In January 2021, ENI launched, with fanfare, the installation of a 14 KW solar system in some medical facility in Angola, with the company saying that it “aims to promote renewable energies”. Two months later it inaugurated construction work on a 50 MW photovoltaic plant in the South of Kazakhstan. ENI produces around 100,000BOPD (net) in Angola and its output is trending upwards, as it makes new discoveries; in Kazakhstan, it delivers 111,000BOPD.

ENI’s Egyptian production trounces its Kazakhstan output, but the Italian player has not featured in Egypt’s relatively aggressive Renewable Energy plan.

Meanwhile, the 50MW Solar plant in Kazakhstan is an add-on to a 48MW windfarm the company has constructed elsewhere in that country.

BP IS WRAPPING UP FROM SUB-SAHARAN AFRICA: it is looking to divest from Angola, from which it has extracted over a Billion barrels of oil in the last 20 years. BP operates around 140,000Barrels of Oil Per Day production on Blocks 18 and 31, where it holds 50% and 26.6% equity respectively. It also has stakes in the TOTALEnergies operated Block 17, and ExxonMobil operated Block 15, the two largest crude oil producers in Angola. The company is leaving Angola because it does not fit into its immediate fossil fuel future, which is focused on natural gas. The British major, however, expects to build its home country’s largest Clean Hydrogen Facility: a 1,000MW ‘blue’ hydrogen project. Its investment in low-carbon projects will jump to $3Billion by 2025 and $5Billion by 2030, with major investments planned in bioenergy, hydrogen and carbon capture and storage. BP excludes Africa from all its renewable energy plans, including the proposal to start ‘advising cities on ‘power packages’ with renewables, back-up batteries and financing’ and increase electric vehicle recharging stations by almost tenfold at its retail gas stations from current level of 7,500 to 70,000.

Equinor extracts 120,000Barrels of oil equivalent every day from the Atlantic Ocean on the edge of Angola, down from a peak of over 240,000BOEPD ten years ago. When asked if the country would be part of the company’s renewables portfolio, Nina Koch, Equinor’s CEO in Angola, recently said it all depends on the available concessions. “Whether there is a market for wind, solar and so on we have yet to see. If the government is putting forward concessions for offshore wind farms, for instance, we would definitely be interested in looking into that”. And then the clarity, she allowed: “For the time being, we don’t have any concrete plans for renewables in Angola”.

We have to cut Equinor some slack here. It holds 15% of the total shares of Scatec, a leading Renewable Energy provider in Africa.

Chevron’s focus is not so much about investing in stand alone renewable energy projects, but in increasing renewable power in support of its business to lower its carbon intensity.

The Norwegian energy research company Rystad, told the investment community, in September 2020, that oil and gas majors are actively pruning their oil and gas assets, stating: “The world’s largest oil and gas firms could sell or swap oil and gas assets of more than $100Billion in order to adjust and transform to cleaner sources of energy”.

I can vouch that over 10% of that $100Billion will be cashed out of African portfolios. Shell, for one, will likely take over $7.5Billion out of Nigeria between 2021 and 2025. Shell has funded some offgrid projects through solar power developers in Nigeria, a country that almost represents the sum of all of Shell’s presence in Africa. But the scale of these renewable power interventions is minuscule. To put it in context, Nigeria itself does not have up to 50MW of solar and wind power capacity.

Oil majors are funding clean energy from the balance sheet of dirty fuel. As I was concluding this article, TOTALEnergies tweeted on April 9, 2021: “We’re using oil production to help finance the #energytransition and achieve our ambition to reach carbon neutrality by 2050, a point stressed by our Chairman & CEO @PPouyanne”. Around 30% of TOTAL Energies’ production is in Africa, but less than 0.5% of its new energy investment will directly benefit the continent. And yet, from all analysis, TOTALEnergies is the best African renewable energy investor out of the six oil majors.

This article was initially published in the April 2021 edition of the Africa Oil+Gas Report.

How David Slew Goliath

Section: ENERGY TRANSITION · May 30, 2021 · No comments |

How David the small shepherd boy killed the giant Goliath is an apt metaphor to explain how Africa can muster its position in the global energy transition. The giants of the energy transition-China, Europe, USA-are ready, willing and eager to explain how Africa must act and what Africa should do. Africa is more timid.

In our narrative, the symbolic David is best represented by Carlos Amaral, General Manager of ACREP, a small independent Angolan oil producer. Amaral, no stranger to controversy, has been at ACREP’s helm for 17 years, steering it through the various boom and bust periods.

ACREP has to date carried out 17 exploration wells, costing $150Million, and discovered 7 fields but has only put one in production. By 2024 the company will produce around 7 000 Barrels of Oil Per Day (BOPD).

Recently he talked at length to The Energy Year about how the industry in Angola and possibly how Africa can evolve. In the next 5-6 years Amaral predicts oil production in Angola will plateau at around 1.2 -1.3MMBOPD. Given that a field’s production will decline about 10-12% per year, you would require an additional production of 120 000BOPD to maintain the current status.

Because of low oil prices, the economy and a low level of international oil consumption, no one is going to do any exploration and new production is not expected before 2025. Amaral is in favour of maintaining a lower level of production- 900, 000BOPD -1MMBOPD- to try and take advantage of the oil price and not emptying the reservoir.

According to Amaral “There is no better deal than coming into Angola, investing in a small player like ACREP and making good money. It is good, clean money based on low risk and solid management.”

The voice of Amaral’s ACREP is not an exception and many Davids are present throughout Africa. Many are active in the oil and gas sector. Yet will their voices be heard in the energy transition? Will their voices be seen as a prelude to proclaiming their oil and gas resources as stranded assets? Which help if any can they anticipate?

Oil and Gas in Terminal Decline

The terminal decline of the oil and gas sector was officially recently announced on 18 May 2021 by the International Energy Agency (IEA). Its net zero emissions goal for 2050 means no new oil and gas fields beyond 2050. Simply put, more fossil fuels are entirely inconsistent with reduced emissions. It can be argued that the IEA’s mandate is to monitor and report on energy transition issues, not to initiate and be the lead on such issues. But the die has been cast and the verdict has been declared.

The IEA may have been voicing publicly what was being discussed in the corporate boardrooms of Asia, Europe and the USA and the international agencies such as the International Energy Agency(IEA), World Bank, IMF, and the regional development banks. Yet was the voice of Africa listened to? After all emission levels in Sub-Sahara’s two major petro-economies- Nigeria with .73% and Angola with.25% – are negligible when compared to China’s 28% and the USA’s 15%.

Of course Africa is not indifferent or unaware of the Paris Agreement and its consequences. How well is Africa prepared to be CO₂ free by

2050? What contribution can be anticipated from Africa’s oil and gas sector? Should Africa be given dispensation and consequently more time to rid itself of CO₂ emissions beyond 2050? Would awarding CO₂ dispensation to Africa- in short delegating this to Sub-Sahara Africa’s two major national oil companies- Nigerian National Petroleum Corporation(NNPC) and Sonangol, Angola- be an award for legitimizing incompetence?

NNPC’s operating subsidiary, NPDC(Nigerian Petroleum Development Corporation) has in Africa Oil + Gas Report been referred to as “a massive, incompetent wrecking ball”. NPDC is seen as a bright star within the NNPC’s portfolio. Why? Only because the degree of its performance is in direct proportion with the help it gets from its partnership with private entities.

Sonangol Angola’s state oil company is now only a shadow of what it once was. It has now been stripped of its two key roles: as concessionaire which was a highly judicious key role giving it monopoly power and legitimacy it had achieved and as state oil company with its monopoly responsibilities for exploration and development of oil and gas resources.

In the Angola of today power has become diffused: Sonangol has been stripped of its concessionaire role and is loaded with a mountain of debt; and the IOCs have the freedom to explore and market their natural gas. Developing green energy is certainly beyond the core competence of Sonangol.

If NNPC and Sonangol are perceived of not having their own house(s) in order how can they be expected to be leaders in the Energy Transition? Does it make any sense to give the same driver, who drove the initial bus off the cliff, keys to drive the new bus?

Juggling and Counterbalancing the Assets

In the current low carbon environment, the IOCs (international oil companies) are constantly juggling their portfolios in order to maintain profitability and low carbon emissions. They have no hesitation in abandoning assets which do not meet investor grade. Leaving their national oil company partners scrambling.

Back in September 2020 Rystad, the Norwegian energy research company reminded the investment community that the oil and gas majors are actively pruning their oil and gas assets stating: “The world’s largest oil and gas firms could sell or swap oil and gas assets of more than $100 billion in order to adjust and transform to cleaner sources of energy”.

The Rystad Energy Study, covers a wide geographical spread and includes ExxonMobil, BP, Shell, TOTAL, ENI, Chevron, ConocoPhillips, and Equinor. The eight companies may need to divest combined resources of up to 68 billion boe, with an estimated value of $111 billion and spending commitments in 2021 totalling $20 billion.

The key criteria for determining whether a major oil company would benefit from staying in a country are the company’s cash flow over the next five years, the potential growth in its current portfolio, and its presence in key E&P growth countries towards 2030. Based on this, Rystad claims that majors may seek to exit about 203 varied country positions and, as a result, reduce their number of country positions from 293 to 90.

The latest sign of things to come is a possible merger of activities between BP and ENI in Angola and possibly other regions. A precedent for the BP and Eni merger talks in Angola finds its roots in Norway. In 2018 Vår Energi was created through a merger between HitecVision’s Point Resources and ENI Norge.

With a hurried exit and downsizing of the oil majors in Africa, private and state African oil and gas companies should look to investment vehicles such as HitecVision which can help fill the impending vaccum.

The need for more outside players is very apparent. With the vacated space left by the majors there is room for innovative and indigenous players who can put together deals. Much like what has happened in the North Sea. The majors- including BP and Shell- selling key assets that were bought up by smaller companies who saw new investment opportunities.

Do not expect only oil and gas deals. More likely oil and gas deals with green strings attached which international investors are demanding. And why not? If the international community expects Africa to become green, Africa should leverage its economic muscle: act as an economic bloc and put together an energy roadmap demanding appropriate financial packages.

An energy roadmap must Involve both the private and public sectors. In particular helping the Davids of Africa to expand their businesses and create new opportunities. Certainly this is an avenue that would be welcomed by the IOCs. Private sector financing could prove to help the Davids of the private sectorand be a positive counterbalance to the national oil companies.

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

Net Zero? Not Yet. Africa Must Fight Energy Poverty with Oil and Gas Development

Section: ENERGY TRANSITION · May 28, 2021 · 1 comment |

On May 18, 2021, the International Energy Agency (IEA) released “Net Zero by 2050: A Roadmap for the Global Energy Sector,” which outlines plans for the global energy sector to reach “net zero” greenhouse gas emissions by 2050.

Achieving net zero emissions means the amount of greenhouse gases being emitted into the atmosphere would equal the amount being removed. Achieving this balance, the IEA maintains, would require more than aggressive carbon-capture measures: It would call for a swift and immediate shift from petroleum energy sources to energy provided through naturally replenished sources like wind, water, and solar power.

From an environmental standpoint, this is a great concept.

But we live in reality. And today, in real-world Africa, this goal is not feasible. Nor is it advisable. While I agree with their data on many topics, the IEA’s conclusion is flat-out wrong on this issue. Africa needs oil and gas.

Unreasonable Objectives

Some of the critical steps in IEA’s roadmap include:• No new investment in new fossil fuel supply (including oil and gas) after 2021• No new sales of fossil fuel boilers after 2025• No new internal combustion engine (ICE) car sales after 2035 globally• 60% of car sales are electric by 2030, and 50% of heavy truck sales are electric from 2035.

These steps assume a lot about the state of the world — assumptions that are faulty, especially for Africa. For one, it will require universal energy access by 2030, meaning that everyone has access to electricity and clean cooking. And with approximately 592 Million Africans currently without this access, we’re going to be hard-pressed to flip that switch in less than 10 years.

The IEA’s roadmap to net zero also relies on unprecedented investments in renewables — a substantial boost in clean energy investments from the $1Trillion made over the last five years all the way up to $5Trillion annually by 2030 — and cooperation from policymakers who are unified in their efforts. In this idyllic partnership, our Western counterparts talk a good game. But the fact is, to date, these same Western countries have invested little to no funding into Africa’s renewables space. To our dismay even the International Oil Companies that have tried to accept the IEA’s publicity stunt have little or no renewable projects in Africa.

“For many developing countries, the pathway to net zero without international assistance is not clear,” OPEC wrote in response to IEA’s roadmap release, issuing a “critical assessment” on the very same day. “Technical and financial support is needed to ensure deployment of key technologies and infrastructure. Without greater international co‐operation, global CO2 emissions will not fall to net zero by 2050.”

As I have stated in the past, demonizing energy companies is not a constructive way forward, and ignoring the role that carbon-based fuels have played in driving human progress distorts the public debate. We cannot expect African nations, which together emitted seven times less CO₂ than China last year and four times less than the US, according to the Global Carbon Atlas, to undermine their best opportunities for economic development by simply aligning with the Western view of how to tackle carbon emissions.

Creating New Problems

China, meanwhile, appears willing to continue investing in fossil fuel projects in Africa. This means that to keep their nations energized, African governments will have little choice but to partner with China — whose performance is notoriously poor when it comes to environmental protection, despite having signed the Paris climate accord. In this scenario, China will become the most influential entity in the African oil and gas industry. And giving China (or any foreign entity) such a monopoly is a dangerous play.

For the IEA plan to work, no new oil and natural gas fields would be developed. The potential energy security risk here is twofold: Concentrated production means that demand will exceed the supply of traditional fuels, while new energy security issues emerge related to the new technologies such as cybersecurity and a dwindling supply of rare earth and critical minerals. And energy insecurity brings economic insecurity and geopolitical instability.

At the same time, a ban on fossil fuel production would bring about the collapse of many carbon-dependent governments. The oil industry is the primary source of income for many African nations. Without the continuation of petroleum production — or time and opportunities to cultivate new revenue sources — their economies will suffer — along with their citizens.

Interestingly, the very announcement of this roadmap features an admission by IEA Executive Director Fatih Birol that net zero will unhinge socioeconomic structures.

“This gap between rhetoric and action needs to close if we are to have a fighting chance of reaching net zero by 2050 and limiting the rise in global temperatures to 1.5 °C. Doing so requires nothing short of a total transformation of the energy systems that underpin our economies,” Birol wrote.

And many of the world’s economies cannot bear this.

Excellent Points from Australia

Energy officials from Australia, for example — incidentally, one of the IEA member countries — had plenty to say in response.

“There are many ways to get to net zero, and the IEA just looked at one narrow formula,” said Australian Petroleum Production and Exploration Association chief Andrew McConville. “The IEA report doesn’t take into account future negative emission technologies and offsets from outside the energy sector — two things that are likely to happen and will allow vital and necessary future development of oil and gas fields.”

In urging policymakers to maintain a degree of skepticism about the wisdom of the IEA roadmap, McConville isn’t alone.

“We are bringing emissions down,” stated Angus Taylor, Australia’s Minister for Energy and Emissions Reduction, “but we’re going to do it in a way that ensures we’ve got that affordable power that Australians need.”

Rather than being dictated to by entities abroad, Taylor argued that Australia must proceed at a pace that makes sense locally. And part of these local considerations includes ensuring that people have energy and jobs. The IEA’s call to cease investment in fossil fuels will impede both of these metrics.

“Global gas demand is forecast to grow by 1.5% on average per year out to 2025, providing incentive to ensure our large gas fields … are developed as soon as possible,” said Keith Pitt, Minister for Resources. “Large upcoming offshore developments … will create thousands of new high-wage jobs.”

Africa’s Realities

The same holds true for African countries.

While environmental causes are a major focus in the West, lawmakers in Africa’s developing countries are more concerned with living wages and supplying basic necessities to the continent’s growing population.

The IEA plan amounts to austerity measures that would see Africans leaving petroleum resources in the ground. It would essentially brand poor African criminals — or at the very least enemies of the environment — for using fossil fuels.

This is folly. Let’s keep in mind the critical role that natural gas is playing in the global transition to clean energy: It’s an affordable and reliable bridge to renewables. And natural gas is particularly important to Africa. As I’ve written in the past, the African Energy Chamber’s 2021 Africa Energy Outlook report projects that African gas production and consumption are going to rise in the 2020s. As a result, Africa’s natural gas sector will soon be responsible for large-scale job creation, increased opportunities for monetization and economic diversification, and critical gas-to-power initiatives that will bring reliable electricity to more Africans. These significant benefits should not be dismissed in the name of achieving net zero emissions on deadline. To tell African countries with gas potential like Mozambique, Tanzania, Equatorial Guinea, Nigeria, Senegal, Libya, Algeria, South Africa, Angola and many others that they can’t monetize their gas and rather wait for foreign aid and handouts from their western counterparts makes no sense.

What’s more, we can’t overlook the fact that renewable energy solutions are still young technologies —they are less reliable -and achieving net zero by 2050 would require widespread adoption of technologies that are not even available yet.

Don’t get me wrong: I understand the importance of working toward renewables. I believe they are the future of the energy industry. But the global energy transition must be inclusive, equitable, and just. Unfortunately, the roadmap laid out by the IEA is none of these.

The IEA is a respected institution whose opinions help shape the rhetoric of the global energy market. So instead of mandating these strict guidelines from abroad, the IEA should try working with African countries to find solutions that we can actually abide. At the very least, I encourage the IEA to consider partnerships with African Private sector and financial institutions, whose collaboration with indigenous and international energy stakeholders provides invaluable insight from all sides across the energy industry. The IEA should use its voice to push for what I have always believe Africa needs the most at this time, free markets, personal responsibility, less regulation, low taxes, limited government, individual liberties, and economic empowerment will boost African energy markets and economies.

Africa deserves the chance to capitalize on its own oil and gas to strengthen itself, rather than being bullied onto a path determined by Western institutions that don’t face the same obstacles. We must be able to improve our energy sector by exploring our continent’s full potential in a way that benefits our people.

OML 118: NNPC, SNEPCo, Others Sign Multibillion Dollar Deep-Water Agreement

Section: Farm in, Farm Out · May 27, 2021 · No comments |

…Deal to Yield Over $780Million in Immediate Revenues to Government.

The Nigerian National Petroleum Corporation (NNPC) and its Production Sharing Contract (PSC) partners -Shell Nigeria Exploration and Production Company (SNEPCo), Total Exploration and Production Nigeria Limited (TEPNG), Esso Exploration and Production Nigeria Limited (EEPNL) and Nigerian Agip Exploration (NAE) – have executed agreements to renew Oil Mining Lease (OML) 118 for another 20 years.

The five agreements signed include: Dispute Settlement Agreement, Settlement Agreement, Historical Gas Agreement, Escrow Agreement and Renewed PSC Agreement.

The NNPC, in a statement, says that over $10Billion of investment would be unlocked as a result of the agreements, which, it argues “signaled the end of the long-standing disputes over the interpretation of the fiscal terms of the Production Sharing Contracts (PSC) and the emplacement of a clear and fair framework for the development of the huge deep-water assets in Nigeria”.

Mele Kyari, the corporation’s Group Managing Director, estimates that “the deal would yield over $780Million in immediate revenues to the Federal Government while it would also free the parties from over $9Billion in contingent liabilities”.

Bayo Ojulari, the Managing Director of SNEPCo, contends that the agreements marked the end of a twelve-year dispute that had marred business relationship and affected trust and investment. “Today, we have signed agreements that define the future of deep-water for Nigeria. This is the first deep-water block that was developed in Nigeria and it is also the first one that we are resolving all the disputes that will lay the foundation for the resolution of other PSCs,” the SNEPCo helmsman stated.

OPAC Refinery: “We Thought We Were the First in Nigeria”

Section: Refining Gap · May 25, 2021 · 1 comment |

By Foluso Ogunsan and Akpelu Paul Kelechi, in Lagos

The OPAC (Modular) Refinery, located in Kwale, in the Niger Delta basin, has taken so long (Four years) from conception to completion, largely because of the bureaucracy of constructing a hydrocarbon processing facility in Nigeria, in the opinion of Momoh Jimah Oyarekhua, the refinery’s CEO.

“We had various issues, because we were more or less like pioneers, we had to fight for waiver and that meant going through processing, going through the Ministry of Petroleum, going through the Ministry of Finance, going through Customs. At some point it was now gazetted by the Presidency,” Oyarekhua discloses. “While we were waiting for waiver, which took us eight months, we had some of our equipments stolen at the port. Our intention was to complete the refinery by the end of 2018, or maybe if it spills over, in 2019. But we had some of our equipment missing, some of that equipment had to be reproduced, which opened us to cost because we were at the forefront”.

Oyarekhua’s use of words like “pioneer” and “forefront” would suggest that the OPAC Modular refinery is the first in the country. In truth, as the 10,000BOPD OPAC refinery undergoes commissioning stages, there are already, on ground, two such facilities fully functional: the Niger Delta E&P (NDEP) owned, three- train 11,000BOPD Ogbele Refinery in Ogbele, in Rivers State and the Waltesmith Petroman owned 5,000BOPD Ibigwe refinery in Imo state, on the eastern flank of the Niger Delta basin.

But this is how Mr. Oyarekhua frames his narrative of OPAC being a pioneer:

“When we were conceiving the idea of this refinery, (in 2017), I truly would say that I did not know any other refinery existed in Nigeria. When we asked around we were only aware there was a one thousand barrel a day topping plant owned by NDPR stripping out the gasoil in their crude. When in 2017 were thinking of actually building a Modular Refinery. Before then, there were licenses and all that. It began to dawn on us that there was a space that we could play”.

Records at the Department of Petroleum Resources (DPR), the country’s regulatory agency, indicate that the ‘authority to construct’ (ATC) a refinery was only granted to Waltersmith Petroman in March 2017, whereas OPAC refinery received its own ATC, six months after, in September 2017. It’s also true that, as of that time, NDEP was only running its first train, a 1,000BOPD (crude oil to diesel) topping plant-a valid refinery itself no doubt- but had not been granted licence to increase the complexity of the unit to the 11,000BOPD refinery it is running today. DPR records show that ATC for NDEP’s second train 5,000BOPD refinery and third train 5,000BOPD refinery, were both granted in December 2018.

From DPR’s records, then, Oyarekhua’s claim of being a pioneer, despite “meeting” two refineries on ground, is not necessarily wrong.

But OPAC had other challenges that ensured the facility’s delay in delivery.

“This project is financed by equity, there isn’t debt. When there are variations, we go back to the drawing table trying to raise money. It’s different from the WalterSmith one that government through NCDMB gave money and all of that. Our models are different, we could be struggling at some point, but they already had everything well worked out”.

The full interview with Momoh Jimah Oyarekhua, CEO of OPAC Refinery, can be read in this link.

Local Refining Can Consume $Billions of Scarce Nigerian Forex

Dana Gas Needs Financing Partner to Drill “Thuraya”, Offshore Egypt

Section: Farm in, Farm Out · May 24, 2021 · No comments |

PARTNER CONTENT

Dana Gas the UAE based minnow, is hoping to drill a “key” prospect in its operated Block 6, offshore Egypt, in 2023.

But the operator, strapped for cash, needs a well-heeled partner to co-finance the probe.

The subject is the Thuraya prospect in the block, which is also known as North El Arish Concession.

Dana Gas is offering a material interest in Block 6 to a company willing to fund the planned Thuraya well, recently estimated likely to cost $95Million (dry hole). “A $90Million cost recovery pool, which is fully recoverable under Egypt’s profit-sharing fiscal regime, can also be shared with an incoming party. Operatorship is available to suitably qualified companies”, says a statement by marketing agents for the prospect..

Dana Gas is in the process of securing an extension to the current 2nd Exploration Period after unavoidable delays incurred during the seismic data acquisition and the COVID pandemic. Together with the optional 3rd Exploration Period of two years, this will secure the license area for three years enabling the well obligation to be drilled by mid-2023.

Envoi, the British acquisition and divestment advisor which the company hired to recruit suitable farminees, frames the situation as an “opportunity to participate in drilling of dual (stacked Oligocene & Cretaceous) play in ‘Thuraya prospect’, testable with one well”.

Envoi says that Thuraya is close to proven play analogues (including cretaceous reef in Zohr Field to the north andOligocene clastics in Ameeq and Nour discoveries to the west).

Envoi says the Thuraya prospect holds estimated combined ‘Mean’ Potential of 17+ Trillion cubic feet (Tcf) of Gas Initially In Place (GIIP) and 37 Tcf Upside (‘Mean’ 11+ Tcf and 24Tcf Upside recoverable resources) “where a discovery of only 2+ Tcf would be commercial”.

“Although large carbonate reef prospects are recognised where local basement highs occur in the region (now also including Block 6), the Oligocene sand potential, proven in the Nile Cone by the Salamat and Atoll fields since 2013, has only recently been recognised as a primary play target in the eastern part of Egypt’s offshore nearer to Block 6”, Envoi notes in its briefing.

“Its potential here has been unlocked by the Nour and Ameeq discoveries made in 2019 and 2020 just 20km to the west of Block 6. This Tertiary play fairway is, however, defined by regional seismic amplitude mapping, which clearly show that extensive basin floor fans originated from the Nile Delta. These have prograded through time to the north and east. These delta floor and prodelta complexes progressed into the Levant Basin and through the Block 6 area during Oligo-Miocene times.

“Today the Miocene is also a proven reservoir in the very large (22Tcf) Leviathan and Tamar Fields to the north east which are interpreted as the younger more distal extension of the same sediment system that passed through Block 6 with similar resource potential, and where it remains undrilled”. Envoi’s briefing contends.

“The majority of the mapped Cretaceous and two distinct Oligocene closures that overlie it in the Thuraya prospect are now confirmed to lie mostly within Block 6 by the new Broadband 3D survey completed in 2020. 3D seismic as well as shipborne gravity and magnetic data was acquired right up to the maritime boundary to define the edge of the Thuraya prospect after the earlier block-wide 2015 3D survey was not permitted to cover the border area.

“Combined, these two plays in the Thuraya prospect are now estimated to be capable of an un-risked ‘mean’ in-place potential of 17Tcf GIIP (and P10 upside of over 37Tcf GIIP) with a ‘mean’ recoverable resource potential of over 11Tcf (and P10 upside of 24 Tcf recoverable), based on conservative volumetric inputs. The commercial threshold for a development in the area is calculated to be around only 2Tcf recoverable, hence a discovery in either the clastic or reef plays would be highly attractive commercially. The full combined mean resource potential in the Thuraya field of over 11Tcf is calculated to have an NPV10 value of $2,2Billion with an EMV of $1Billion. Block 6 also has material follow-on prospectivity, including the same stacked Oligo-Miocene play in three undrilled prospects which combined could add around 7 Tcf to the Block 6 recoverable resources. The potential value of this opportunity and the Thuraya prospect on its own should not be underestimated. Egypt’s self-sufficiency, with declining domestic gas production, is only expected to be able to fully support demand until around 2025”.

Funding is the Challenge for Ugandan Government’s Stake in Refinery

Section: Refining Gap · May 24, 2021 · No comments |

With the conclusion of agreements to launch the upstream and midstream segments of the Lake Albert development project, discussions are shaping up around financing close for the 60,000BOPD.

The government holds a 40% participating interest in the refinery. The Uganda National Oil Company (UNOC) is taking up the biggest shareholding in the project through one of its subsidiaries, the Uganda Refinery Holding Company (URHC), on behalf of the state. “We have a role together with the refinery consortium in ensuring that the refinery makes a final investment decision in 2022, in accordance with the timelines of the Project Framework Agreement”, says Proscovia Nabbanja, CEO of UNOC.

The Albertine Graben Refinery Consortium, which holds 60% of the project, consists of General Electric (GE), Yaatra Ventures LLC, Intracontinent Asset Holdings and Saipem SPA.

The refinery is expected to come on stream between 2024-2025. “There’s a lot of work being done today, such as the environmental and social impact assessment and the front-end engineering design”, Ms. Nabbaja explains. “We are also working with the Ministry of Finance to secure financing for our equity in the refinery”, she notes.

But the Ugandan government is stretched thin. In the last five years, it has expended close to $2Billion on infrastructure, to equip the country to handle the oilfield project, which will see over 10 fields in the Hoima district producing 230,000BOPD at peak.

“Without financing you can only do so much”, Nabbanja says.“If you are going to play as a contracting party or partner within the agreements, then you must have the financing”.

She says that Financing is not only for UNOC’s equity participation; “to deliver on your strategy, you must have a good target operating model and you must have resources for it. Internally, we have defined the financing needs for UNOCoperations to make ourselves field-ready and capacitated for that time when we actually get into execution mode for the projects”.

Aker Energy Looks to Farm Down in DWT/CTP

Section: Farm in, Farm Out · May 24, 2021 · No comments |

Aker Energy is looking to sell part of its 50% participating interest in the Deepwater Tano Cape Three Points (DWT/CTP) block in Ghana, which includes the Pecan development project.

After the COVID-19 wreckage, the Norwegian operator has struggled to come up with the funding for the Pecan development,which it sounded so passionate about just 18 months ago.

Aker Energy’s demonstrated passion to fast track the development project led to the Ghanaian government’s amendment of Petroleum Agreements concerning the DWT/CTP and the South Deep Water Tano (SDWT), an amendment which significantly reduced the state’s share of the partnership and snuffed out the involvement of GNPC Explorco, a company that was set up to build operating capacity of the state hydrocarbon company GNPC.

But Aker Energy appeared to walk the talk. As far back as February 2020, the operator had entered into a Letter of Intent (LOI) with Yinson Holdings Berhad to award a bare-boat charter and an operations and maintenance contract for a floating, production, storage and offloading (FPSO) vessel at the Pecan field, following a competitive tender. The plan was that the contracts would have a firm duration of ten years followed by five yearly extension options exercisable by Aker Energy as operator on behalf of the license partners. Once developed and installed, the FPSO will be located over and connect to the state-of-the-art subsea production system located at approximately 2,400 metres below sea level.

Now, all of that enthusiasm has been considerably challenged by the economic downturn of the last one year.

Aker Energy’s other partners in the DWT/CTP block are Lukoil (38%), Fueltrade (2%) and Ghana National Petroleum Corporation (10%).

ENI and BP to Explore Combining Angolan Interests into New Joint Venture

Section: In the news · May 19, 2021 · No comments |

BP and ENI have entered into a non-binding memorandum of understanding (MoU) to progress detailed discussions on combining their upstream portfolios in Angola, including all their oil, gas and LNG interests in the country.

The companies believe that combining their efforts in a new joint venture company would bring significant opportunities for them to jointly boost future developments and operations in Angola. In particular, it would be expected to generate significant synergies, create more efficient operations, and increase investment and growth in the basin. The new venture would reflect both companies’ commitment to continue developing the upstream sector potential of Angola.

The new company would be supported by Eni and bp, benefitting from the competencies and personnel of each, and would be expected to be self-funded. A business plan for the company would be agreed by bp and Eni to allow it to capture future opportunities in exploration, development and possibly portfolio growth, both in Angola and regionally.

HSE performance, project delivery and production efficiency will be priority areas for the management. The companies’ social investment commitments in the country will continue to be honoured.

BP and ENI have informed the Angolan Government of their intention. Any final transaction will be subject to relevant Governmental, regulatory, and partner approvals.

The companies have appointed advisors that will support the companies in raising finance for the new joint venture.

ENI is operator of block 15/06, and exploration blocks Cabinda North, Cabinda Centro, 1/14 and soon 28 and is also operator of the New Gas Consortium (NGC). In addition, Eni has a stake in the non-operated blocks 0 (Cabinda), 3/05, 3 / 05A, 14, 14 K / A-IMI, 15 and in Angola LNG.

BP is operator of Blocks 18 and 31 offshore Angola, and has non-operated stakes in blocks 15, 17, 20, and soon 29. bp also has non-operated interests in the NGC and Angola LNG.

Cameroon Formally Grants an Extension for the Thali Licence

Section: Farm in, Farm Out · May 19, 2021 · No comments |

AIM listed minnow, Tower Resources, has now received formal confirmation from Cameroonian authorities, extending the First Exploration Period on the Thali PS Licence.

The formal “arrête” from the Minister of Mines, Industry and Technological Development (MINMIDT) MINMIDT extends the First Exploration Period to 11 May 2022.

“This formal extension allows the Company to proceed with finalising a schedule for drilling and testing the NJOM-3 well”, Tower claims. “We are looking forward to seeing the NJOM-3 well drilled as soon as possible, and we will have more news for investors about the schedule in due course.”

Tower Resources had declared Force Majeure in March 2020 in respect of the First Exploration Period of the PSC, in light of the restrictions required to combat the COVID-19 pandemic, and on 31 March 2021 the Company announced that the President of the Republic had also approved a formal extension of the First Exploration Period.

But this announcement is about the formal grant of the extension.

“We are once again grateful to the Republic of Cameroon and to the Minister of Mines, Industry and Technological Development and his staff for their continued support of the Thali project, and also to the President of the Republic, the Secretary General of the Office of the Presidency, and the Prime Minister for taking a direct interest in our activity, as well as all the staff at the Societé Nationale de Hydrocarbures who have supported us during this First Exploration Period”, Tower Resources says.

Equinor’s Algerian Output Drops, Company Inks Agreement with Sonatrach

Section: Farm in, Farm Out · May 18, 2021 · No comments |

Norwegian explorer Equinor, which saw its output drop by 25% in Algeria in 2020, has inked a forward looking, cooperation agreement with that country’s state hydrocarbon firm.

The memorandum of understanding (MoU) between Sonatrach (the Algerian state company) and Equinor, is looking beyond hydrocarbon exploration and production in the country.

“The signing of the MoU strengthens the existing partnership between Equinor and Sonatrach”, Equinor says in a release.

Equinor has been in Algeria for 17 years, with positions in two developments and one rank exploratory tract, including stakes in the In Salah onshore gas development, the In Amenas onshore gas development and a partnership on exploration in the Timissit licence.

The company’s equity production in the two producing projects crashed from 55,000BOEPD in 2019 to 41,000BOPD in 2020.

Equinor’s release says that the MoU “includes cooperation within greenhouse gas emissions and carbon management, industrial safety management, implementation of technology to increase hydrocarbon recovery and development of a model for driving high-performance oil operations”.

Will Nigeria’s LPG Demand Buckle under the Weight of the Country’s Forex Problems?

Section: GAS COMMERCIALISATION · May 18, 2021 · 1 comment |

By Bunmi Aduloju, NAREP Fellow

…Some say that growing in-country LPG production should mitigate these concerns, but..

When Vitalis Obinna, an LPG retailer and dealer in gas cylinders and accessories in Festac Town, a western suburb of Lagos, Nigeria, caught sight of a figure advancing towards his shop, he jumped to his feet with an anticipatory flash of excitement. Surrounded by other LPG retailers at the location, a new customer would mean more sales for the day. Soon, his interaction with this reporter took a turn of business reality.

“Since last year, business has been very dull,” he said. ‘But when the year began, it became really bad. There’s been no profit in cooking gas. We buy gas for about ₦4300 and sell it for about ₦4500.

“Before now, we used to make profit of at least ₦600 on 12.5kg of cooking gas but now, our profit is ₦150 to about ₦200 for 12.5kg of gas.”

Asides a drop in profit, he also has to put up with reduced customer patronage.

“Before the price increased, I used to refill at least 10 cylinders everyday but now, I hardly refill three cylinders. In fact, when I think some customers are going to refill their 12.5kg cylinders, you would be surprised that they will only buy ₦500 worth of cooking gas,” he added.

Nike Kazeem and Christiana Sikiru, both petty traders (selling provisions and groceries) in makeshift stalls, express concern about the increased price of the product in the first quarter of 2021.

Whereas Mrs. Kazeem, who says she’s been using LPG for decades, has resorted to kerosene stove to cook for her family in the meantime, Mrs. Sikiru switched to cooking gas in January “because she found that “Kerosene dries up quickly.” She said that the increase was a normal trend with commodities. “There has been an increase in price but I understand that things are now expensive,” she explained.

Fluctuations in LPG Price Lead to Regional Distortions

According to the National Bureau of Statistics (NBS), the national repository for statistics in Nigeria, the average cost of refilling 12.5kg cylinder of cooking gas was ₦4,117.55 in January, and ₦4,363.51 in February but it fell to ₦4,359.23 in March.

The average price for refilling 5kg LPG cylinder increased from ₦1,949.02 in January to ₦2,018.91 in February and inched up again, in March, to ₦2,057.71.

In 2021, the total average price for refilling 12.5kg in Q1, stood at ₦12,900.28. However, in 2020, the total average price for refilling LPG cylinder was ₦12,542.04.

Eyono Fatai-Williams, General Manager, NLNG responding to a Thisday enquiry about the increasing price of Liquefied Petroleum Gas (LPG) in January replied that the dependence on imported LPG had put undue pressure on the price of the commodity.

In the same vein, two LPG stakeholders gave a similar account for the increase.

“Gas price is highly seasonal. LPG is a global commodity and during the winter seasons, prices are usually high and then, they go down towards the end of the summer. Then again, by the end of 2020 and early 2021, because of forex changes in Nigeria, it took the prices higher than normal,” says Mr. Bashir Koledoye, Managing Director, Dharmattan Gas and Power Products Ltd, adding that the prices “will continue to drop until the summer”.

Fatai Ogungbenle, Head, Business Development and Sales (LPG), Kwale Hydrocarbon Nigeria Limited, an independent downstream gas company, agrees that the increased price of LPG is tied to the seasonal demand for LPG in Europe during the winter seasons.”

“Europe has more of sustained cold season this year because of global warming. It added to the issue of high demand in Europe and part of America, making us to price highly. But in few weeks to come, I think the price of LPG may likely decrease a bit. But the downside to it is the exchange rate. If nothing is done to it, we may experience this for a longer time more,” he explained.

“I can remember vividly that a truck of gas in November 2020 was ₦4 Million to ₦4.2 Million. But now, it is around ₦5.5 Million to ₦5.6 Million for over a period of about 6 months,” he added.

Nor is the higher price restricted to the gas molecules alone. The cost of the equipment too is rising. Vitalis Obinna said that he sells a 6kg gas cylinder with an accompanying burner for ₦11,000, a 30% jump increase from ₦8,500 which he sold the two equipment just five months ago, in December 2020

Koledoye explains that “demand dips with higher prices, but because Nigeria is rapidly adopting LPG, the effect is not significant”. He admits that there are challenges with the Forex situation, “but increase in in-country LPG production is expected to reduce this problem very soon”. In general, he feels comfortable with the way the market is now.

In Q1 2021, 55.7% of LPG consumed was imported. This contrasts with 58.4% of LPG consumption, which was imported in Q1 2020, according to the Petroleum Products Pricing Regulatory Agency (PPPRA), a monitoring and regulatory agency of petroleum products in Nigeria. In both quarters, importation took the lead.

Apart from the price volatility of LPG in Nigeria and enormous dependence on imported products, the price in each State in the country is largely determined by the landing cost of the product.

In March 2021, Cross River State paid the highest for cooking gas at ₦4762.65 and Zamfara State, ₦3,749.06, accounting for the lowest.

Similarly, Lagos paid ₦4,435.45 to refill 12.5kg cooking gas cylinder.

Cross River state residents paid the highest price in the nation for 12.5kg LPG in Q1 2021, with a sum of ₦14,407.89 while Kaduna paid the lowest with ₦10,900.79 in total.

Different Retail Prices

An LPG retailer at New Site, Satellite Town, a sprawling housing estate in the west of Lagos, who pleaded anonymity, says that LPG price varies among retailers too.

“The price of cooking gas differs depending on who we buy from. If we buy at a high cost, we sell at a high cost. If we buy at a lower cost, we sell at a lower cost. The gas station sold 12.5kg of cooking gas to me at ₦4,500, I sell it at ₦4,600.”

“The business of LPG has always been a good business but it is just that now, it is not really yielding money like it used to. Last year, it was sold to us at ₦4,000 naira but since January, it increased”, he added.

Abundant Resources, Lack of Utilization

Nigeria has the largest gas reserve in Africa. As of June 2020, Nigeria’s proven gas reserve was 203.16 Trillion cubic feet (Tcf), according to a report by the Department of Petroleum Resources (DPR) .

In the report, Sarki Auwalu, the director of DPR, said that even with this huge proven gas reserve, gas utilisation was only about 5.5%.

Mr. Ogungbenle of Kwale Hydrocarbons expressed dissatisfaction at the underutilisation of Nigeria’s gas potential.

“For domestic use of LPG, we are doing less than 25%, far below what we can do,” he said.

Some of the challenges that the domestic LPG market is faced with include uneven terminal distribution, lack of adequate transport facilities and administrative charges on the domestic sales of LPG, although deregulated.

INTERVENTION PLANS

Nigeria’s federal government set up the LPG Penetration Framework to encourage the use of LPG in households, power generation, auto-gas and industrial applications in order to attain five million Metric Tonnes of local consumption of LPG in 2022, according to the Federal Ministry of Petroleum Resources (FMPR).

The government’s objective of attaining Five million MT of LPG consumption by 2022, puts the national consumption target of LPG at an estimated 83.33 thousand MT per month from 2018 to 2022.

In 2021 Q1, only March’s LPG consumption met this monthly target at 87, 199.846 Metric Tonnes (MT).

Even though the calorific content of Liquefied Petroleum Gas (LPG) is higher than kerosene and other cooking fuels, LPG is more capital intensive than most cooking fuels in Nigeria.

This initial cost of switching to LPG is a contributing factor to the 43% population without access to clean cooking, as at 2018.

The LPG Gas Expansion Plan was introduced to increase the consumption of LPG in the nation, as the domestic energy mix consist of 60% firewood, 30% kerosene, 5% LPG, 5% charcoal.

With plans to increase usage of LPG, the federal government will be injecting 10Million cylinders in ten years to the market, according to Dayo Adeshina, Programme manager of the national LPG expansion plan, during a sensitisation workshop on LPG adoption and implementation for industry stakeholders, in Lagos.

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.

Why the Big Oil Class of 2021 Flunked Energy Transition 101

Section: ENERGY TRANSITION · May 18, 2021 · No comments |

By Gerard Kreeft

With the end of the school year students are eager to hear the results of how they fared. Unfortunately, I have only bad and worse news for my Big Oil Energy Transition Class 101.No one passed. Everyone failed. And in some cases failed miserably. How did this happen?

Energy Transition Class 101 has a very straight forward goal. It is focused on the two energy scenarios developed by the International Energy Agency (IEA): • Stated Policies Scenario(SPS) is geared for the short to medium term; and • Sustainable Development Scenario(SDS) for medium to long term.

The SDS scenario, the “Well Below 2 °C “is the benchmark that determines whether course participants pass or fail.

Unfortunately no one passed. Some will get a positive mention to encourage their green activities, others will be reprimanded in private, but given the disastrous results, a public rebuke is necessary.

In The Energy Transition Class 101 SDS scenario, the “Well Below 2 °C” benchmark was key for energy company participants to help understand the steps required to ensure an orderly, low-carbon,energy transition.

The Energy Transition Class 101 went a step further and took on board the Wood Mackenzie’s Accelerated Energy Transition scenario (AET-2),which assumes the world is on course for near 3 °C warming because of renewed energy demands and the challenge of reducing CO₂ emissions.

According to Wood Mackenzie: “The AET-2 scenario is based on the Intergovernmental Panel on Climate Change carbon budget allocation for the next eight decades, to 2100. It sets out our view of how the world can limit the average rise in global temperatures to 2 °C, compared with pre-industrial times, examining potential policy drivers, cost reductions and technological innovations. Electrification and low-carbon fuels are central to meeting the 2 °C limit. We estimate that electricity meets 47% of total final energy consumption globally in 2050, compared with 20% today. Three key assumptions underlie our AET-2 scenario:

• rapid electrification in all sectors; • the decarbonisation of the power sector through the penetration of renewables and storage and coal-to-gas switching ;

• the large-scale development of carbon capture and storage (CCS) and carbon capture, utilisation and storage (CCUS) – 5Billion tonnes (Bt) by 2050 – and low-carbon hydrogen – 380Million tonnes (Mt) by 2050 – in hard-to-decarbonise sectors.”

AET-2 has massive implications for oil and gas demand in 2050: 70% lower than today. From 2023 onward oil demand drops with year-on-year fall of around 2Million barrels per day (2MMBOPD). Total oil demand by 2050 is down to 35MMBOPD.

Natural gas demands, in contrast, remains resilient to about 2050. Large scale CCS in the industrial and power sectors will support gas while the deployment of blue hydrogen (135Mt by 2050) is a growth sector. Growth will come primarily from Asia, especially China and India.

Under AET-2, the assumption is that as many as 80% of new vehicles sold are electric, either battery-driven or hybrid. Heavy transport- ships and trains- are electric or hydrogen driven. Non-combustion liquid petrochemical demand for plastics is damped by higher rates of recycling.

Wood Mackenzie’s AET-2’s scenario draws the following conclusions:• World needs no new supply of oil…”core function is to maintain current commercial production by going into full harvest mode”…• Market power slips from OPEC to giant gas producers such as USA, Russia and Qatar.• Downstream suffers death by a thousand cuts. By 2050 the refining sector will have withered to 1/3 of its current capacity with less than 150 of the current sites in operation.• Era of carbon-neutral gas is born. AET-2 would require $300Billion to support Liquified Natural Gas growth globally and $700Billion to support dry gas development in North America. Blue hydrogen and ammonia emerge as new market products.• Currently no International Oil Company nor National Oil Company is prepared for the scale of decline envisaged in this scenario.

To protect the guilty and more vulnerable my analysis of The Energy Transition Class 101 will be limited to two candidates- Shell and TOTAL- who have at least shown some potential green promise.

Shell

According to The Australasian Centre for Corporate Responsibility(ACCR), Shell states in general terms that it is aligned to meet CO₂ neutrality by 2050, but has no defined number for the medium term in 2030. This is a 30% increase (pre-abatement) or a decrease of 30%. A difference in absolute terms compared tothe equivalent of Germany’s carbon footprint.

Shell has committed, by 2030, to decrease the intensity of its emissions by 20% (energy business only) and reposition its business away from oil, towards gas and chemicals, renewables and marketing.

Gas production will be expanded by 20% by 2025 as well as increases in renewable electricity and Electrical Vehicles(EV) infrastructure, biofuels and hydrogen(blue and green).

ACCR states that Shell plans to use 120 Mt nature based solutions per year by 2030 and 25 Mt CCS per year by 2035. This amount of nature based solution is greater than the size of voluntary offset traded in 2019 (104 Mt) and equals to a non-conifer forest the size of Washington state(needed to be mature by 2030).

Shell’s CCS ambitions are similarly difficult. Today there is 40 Mt of operational CCS globally and only 15% geologically, mostly attributed to Shell’s Gorgon JV, which is currently not working.

If Shell had implemented its CCS and nature based solutions in 2019 it could have provided 50% reduction of Shell’s required CO2 emissions. According to ACCR “Shell will not reach the carbon intensity under Transitions Pathways Initiative 2°C for oil and gas missing the 2030 target by 32%”.

TOTAL

TOTAL is now pledging to reduce the average carbon intensity of energy products – Scope 1, Scope2 and Scope3 – used by its customers worldwide, by 20% in2030, an increase from 15%. This indicator would have to fall by 75% to be consistent with a 2°C target, and by 90% for a target of less than 2°C.

Scope 1 – All Direct Emissions from the activities of an organisation or under their control. Including fuel combustion on site such as gas boilers, fleet vehicles and air-conditioning leaks.

Scope 2 – Indirect Emissions from electricity purchased and used by the organisation. Emissions are created during the production of the energy and eventually used by the organisation.

Scope 3 – All Other Indirect Emissions from activities of the organisation, occuring from sources that they do not own or control. These are usually the greatest share of the carbon footprint, covering emissions associated with business travel, procurement, waste and water.

TOTAL will by 2030 only cut in Scope 3 Emissions in Europe to 30% and by 2050 to zero. The fly in the ointment is that TOTAL is simply exporting its remaining Scope 3 Emissions to the rest of the world, including Africa, thus creating a two-tiered emissions system.

TOTAL states that it plans to increase its energy production from 3 to 4MMBOEPD by 2030, with half of that growth coming from gas, and oil likely to remain close to its current level. That means that gas production could increase by 30% by 2030.

These plans are at odds with Carbon Tracker’s Index (CTI) finding that Total must achieve a minimum 35% reduction in fossil fuel production by 2040 compared to 2019 levels, in order to stay within the IEA’s “Beyond 2 Degrees Scenario” (B2DS).

Yet in spite of the predicted increase in oil and gas production, another important change was taking place. In the summer of 2020, TOTAL wrote off a $7Billion impairment charge for two Canadian oil sands projects. This might have seemed like an innocuous move, merely an acknowledgement that the projects hadn’t worked out as planned.

It opened a Pandora’s box that is changing the way the industry thinks about its core business model—and point the way towards a new path to financial success in the energy sector.

While it wrote off some weak assets, it did something else: Total began to sketch a blueprint for how to transition an oil company into an energy company. For the first time a major oil company translated its renewable energy portfolio into barrels of oil equivalent. Patrick Pouyanné, Total’s chairman and chief executive, now says that by 2030 the company “will grow by one-third, roughly from 3MMBOEPD (Barrels of Oil Equivalent per Day) to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables.”

At the same time that the company has slashed “proved” oil and gas from its books, it has added renewable power as a new form of reserves. Proved reserves long stood as the Holy-of-Holies for the oil industry’s finances—the key indicator of whether a company was prepared for the future. For decades, investors equated proved reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the Reserve Replacement Ratio, or RRR—the share of a company’s production that it replaced each year with new reserves—became a bellwether for oil company performance. The RRR metric was adopted by both the Society of Petroleum Engineers and the USSecurities and Exchange Commission. An annual RRR of 100% became the norm. Adding reserves doesn’t necessarily mean adding value.

But TOTAL’s write-off showed that even “proved” reserves are no sure thing, and that adding reserves doesn’t necessarily mean adding value. The implications are devastating, upending the oil industry’s entire reserve classification system, as well as decades of financial analysis.

How did TOTAL reach the conclusion that “proved” reserves had no economic value? Simply put, reserves are only reserves if they’re profitable. The prices paid by customers must exceed the cost of production. Given current forecasts that prices would remain lower for longer, TOTAL’s financial team decided those resources could never be developed at a profit.

A similar scenario could play out with TOTAL’s remaining oil and gas projects. If driven by shareholder activism, more projects could become earmarked as stranded assets. Which could act as a catalyst to accelerate Total’s renewables portfolio. The planned expansion to 35 GW by 2025, and 100 GW by 2030 could become the start of a robust campaign to embrace renewables at an even quicker pace.

This has huge ramifications for Africa which has long been a rich source of cash flow for the company. In 2019 the continent generated around $10Billion of TOTAL’s $26Billion cash flow from operations, and 30% of its oil and gas production (900,000 barrels of oil equivalent per day).

If TOTAL, through increased shareholder activism, takes on more renewable energy, this could have a profound effect on Africa’s renewable energy journey.

Conclusions

Perhaps in 2050 the Energy Transition Class 101will look back with nostalgia and smile about the challenges that the Class of 2021 faced. Will the more than 2°C challenge have been met? Perhaps the basis of fairy tales told to youngsters as bedtime stories by their grandfathers. Perhaps Grampa was a Member of the Class of 2021 that flunked.

Note: My thanks to Carbon Tracker, The Australasian Centre for Corporate Responsibility(ACCR), Institute for Energy Economics and Financial Analysis (IEEFA),Reclaim Finance, and Wood Mackenzie.

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

Schlumberger Appoints Siemens’ Vice President as its New Chief of Strategy

Section: Petroleum People · May 17, 2021 · No comments |

Schlumberger has announced the appointment of Katharina Beumelburg to the position of Chief Strategy and Sustainability Officer, Schlumberger Limited, reporting to Olivier Le Peuch, Chief Executive Officer. The appointment is effective Monday, May 17, 2021.

Ms. Beumelburg was Senior Vice President, Global Transmission Services at Siemens Energy, a subsidiary of Siemens, a global technology company, headquartered in Germany.

She took a doctorate degree from the University of Stuttgart in 2005, after earning her first engineering qualification at Universität Siegen, over a five-year period (1995 to 2000), during which she also trained in industrial engineering at the University of Tulsa (1997-1998),

“As a member of the executive team, Dr. Beumelburg will oversee corporate strategy, sustainability, marketing and communications activities across the Company”, Schlumberger says.

“Dr. Beumelburg has held various leadership positions in Siemens, including strategy development incorporating sustainability; management consulting; business excellence; and operationsmanagement”.

Welltec seals exclusive intervention deal with Petronas

Section: In the news, PARTNER CONTENT · May 16, 2021 · No comments |

PARTNER CONTENT

Welltec has been awarded an exclusive three-year contract by global energy and solutions company, Petronas. The agreement, which officially commenced on April 1st, appoints Welltec as the sole provider of downhole conveyance and powered mechanical services in both East and West regions of Malaysia.

“It’s a great team effort that has that has led to the award of this exclusive long-term contract with Petronas, and Welltec has demonstrated a strong ability to deliver, even though a challenging 2020, high quality services in a safe manner to the largest assets in the country at a very cost-effective rate,” Espen Dalland, WelltecArea VP for the Asia-Pacific region, said. “This winning combination is the foundation for Petronas awarding us an even larger work scope for the next three years, where we will continue to deliver world-class technology and services.

“This is the third new contract we have received from Petronas following awards in 2014 and 2017, with an extension exercised in 2019. This latest contract predominantly features the same scope of services but now the geographical scope has increased from previously just being East Malaysia, to also include all assets in West Malaysia.”

With the new deal covering the entirety of Petronas’ intervention operations, the award not only builds on a long-standing relationship, but also shows a real vote of confidence in Welltec’sfleet and technological capabilities. The services are based on daily or monthly rental and will be selected by the various Petronas assets for any upcoming project during the coming three-year period.

The delivery will include the entire Welltec Intervention portfolio with the majority of services having already been deployed successfully for Petronas under previous agreements, but now additional services like the RCB (Reverse Circulating Bit) and several sizes of the Well Cutter family have also been added to the list. Welltec’s unique RCB breaks through obstacles, such as composite plugs, and recovers the generated cuttings with suction into integrated bailer sections. In a single run, this allows users to mill such obstacles as composite plugs and recover any associated debris the well to prevent further associated problems.

“This is a fantastic win for us. Petronas is a key customer in the region who over recent years have moved more and more towards an integrated approach for interventions.” said Alex Nicodimou, Welltec Sales & Marketing VP. “The fact they have provided us 100% of their intervention work speaks volumes about their belief in our technology and ability to deliver. We’re looking forward to continuing to support them to the best of our abilities.”

South Africa Sprouts New Shoots

Section: In the news · May 6, 2021 · No comments |

In the last five years, several E&P companies, primarily owned by South Africans, have left the upstream market, such that it is tempting to declare the end of the growth of South African E&Pindependents.

JSE listed SacOil, badly burned by its dealings in Nigeria with local partners Transcorp and NigDel, has turned into a downstream company and changed its name to Efora.

Thombo Petroleum, owned by Trevor Ridley, former Petroleum Advisor at BHP Billiton, disappeared into the folds of Canadian owned Africa Energy Corp.

But apart from Sasol Exploration and Production International, which is the most visible and best resourced South African bornE&P company, there are a number of companies to consider:

JSE and ASX listed Renergen describes itself as an integrated alternative and renewable energy business that invests in early-tage alternative energy projects.

But it started its project life six years ago by acquiring an onshore natural gas acreage from Molopo South Africa Exploration and Production. Renergen holds the first, and currently only, onshore petroleum production right in South Africa.

Several homegrown independent South African companies, including Tshipise Energy (Pty) and Sungu Sungu Petroleum, are exploring for natural gas, in coal beds, in the Karoo and offshore Orange Basin, but their distance to development is, at best, far off.

Renergen is the only one pumping natural gas from subsurface reservoirs into the local market. It has been supplying compressed natural gas to transportation companies since May 2016.

South African National Petroleum Company (formerly PetroSA), the only other natural gas producer in the country, is a state-owned enterprise.

Renergen is working on ramping up production from its acreage, which holds an estimated 142Billion standard cubic feet of proven and probable reserves, near Virginia, about 300km southwest of Johannesburg. It has moved intoliquefied natural gas (LNG) production, “primarily serving the growing domestic heavy duty truck market across Africa and emerging markets”, it says. Renergen has signed an offtake agreement with South African Breweries (SAB) for the supply of liquefied natural gas to power its delivery trucks. For this project, it initially rolled out compressed natural gas to a small fleet of SAB trucks in Gauteng, the country’s major commercial province.

A POTENTIAL STAR IN THE SOUTH AFRICAN E&PFIRMAMENT is Sunbird, a gas explorer and developer which owns a 76% interest in the Ibhubesi Gas Project, Block 2A, offshore of the west coast of South Africa and is the operator of the block. The company was originally owned by Australians, and was sold to South Africans in 2016. The Ibhubesi Gas Project is the country’s largest, undeveloped gas discovery, in the opinion of Sunbird and the local media. Theindependently certified gas reserves are 540 Bcf (2P) with “best estimate” prospectivity of close to 8 Tcf of gas, according to the company. The immediate focus of the project is provision of gas to the Ankerlig Power Station, an 11 year old, 1,338MW capacity thermal plant, designed to be fired by natural gas, but instead, utilizing expensive diesel fuel.Sunbird’s JV partner PetroSA, holds the remaining 24% in Ibhubesi.

Sunbird, for now, remains no more than a potential.

Five years after the Department of Environmental Affairs (DEA) issued an Environmental Authorisation (EA) for the project, the company is not anywhere close to concluding the gas sales negotiations with Eskom, the South African state power utility which owns the Ankerlig power plant. Nor is Sunbird seen to be progressing any deal to sell gas for industrial uses like Renergen is doing.

Kuwaitis Find New Oil and a Trickle of Gas in Egypt’s Western Desert

Section: Oilpatch Sahara · May 6, 2021 · No comments |

Kuwait Energy has flowed a modest crude oil rate and a trickle of gas after drill stem tests were performed on a new field wildcat well in Egypt’s Abu Sennan Concession in the Western Desert Basin.

The company flowed a cumulative maximum rate of 2,834Barrels of Oil Per Day (BOPD and 4.211Million standard cubic feet of gas per day (MMscf/d) on a 64/64″ choke in two reservoirs in the ASD-1Xwell.

For these two reservoirs, the Lower Bahariya and Abu Roash C, the cumulative minimum flow rate was 1,511BOPD and 1.232MMscf/d on a more constrained 32/64″ choke

Modest as these results are, they exceed Kuwait Energy’s pre-drill expectations.

The oil rates are actually higher than the Egyptian average, but the natural gas flow is incredibly small.

Still, the operator has gone ahead to submit an application for a development lease to develop the “field”, within the Abu Senanconcession.

ASD-1X, located 12km to the north-east of the producing Al JahraaField, reached Total Depth (TD) of 3,750m MD on March30, several days ahead of schedule and under-budget.

Apart from the t reservoirs tested, preliminary results suggest the well encountered a combined net pay total of at least 22m across a number of reservoir intervals, including the primary reservoir targets of the AR-C and AR-E, as well as the Lower Bahariya and KharitaFormations.

The well was drilled by the EDC-50 rig, which has now been moved to the Al Jahraa Field, also within the Abu Sennan concession, where the drilling of the AJ-8 development well commenced on May 2, 2021. This well will target the Abu Roash and Bahariyareservoirs in an undrained portion of the Al Jahraa field.

Below are details of the test results:

· The ASD-1X well tested both the Lower Bahariya and Abu Roash C reservoirs

· Preliminary short-term test results from the Lower Bahariyareservoir indicate:

o A maximum flow rate of (c. 2,187bOEPD gross; 481BOEPD net) on a 64/64″ choke

o A rate of 852BOPD and 1.600MMscf/d (c. 1,172BOEPD gross; 258BOEPD net) on a more constrained 32/64″ choke

· Preliminary short-term test results from the Abu Roash C (“ARC”) reservoir indicate:

o A maximum flow rate of 1,215BOPD and 1.371MMscf/d (c. 1,489BOEPD gross; 328BOEPD net) on a 64/64″ choke

o A rate of 661BOPd and 0.632MMscf/d (c. 787BOEPD gross; 173BOEPD net) on a more constrained 24/64″ choke

Nigeria’s Bid Round Signature Bonuses are Overpriced, says Platform’s Outgoing CEO

Section: Farm in, Farm Out · May 6, 2021 · No comments |

…Dismisses the rumour that the company was awarded stakes in several fields.

The Nigerian government’s expectation of raising half a billion dollars from signature bonuses, has imposed significant financial pressure on participants in the about-to-be-concluded bid round of marginal fields, in the opinion of the chief executive of a homegrown E&P independent.

“By our own assessment, I think it is overpriced”, contends Osa Owieadolor, the Managing Director and Chief Executive Officer of Platform Petroleum, itself a marginal field operator. “In (the last marginal field bid round exercise) in 2003, $150,000 was paid as signature bonus, but now it is ranging from $5,000,000 to as high as twenty-something million dollars. That’s a lot of money!”

Owieadolor, 51, who retires from the job at the end of this month, says he is not canvassing for a signature bonus as low as $150,000, “but $5Million for a marginal field is too high” and this is one of the lowest figures.

The government, apparently, is targeting early revenues from the process into the national treasury. Sarki Auwalu, the CEO of the Department of Petroleum Resources DPR, the industry regulator, set out the agency’s expectations in a televised interview with the local TV channel Arise News last February. “We estimate [signature bonuses] will be not less than $500Million, which is on the conservative side,” Auwalu said.

Owieadolor argues that field development activity should take the primacy of place. “For marginal fields, you need to look beyond the signature bonus. You want to come up with a low figure that is an incentive to encourage people to focus on the development costs. Because that is really the key thing. The idea is not to have these assets, you pay for signature bonus, at the end of the day, you’re not able to develop it. The awardee should not feel much pressure when it comes to the signing into the asset, that s/he loses clear line of sight to first oil. I think the signature bonus was overpriced”.

Asked if the stellar performance of some of the fields awarded in the last bid round exercise could have encouraged the government to raise the tariff this time, Owieadolor responds in the affirmative. “I think that is one of the factors that DPRused”, he says. “Some assets that were reported as having very low reserves have, over time, produced way above what was booked as the reserves”, he testifies. “But you have to look at the capacity to fund. It’s not about owning the asset. You own the asset, you pay government so much upfront and then you cannot fund the development; after five years, the lease expires on you. When you have a situation where a lot of these awardees and co-awardees are first and foremost going to be struggling, some people are even trying to get debt facility for signature bonus, you’ll run into problems. For signature bonus, you should be able to secure some bit of equity funding for that. Then when you now get to your real development, a mix of debt and equity can see you through all of that”

Platform Petroleum has produced the Egbaoma field, in northwestern Niger Delta basin, for 14 years, with current oil production of around 3,000Barrels of per day and natural gas output of 22Million standard cubic feet per day, pumped into the Nigerian Natural Gas Grid system.

“Difficult access to financing even played a huge role in the activities of the 32 companies who were assigned 24 marginal fields in 2003/2004. Today, only about 40% of that group that achieved full development of their assets. Those that were able to achieve first oil within the first five years were actually less than 30%. A number of them had to seek extension and all that”.

Owieadolor dismisses the rumour that Platform was awarded stakes in several fields in the ongoing round. “We were awarded just a quarter of the equity in one field”, he clarifies. “For us, that again surprisingly is one of the disappointments we’re seeing in this bid round. We had thought that companies like ours that were part of the 2003 Bid Round, we’ve clearly demonstrated capacity, we’ve grown experience over the past almost two decades and we felt that companies like us, would have been given some special considerations in this process. But for some reasons, we were treated like any other applicant. But that is what it is”.

In the current round, no single field is assigned to a single company; all fields are awarded to multiple companies and the would-be partners” are expected to form a Special Purpose Vehicle per field. Owieadolor considers it bit premature to write off the SPV idea. “The flip side of that arrangement is now you have different entities coming together. There’s a bit of collaboration. You expect that the equity funding would be improved. When you have four entities in an asset, so it’s going to be easier for the four entities to contribute their share of whatever the signature bonus will be. You’re going to be funding based on that Pro-Rated obligation. But getting the right synergy is really where the question is. But I think that can be worked out. We’re already seeing it playing out, a lot of engagements are going on, there’re all kinds alliances here and there. You have 161 companies that were awarded about fifty-something assets. Perhaps you have about 70% of this number struggling to pay their signature bonus. Then maybe out of that, you have another 20-30% in the next two-three years are able to achieve first oil. If that happens, the pattern is not different from what we had previously. For me overall, you can say that is some success.”

TOTAL Boosts Gross Angolan Output With a 40,000BOPD Development

Section: In the news · May 6, 2021 · No comments |

French major TOTAL, has announced the start of production from Zinia Phase 2 short-cycle project, in its prolific Block 17, in deepwater off Angola.

The field is hooked up to the existing Pazflor’s FPSO (Floating Production, Storage and Offloading unit).

The project includes the drilling of nine wells and is expected to reach a production of 40,000 barrels of oil per day by mid-2022.

TOTAL operates Block 17 with 38%. Partners include Equinor 22.16%, ExxonMobil 19% and BP 15.84% and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor.

Gross crude oil volume exported from Block 17 in March 2021 was 10, 455,209 barrels, amounting to 337, 265BOPD, according to Angolan government statistics.

Located in water depths from 600 to 1,200 metres and about 150 kilometres from the Angolan coast, Zinia Phase 2 resources are estimated at 65Million barrels of oil.

TOTAL said that the project’s entire development “was carried out according to schedule and for a CAPEX more than 10% below budget, representing a saving of $150Million.

“It involved more than 3Million manhours of work, of which 2 million were performed in Angola, without any incident”.

The Block 17 production license was recently extended until 2045.

Osa Owieаdolor, Platform Petroleum’s CEO, Elects Early Retirement

Section: Petroleum People · April 28, 2021 · 1 comment |

Osa Owieadolor, Platform Petroleum’s Chief Executive Officer, is leaving the company at the end of May, 2021.

He will hand over to Longfellow Atakele, the company’s General Manager Asset and Deputy CEO.

“It has been 14 years of very fulfilling career Journey with Platform, laced with unique, broad and diverse experiences”, Owieadolor told the Africa Oil+Gas Report in a valedictory interview. “I cherish all the relationships I have made while here and would hold on to the many accomplishments that are part of my history with Platform”.

A Fellow of the Nigerian Society of Engineers, Owieadolor spent seven years working for Shell and has had close to half of his 29-year postgraduation experience at Platform Petroleum, a marginal field operating company in which he has risen from production operations, served as pioneer technical lead, been chief operations manager and risen to Chief Operating Officer, before becoming the CEO six years ago.

Platform is an exemplary operator in the annals of Nigerian marginal oil field development and to be its CEO counts for a lot. It was the first to reach first oil, out of the 24 operating companies granted marginal fields in 2003/2004. With its JV partner Newcross Petroleum, Platform constructed a crude evacuation pipeline and a gas processing plant on the field. Since first oil in 2007, Platform has extracted 10Million barrels -with a remaining 10Million barrels left – in a field whose estimated reserves at the time of award was less than 10Million barrels. Owieadolor has been with the company sine the year of first oil.

“My learning has been very steep”, he says. “In a small company, you have a lot of responsibilities, you have to be involved in so many things, unlike what you’d typically have in a place like Shell. It’s been a very fulfilling experience, and we’ve also seen a lot of value creation”, he testifies. “I am extremely grateful to the Chairman, Vice Chairman, Board members, Management team and entire staff whom I worked very collaboratively with to achieve our board objectives as a family”.

The outgoing CEO explains that Platform is fortunate to have a robust succession plan in place. “This was carefully designed and we have taken time to ensure it was nurtured and implemented over the years”. Atakele’s ascension to the top job fits the plan. “The current GM Asset who is also my deputy is well groomed and matured to seamlessly fill the role”.

Asked what he would be doing next, Owieadolor demurs.

Austin Avuru, deputy chairman of Platform Petroleum’s board of directors, says he and Dumo Lulu-Briggs, the company’s Chairman of the Board, were hoping that Owieadolor would change his mind when he initially informed the board he was leaving. “We were expecting him to come forward with a request for his second term of three years”, Avuru recalls. “It (the renewal) would have been automatic. Just a formality. Instead, Owieadolor, who turned 51 two weeks ago, came up with the information that he was electing early retirement.

On his part, the chairman says he “felt a great trepidation” when Owieadolor told him in a zoom conference that he desired to go on early retirement, adding that the outgoing CEO “had a meteoric rise”, in the company’s career ladder. “Nothing prepared me for such absence from the Platform Petroleum Ltd family”, Mr. Briggs explains, especially after he had read Owieadolor’s “Forward Looking“ new year message to staff .

“He had done a good job”, Avuru says.

BP Starts Up 600MMscf/d Field for Egypt’s Domestic Gas Market

Section: Gas Monetization · April 28, 2021 · No comments |

British supermajor BP has commissioned the Raven gas field in Egypt’s West Nile Delta, producing 600Million standard cubic feet per day (600MMscf/d) into the country’s natural gas grid for a start.

The field produces into a new onshore processing facility, alongside the existing West Nile Delta onshore processing plant.

At its peak, Raven has the potential to produce 900MMsscf/d and 30,000 barrels per day of condensate.

Raven is the third of three projects in BP’s West Nile Delta (WND) development off the Mediterranean coast of Egypt. It follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019 respectively.

The approximately $9Billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. BP and its partners, working with the Ministry of Petroleum, have developed the WND in three stages.

Egypt is Africa’s most absorptive market for natural gas, consuming over 6Billion standard cubic feet per day (6Bscf/d), most of it in its 55,000MW electricity generation market.

Bernard Looney, BP’s chief executive, says that the WNDprojects “will make an important contribution to meeting Egypt’s growing energy needs by providing a cost-competitive and resilient gas supply from the country’s own resources.”

FAR Finally Agrees to Sell to Woodside in Senegal

Section: Farm in, Farm Out · April 28, 2021 · No comments |

Shareholders of FAR Limited, the Australian hydrocarbon property broker, have agreed to sell the company’s stakes in Senegal to Woodside Energy.

The deal is that Woodside will pay FAR, $45Million, then reimburse FAR’s share of working capital, including any cash calls, from January 1, 2020 to completion of the sale, with entitlement to certain contingent payments capped at $55Million.

Woodside moved, last December, to exercise its right of first refusal to preempt the sale of FAR’s interest in the Rufisque offshore, Sangomar offshore and Sangomar deep offshore (RSSD) contract area to the Indian player ONGC Videsh Vankorneft. FAR’s interest in the RSSD Joint Venture comprises 13.67% of the Sangomar exploration area and 15% of the remaining RSSD evaluation area.

By the time the transactions are concluded, Australia’s largest E&P firm would have bought up all the stakes belonging to its partners Cairn Energy and FAR in Senegal. It will then hold 82% working stake in the Sangomar exploitation area with the state owned Petrosen holding 18%. Its working interest in the remaining Rufisque, Sangomar and Sangomar Deep (RSSD) evaluation area (including the FAN and SNE North oil discoveries) will be 90%, while Petrosen holds 10%.

In January 2020, Woodside took Final Investment Decision to develop the Sangomar field, located in 800 metres of water. It will be Senegal’s first offshore oil project and the floating production storage and offloading (FPSO) vessel will have a production capacity of approximately 100,000 barrels of oil per day. The execute phase of the Sangomar Field Development includes the drilling of 23 wells, construction and installation of the subsea network and the construction and installation of the FPSO. The company targets first oil in 2023.

In December 2020, Woodside concluded the completed the acquisition of Cairn’s interest with the purchase price of $300Million plus a working capital adjustment of approximately $225Million, which included a reimbursement of Cairn’s development capital expenditure incurred since 1 January 2020. Additional payments of up to $100Mllion are contingent on commodity prices and timing of first oil.

After all these buys, Woodside will, in its own view, have“simplified the structure of the joint venture ahead of our planned equity sell-down in 2021”.

The company is convinced that the Sangomar development “is an attractive, de-risked asset that offers near-term production to potential buyers.”

VAALCO to Replace the ‘Expensive’ FPSO Petróleo Nautipa on Gabon’s Etame Field

Section: In the news · April 28, 2021 · No comments |

US minnow VAALCO is looking to reduce its operating costs on the Etame field, offshore Gabon, by dispensing with the services of Petróleo Nautipa, the Floating Production, Storage and Offloading (FPSO) owned and managed by the Norwegian service company BW Offshore.

The operator has announced that it has signed a non-binding letter of intent with the Omni Offshore Terminals Pte Ltd to provide and operate a Floating Storage and Offloading (FSO) unit on the field for up to 11 years.

The one-year contract extension with BW Offshore for PetróleoNautipa expires in September 2022. Gross crude oil output on the Etame field is 17,200BOPD, of which VAALCO holds 31.1% operated interest.

“The Omni FSO proposal could reduce VAALCO’s operating costs by 15% to 25% when compared to the current FPSO contract during the term of the proposed agreement”, VAALCOsays in a release. “Maintaining the current FPSO beyond its current contract or transitioning to a different FPSO would require substantial capital costs”, it adds. “Estimated capital investment of $40 – $50Million gross ($25 – $32Million net to VAALCO) for deployment of the Omni FSO and the required field reconfiguration, with approximately 20% invested in the second half of 2021 and the balance in 2022 with an expected payback of less than three years”.

VAALCO explains that in the new field configuration, the FSOwould store and offload the production and processing would be completed on the existing platforms.

The company is currently forecasting that its capital costs for the FSO and field reconfiguration, as well as its planned 2021/2022 drilling programme, can be funded with cash from operations and cash on hand;

VAALCO and Omni, having agreed to an exclusivity period through June 1, 2021, will engage in further discussions with the intent to finalize a definitive agreement.

VAALCO however says that there is as yet no assurance that itsagreement with Omni will be finalized “and any such agreement will be subject to Board approval by both parties as well as Etame joint-owner and Gabonese government approvals”.

Dana’s Egyptian Assets Still Up for Grabs

Section: Farm in, Farm Out · April 25, 2021 · No comments |

By Mohammed Jetutu

Dana Gas, the Abu Dhabi listed independent, is still looking for buyers for its Egyptian onshore oil and gas assets, after it failed to consummate a sales and purchase agreement with IPR Energy Group, another middle eastern minnow.

The two had signed a tentative agreement on the transaction, worth $260Million in October 2020. But some of the conditions precedent for the sale to go through were not met by the agreed time-frame on April 14, 2021, Dana said. “A number of conditions precedent to the transaction could not be completed to the satisfaction of both parties,” the company, which describes itself as the ‘Middle East’s largest private sector natural gas company’, declares in a briefing. “The Board has therefore decided to retain and operate the assets in Egypt alongside the highly prospective exploration acreage offshore Block 6”. Patrick Allman-Ward, Dana Gas’ Chief Executive Officer, commented.

The sale was previously due to close in 1H2021.

What Dana Gas Wants to Sell

Dana Gas is a 100% operator in four concessions and 50% non-operator of one concession, all located in onshore Niger Delta. The concessions include: El Manzala, West El Manzala andWest El Qantaraall covering 796 square kilometres, with an estimated 89Million Barrels of Oil Equivalent (BOE) of reserves(Gaffney Cline and Associates). The four concessions include 15 development leases with gas and condensate production from 15 fields. Gas production is about 155 MMscf/day 5,300Bbls/Dcondensate plus 235 tons/day of LPG, totaling 33,000BOEPD in 2020, an 8% decline from 30,300BOEPD in 2019, as a result of natural field declines. Dana Gas has been looking to offload these assets since July 2019, when it declared that a sale would allow it to double down on its more promising operations in Iraqi Kurdistan.

What Dana Gas Wants to Keep, in Egypt

Dana Gas is 100% operator of one offshore concession in the Eastern Mediterranean, a growing natural gas hub.

Kenya’s “Excess” Power Generation Burdens the Country’s Electricity Distributor

Section: Power Deficit · April 25, 2021 · No comments |

Kenya’s Energy and Petroleum Regulatory Authority (Epra) reports that the country’s electricity generating firms have increased their output to such an extent that the nation has a problem of idle power.

With rising cost of fuel and reduced rate of increase in demand, a heavy financial burden now lies on Kenya Power, the country’s distribution utility.

KenGen, the top generating company, and other power producers increased their supply to Kenya Power to 1.058Billion kilowatt-hours (kWh) in March 2021, reports the Epra, a figure described by the, Business Daily Africa, the leading local financial newspaper, as an “all time high”.

“The March 2021 figure is an 11.8% rise from 946.09Million kWh that was supplied in the previous month and now jumps above the previous record supply that had been set last October”, the newspaper explains.

Business Daily Africa says that the spike in generation “exposedhomes and businesses to the burden of paying for idle electricity”amid depressed consumption. “Payments for idle electricity is a pass-on cost to consumers. The take-or-pay clause in contracts signed between government and power producers compels Kenya Power to buy the agreed amount of electricity regardless of whether or not the utility needs the energy”.

Kenya Power, the distribution company, has been struggling. In February 2021, it reported that revenue from the sale of electricity fell to $635Million (KSh69.014Billion) in the six months period that ended on December 31, 2020, compared to $641Million (KSh69.607 Billion) at the end of December 2019. Transmission and distribution costs dropped 19% to $17.2Million (KSh18.7Billion) from 212Million (KSh23Billion) in the corresponding half year period in 2019.

The March 2021 supply is for instance 41.5% higher than the 748.44Million kWh that Kenya Power sold to consumers in February 2021.

“The excess generation has been a major concern for Kenya Power, which has to pay for the electricity generated even when there is no market to sell it”, the daily concludes.

Suez Canal: Ever Given Still Hasn’t Given Way

Section: MARITIME ISSUES · April 25, 2021 · No comments |

By Mohammed Jetutu

The MV Ever Given, the giant vessel which blocked the Suez Canal for close to a week in March 2021, still hasn’t moved away from the region.

Its seizure, by the Suez Canal Authority (SCA), is the subject of an appeal to be heard in the Ismailia court (one of the Egypt’s seven courts of appeal), in the first week of May 2021.

Ever Given’s Japanese owner, Shoei Kisen Kaisha, is appealing for the overturn of a lower court’s decision, which earlier in April 2021, gave the SCA the permission to arrest the ship. The SCA is demanding $916Million in compensation for the six-day blockage, a sum that Shoei Kisen’s insurer, the UK Club, has dismissed as extraordinarily large.

Ever Given forced a standstill of shipping activity when, on March 23, 2021, it got wedged sideways across the canal, a critical global trade artery that connects the Mediterranean and the Red Sea. The initial reason proffered for the accident was that high winds and a dust storm made the crew lose control of the ship. The 400 metrelong, 59 metre wide, 224,000 tonne ship is one of the largest cargo vessels in the world. Pictured on its side, the ship presented a rough sketch of a skyscraper.

“The appeal against the arrest was made on several grounds, including the validity of the arrest obtained in respect of the cargo and the lack of supporting evidence for the SCA’s very significant claim,” the UK Club complained. SCA’s $916Million demand comprises a $300Million “salvage bonus” and another $300Millionfor “loss of reputation,” among other items. The claim does not factor in the cost of salvaging the Evergreen-chartered vessel, which “owners and their hull underwriters expect to receive separately.”

A total of 422 ships piled up at either end of the canal as the mega-vessel blocked it for six days

An eight-person team from Dutch marine response firm SMIT Salvage as well as a team from Japanese owned Nippon Salvage were hired by Shoei Kisen Kaisha to move the ship. The rescue operation also involved tugboats and dredgers.

The MV Ever Given, was enroute from China to the Netherlands when the accident occurred.

“Nigeria’s top Problem is Well Cost: We are Out to Solve it”

Section: PARTNER CONTENT · April 19, 2021 · 6 comments |

PARTNER CONTENT/Hd Drilling Services

Hope Okwa, Founder/Chief Executive Officer Hd Drilling Services, sees the high cost of well construction as major impediment to Nigeria’s meeting its goal of achieving 4Million Barrels of Oil Per Day of crude oil in the short term.

“If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands”, he tells Africa Oil+Gas Report’s Ahmed Gafar, “even local banks may be able to fund field development campaigns”.

He also fields questions on a range of issues, from opportunities that newly awarded marginal fields throw up to demand for Nigerian hydrocarbon.

A bachelors and masters degree holder in engineering from the University of Benin (Nigeria) and Heriot Watt University in the UK respectively, Okwa has 29 years of post graduation industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deep-water operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another 18-month stint at BP Angola as senior drilling engineer.

Excerpts from the conversation.

Hd Okwa Drilling advertises itself as a company with a laser focus on oilfield drilling services. How did you come to this realisation?

The Nigerian Government targets Four Million barrels of oil per day (4MMBOPD), but the country is barely achieving 1.5MMBOPD due to high well cost. A 10,000 ft well producing only 3,000 BOPD costs up to $25Million to construct. To move from current 1.5MM to 4MM BOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables? The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels.
The sources of inefficiencies in well construction, is very much within our expertise, as a demonstrated through the several SPE papers we have authored.
It is very urgent to implement these solutions. In nine (9) years’ time, by 2030, the first world will pivot away from fossil fuel. What will then happen to Nigeria’s reserves of 37 Billion BOE?
We believe we have the solutions to reduce well costs in Nigeria by as much as 70%. I have a track record of this achievement from my employment with Shell, BG-Group, BP, Saudi Aramco, as well as many local operators. Hd Okwa Drilling is collaborating with operators and service companies to deliver wells that are only 30% of the standard cost. We hope to have an opportunity to talk about these alliances and collaborations in the course of this discussion.

When you say: A 10,000 feet well producing only 3000 BOPD costs up to $25Million to construct, are you referring to an onshore well or a shallow offshore well?

The statement is true for land, swamp and shallow offshore. These use surface blowout preventers.

Ad if a 10,000feet well is considered too expensive at $25Million in Nigeria, what is the reference round the world? What are you benchmarking against?

My reference is Canada/USA, where the rig rate for land is $32,000/day comparable with $25,000/day for Nigeria. A 10,000 ft land well takes 8 days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2 million, while Nigeria is $25 million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5 million horizontal well for a Nigerian marginal operator, applying our technigues..

Your website indicates that there’s an entire business proposition around well services that require some single mindedness. and how is the journey so far?

The establishment of Hd Okwa Drilling Services is a milestone in its own right. We have had opportunities to offer advice on Well Design, NPT avoidance, cost improvement, personnel recruitment, etc for various operators. In the years ahead, we plan to expand these offerings to technical consulting, staff development on cost-reducing well delivery processes and dealing with the complexity of supply chains in Nigeria.

Rig activity has taken a dive in Nigeria in the past year. What has been Hd Okwa Drilling’s Business Strategy in this prolonged period of silence?

We may ascribe the direct cause of rig activity collapse to the COVID-19 outbreak. However, I suspect the underlying cause of this sharp decrease in drilling activity may not be far from the high cost of wells, as I highlighted earlier, and the challenge of obtaining investment cash in an environment where everyone is going to renewables.

We believe that if we reduce well costs drastically, through our activities, we will be able to stimulate activities. For example, if we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.

Over 200 companies are expected to form 57 Special Purpose Vehicles (SPVs) to develop 57 Marginal Fields in the next 36 Months. How is Hd Okwa working on taking advantage?

Here is where we hope to make the most impact. In the past, many marginal field winners have struggled to bring oil to market due to several challenges, related to investment funds availability. Many of the marginal operators are going to need to drill 3-5 wells to realise their field potentials. Without support from our activities, each operator will try to raise $75 – $125Million for field development. With our expertise, this could just be only $15 – $25Million, which is within the capability of local banks. We have assembled a repertoire of options available to marginal operators e.g. from our bespoke consulting services, to full project management through our sister company H-PTP Energy services, or our supply chain improvement alliances The Well Engineering Platform, etc. Through these outlets Hd Okwa Drilling services hopes to transform the well delivery landscape in the country and catalyse a speedy development of the marginal resources.

What is your outlook on Nigeria’s Upstream sector for 2021?

The environment is very challenging. There is demand for Nigerian oil with the ongoing commissioning of Dangote’s 650,000 BOPD refinery, and several modular refineries. These refineries will help reduce dependence on imported fuel, and not only satisfy local consumption, but fulfil demand across Africa and many of the developing world, who would still be dependent of oil consumption for the foreseeable future. As our contribution to the preparation, we are developing local manpower by running courses like the

Well Design Masterclass,
Re-Entry and Workover Engineering Masterclass,
Abandonment and Decommissioning Planning Masterclass.

We also extending our collaborations to experts overseas, who we are bringing to run specialist training in Nigeria for Nigerians, at very low price. We are also developing ourselves in readiness for the future challenges. For example, I am completing my Master of Science in Innovation and Entrepreneurship at the No.1 Business School in Europe, HEC Paris. Thus, we are ready to make our contribution to energise the Nigerian oil sector.

Nigeria exports oilfield service expertise outside the country. Are you one of such providers? Does Hd Okwa Drilling have Pan African ambitions?

Not at the moment. The focus of Hd Okwa Drilling Services is Nigeria. In North America, drilling planning has really advanced, and the gap with Africa is very wide. So, we focus on Nigeria first, then we can expand to the other African countries later. Let charity begin at home.

Hd Okwa Drilling takes training a so seriously that it’s a full component of its spectrum of business. This is quite unusual in the Nigerian industry. Is training a highly monetised component of your business portfolio?

A direct answer is ‘NO’. However, we need a pipeline of skilled professionals to master the techniques and processes that we deploy. One way of doing this is through training and mentorship. We have established several specialists’ courses relating to efficient well delivery. These courses are available to both individuals and operators, at a fraction of the cost. Training cannot pay back if we are to consider the efforts we put in, as these courses are at the cutting edge of the future of well engineering. They cover Well Design Masterclass, Re-Entry and Workover Engineering Masterclass, Abandonment and Decommissioning Planning Masterclass, Efficient Cementing Technology, etc. We also organise team alignment workshops, well challenge sessions, drill-the-well-on-paper (DWOP) exercises, in addition to our normal specialist courses. Our resource persons are the leaders on the well engineering disciplines within Nigeria and the global industry.

The International Association of Drilling Contractors (IADC) Nigerian Chapter is always talking about training about quality and capacity of rig personnel, about safety on rigsite. Is your company looking at Collaboration with IADC?

We have it as part of our strategy to collaborate with the IADC Nigerian Chapter, on manpower development for the Nigerian industry. We are in the process of founding a Well Engineering professional organisation. When completed, the organisation will also be part of our springboard for driving down well costs in Nigeria by accelerating competence development of professionals through mentoring by Nigerian professionals with extensive international experience.

I am curious about a company calling itself strictly a Drilling Service company; why can’t you simply describe yourself as a full subsurface solutions provider?

Of course, we are a subsurface consultancy group. However, expertise in the other areas of petroleum engineering abound. As drilling requires long training and mentorship to attain professional maturity, it appears to be the area in serious need of attention. If well costs are allowed to continue to grow, the current lull in well construction activities will linger too long. There is need for urgency, as we cannot predict what would happen to Nigeria’s oil after 2030, which is only nine years time!

I see that you count Shell, Amni, and First E&P as part of your clientele. For indigenous companies who are mushrooming in Nigeria, the logistics of integrated project management can be so challenging they’d do better to outsource it. Is this the space you are after?

Shell, Amni, First E&P, Monipulo, Elcrest, Addax, etc, are some of the beneficiaries of our expertise and we have worked in one form or the other with these organisations. However, we are a technical consulting organisation. We use our expertise to help operators, reduce well costs. We do this by facilitating well design improvement, helping them eliminating non-productive times, and training and mentorship of personnel. Our project management activities are carried out through another organisation that we contribute expertise to.

Out of the several specialisations in Hd Okwa Drilling services: Well Cost Improvement Catalysis, Strategic Expertise & Technical Consulting, Well Operations Risk Elimination, which of them does Hd Okwa Drilling find most forward looking? And which are you best at?

Our expertise covers all areas, and we need all of them as arsenal to attack the monster of well costs escalation. We operate through several avenues:

In Non-Productive-Time elimination for example, our research showed that all NPT’s in the Nigerian drilling operations are caused by four main events namely Well control, wellbore instability, equipment failures and human errors. These events constitute 30% of the total time spent at the well site on a well. We have developed expertise that we use to support operators to eliminate these events.
Invisible lost time constitutes the least beneficial activity to the drilling operation, but are being carried because they can’t be detected. This time constitutes up to 50% of wellsite times. We collaborate with international experts to develop well operations analytics software. We currently support two – SMARD and CI Drill. Both software are creating disruption in the well analytics space. These two-software combined can eliminate up to 30% of all invisible lost times.
Drilling project management requires high level of expertise. The country has relied on Shell to develop drilling expertise for the industry in Nigeria. However, as the company has shrunk over the years, so have the number of professionals they develop. We contribute technically to H-PTP Energy Services which is full services well projects management organisation founded by like-mind professionals with strong international expertise.
We have developing collaborations and alliances with service suppliers to the drilling business to help them improve their services to international standards.
I act as Technical expert in well engineering such as expert witness, standards development, expert opinions, etc.
We have supported a financial service organisation to advise them on energy project funding.
We act as well examiner, in line with international standards, where we look at drilling project plans, and offer recommendations for improvement.
We conduct workshops to drive the ideas through the clients’ teams.
And, of course, training services. We are very good in this area.

The last annual report by Shell sounded so despondent about their experience out on the Nigerian oilfield environment. What is your message to international investors about the future of the Nigeria’s oil and gas market?

We need investors to help us develop the 4MMBOPD we need to develop the economy and enjoy the benefits of oil and gas. I think investors can help to improve the technical space in the local industry by patronising local expertise. For example, our organisation consists of high-level professionals with experience of global oil and gas industry, as well as internal consultancies such as McKinsey & co, as well as PWC, among others. These professionals understand international standards and procedures, and are able to offer advice to international level.

On the whole, the development of local refineries will help insulate the industry from the vagaries of international oil market cycles. With a population of 200Million citizens, Nigeria is the country to invest in. And the oil and gas leads the way.

EI’s New CEO is BP’s Former Head of Alternative Energy

Section: Petroleum People · April 11, 2021 · No comments |

Nick Wayth, formerly Chief Development Officer of Alternative Energy at BP, will take up the position of Chief Executive Officer of the Energy Institute (EI), beginning May 4, 2021EI is a British headquartered global chartered professional membership body, which says it “articulates the voice of energy experts, taking the know-how of around 20,000 members and 200 companies from 120 countries to the heart of the public debate”.Wayth takes over from Louise Kingham, who has headed the EI and its precursor bodies for more than twenty years.

Ms. Kingham is stepping down this month to become UK Head of Country and Senior Vice President for Europe at BP.Wayth, who holds a PhD in Mechanical / Electrical Engineering and a degree in Mechanical Engineering, both from the University of Southampton, has spent nearly 22 years at BP plc in a broad variety of executive and management roles. Most recently he held the post of Chief Development Officer of Alternative Energy, where he led BP’s strategy and business development in a broad range of renewable technologies, including solar, offshore wind and digital energy. Through this role he was also a member of the BP Ventures Investment Committee, sponsoring several of BP’s venture investments.

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

Section: In the news · April 11, 2021 · No comments |

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.

Nigeria’s High Well Costs are at the Heart of its CAPEX and OPEX Challenges

Section: Oil patch Sub-Sahara · April 11, 2021 · 6 comments |

By Ahmed Gafar, in Lagos

The astronomically high drilling costs of wells in Nigeria are key to the challenges faced by operators in reining in operating and capital expenses, an industry service provider has suggested.

If Africa’s highest crude oil producer is to reach its target of delivering Four Million Barrels of Oil Per day (4MMBOPD) in the near term, those costs need to be brought down, argues Hope Okwa, Founder/ Managing Director of Hd Okwa Drilling Services.

Hope Okwa

“A 10,000 feet well producing only 3,000 BOPD costs up to $25Million to construct in Nigeria”, Okwa allows. “To move from the current 1.5MMBOPD to 4MMBOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables?”.

Okwa is persuasive that he is not just throwing numbers around: “$25Million per well cost is true for land, swamp and shallow offshore, as the rigs all use surface blowout preventers.

“The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels”, he contends. “The sources of inefficiencies in well construction, is very much within our expertise”, Okwa declares: “it is very urgent to implement these solutions”, as “in nine (9) years’ time in 2030, the advanced countries will pivot away from fossil fuel. What will then happen to Nigeria’s reserves of 37Billion BO?”

Okwa’s benchmark is North America. “In Canada/USA, the rig rate for land is $32,000/day compared with $25,000/day for Nigeria. A 10,000 feet land well takes eight (8) days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2Million, while Nigeria is $25Million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5Million horizontal well for a Nigerian marginal operator, applying our techniques”..

Cost control in oilfield activities has been a front burner issue in Nigeria. Last February, the state hydrocarbon company NNPC had an elaborate event on cost optimization, at which Timipre Silva, Minister of State for petroleum, asked the country’s 34 oil and gas producing companies to join in working towards reducing operations cost to achieve the $10 or less per barrel production cost target.

Stakeholders have responded to Ministry of Petroleum’s call for cost control by naming causes including insecurity (You need gunboats full of naval officers on the way to rig-site) and taxation (government at all levels level multiple taxes: DPR hikes costs of obligatory services, State Governments demand various tariffs, Local Governments harass operators; communities hold up work; regulators sometimes delay).

Okwa counters that “those issues relate to production mainly, and companies are having to trade off drilling wells due to the issues mentioned and high well cost”.

Okwa has 29 years industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deepwater operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another stint at BP Angola as senior drilling engineer.

“We believe that if we reduce well costs drastically.. we will be able to stimulate activities”, he says. “If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.

The full interview is in the link

Elohor Takes Over SNEPCO From Bayo Ojulari

Section: Others, Petroleum People · April 11, 2021 · No comments |

By Sully Manope

Elohor Aiboni has taken over from Bayo Ojulari as Managing Director of Shell Nigeria Exploration and Production Company (SNEPCO).

She is the first woman to take the job, which has become increasingly important as AngloDutch Shell increases its focus on deep-water, hub-scale opportunities.

Mrs. Aiboni’s chief immediate task is to find a way to achieve Final Investment Decision (FID) for the pending Bonga SouthWest Aparo (BSWA) project, a job that Ojulari laboured over in the last three years. If she is lucky, she might even witness, on her watch, the 150,000BOPD (peak production) project from construction to first oil.

A 1999 bachelor of science degree holder in Chemical Engineering from the University of Benin, and Masters’ degree in Integrated Environmental Management from the University of Bath in the United Kingdom, Aiboni has moved through the ranks, serving as operations support engineer in Shell’s Eastern Nigeria Division and team leader on the relatively large Obigbo oil field (around 160Million barrels reserves as of 2008), straddling two Oil Mining Leases (OMLs) 11 &17.

Her first look-in into Upper Management philosophy was as Business Analyst to the Executive Vice President Shell E&P Africa. She then moved on cross posting to Kazakhstan, where she was part of the Kashagan project, returning to assist in overseeing the divestment of Shell’s onshore eastern assets(OMLs 18, 24 & 29) in 2014/2015.

Aiboni’s first work on a Nigerian offshore asset was as operations manager of the Floating Production Storage and Offloading (FPSO) facility on the shallow water EA field, which is a SNEPCO asset, in 2015. She moved into deeper waters three years ago, when she was appointed Asset Manager for the Bonga project, Nigeria’s flagship deepwater field.

That appointment can now be interpreted as the training opportunity for Elohor Aiboni to take the reins of SNEPCO.

Nigeria Unlikely to Meet Mid Term International Targets for Universal Electrification

Section: ENERGY TRANSITION · April 10, 2021 · 1 comment |

By Bunmi Aduloju, NAREP Fellow

Nigeria has fallen far behind the main internationally set target for energy access, to which it had itself been an active participant, a review has shown.

The country’s current quantum of electricity delivery and its near-term prospect of Universal Electrification, do not come anywhere close to the 2030 targets of the Sustainable Development Goals (SDGs), set up by the United Nations, our review indicates.

17 Sustainable Development Goals (SDGs) were formulated bythe United Nations (UN) in 2015 to address the environmental, economic, political and social challenges facing the world.

Sustainable Development Goal 7 (SDG 7) is a “blueprint to achieve a better and more sustainable future for all.”Specifically, Sustainable Development Goal 7.1 calls for “universal access to affordable, reliable and modern energy service.”

In the Sustainable Energy for All (SE4ALL) Action Agenda, Nigeria’s implementation tool for the Sustainable Development Goal 7 (SDG 7), the country has a goal to reduce share of the population living without electricity to about 10% and increase electricity generation to at least 32,000MW by 2030.

Let us consider the current figures.

Electricity Access

Eighty Five Million people lack access to grid connection electricity in Nigeria, leaving 43% of the population without electricity access. The country, in effect, has the largest energy access deficit in the world. Nigeria’s 206Million people share an installed capacity of 12,555MW, but only about 4,000MW is distributed to Nigerians on most days by the seven generation companies (GenCos). On the other hand, South Africa and Egypt, whose economies are second and third largest to Nigeria’s, in Africa’s GDP ranking and with population of 59Million and 85Million respectively, have installed capacity of 58,095 MW. This is way higher than Nigeria’s installed capacity despite Nigeria’s larger population.

According to the Nigerian Electricity Regulatory Commission (NERC) in its 2020 second quarter report, Nigeria recorded 5, 316MW as the peak daily generation on the 20th of April, 2020. If on the 20^th of April 2020, 5,316 MW was distributed to energy consumers, and 85million people do not have access to electricity, the remaining 121 million Nigerians got an average 44watts of electricity supply.

This explains the constant power outages in the nation. Whole communities frequently bear the brunt of the nation’s power supply incapacities. In 2015, 444 communities spanning 18 local government areas reportedly lacked electricity in Edo State. Similarly, it was reported that residents of a particular Local Government Area in Ekiti State experienced total blackout for three years.

Because Nigerians are not always entitled to 24-hour power supply, many businesses, homes and offices have had to fall back on petrol and diesel back-up generators.

Nigeria ranks as one of the six top countries generating energy with back-up generators fuelled by high quantities of fossil fuel, according to the International Finance Corporation, World Bank Group in a report titled, The Dirty Footprint of the Broken Grid. Apart from the environmental degradation that ensues from the use of back-up generators, it poses outrageous health hazards to anyone who inhales its fumes, as its emission contains carbon monoxide. A handful of Nigerians have lost their lives to fossil-fuels powered generator fumes which could be averted if there is continual 24-hour power supply in the nation.

Early in the year, two undergraduates reportedly lost their lives after inhaling generator fumes.

Renewable Energy, the Future of Improved Energy Access

Renewable energy is top on the United Nation’s radar to provide widespread energy access to unreached communities, and it has proven to be a long-lasting solution to the electricity access problem in Nigeria and Sub-Saharan Africa at large, as only 47.7% have access to electricity in Sub-Saharan Africa.

The Nigerian government insists that it is making efforts to provide electricity to provide direct support for rural electrification. As part of its Post-Covid National Economic Sustainability Plan, it proposed a Solar Home System (SHS) in 5Million homes which will serve about 25Million Nigerians in rural areas without access to the National Grid. This is a commendable approach to rural electrification.

Segun Adaju, President, Renewable Energy Association of Nigeria (REAN) and CEO, Consistent Energy Limited, speaks glowingly of the government’s efforts to deploy renewable energy in the nation’s power delivery said,

“Government has been part of the growth we have seen in renewable energy in the last three to five years through the rural electrification agency. There is now a 10 megawatts wind farm in the Kastina State. Also, Bayero University runs on solar now. Also, several hospitals are on solar, powered by the government.”

Renewable Energy to the Rescue

The generation capacity of renewable energy for power generation in Nigeria is relatively low, compared, again with South Africa and Egypt, the two economies with comparable GDP size to Nigeria.

These two countries each generates over 3,000MW of grid connected solar and wind power, whereas Nigeria generates less than 50MW from solar and wind technologies.

According to the US Energy Information Administration (EIA), “Nigeria’s generation capacity was 12,664 megawatts (MW) in 2017, of which 10,522 MW (83%) was from fossil fuels; 2,110 MW (17%) was from hydroelectricity; and 32 MW (1%) was from solar, wind, and biomass and waste.”

Since renewable energy will not dry up one day like fossil fuels, Nigeria should increase focus on developing the renewable energy sector for improved power generation. The increased contribution of renewable energy to the energy mix will allow for greater power generation.

China is a perfect illustration of a country that has harnessed its renewable energy potentials for electricity generation. China has the world’s largest hydropower capacity with 356GW in 2019. With this advantage, it tops as the world renewable energy generation producer.

Hydropower

Nigeria has water resources in the form of water falls and large rivers. With these natural potentials, hydropower serves as the most efficient renewable energy resource for power grid generation in the nation.

Nigeria’s 2015 National Renewable Energy and Energy Efficiency Policy (NREEEP), aims to harness hydropower production to ensure sustainability. It aims to generate 12,801MV of power from hydropower in 2030 and generate 30% in the energy mix.

Similarly, in the Renewable Energy Master Plan (REMP), there is a plan to increase renewable electricity supply to 36% by 2030.

If these targets are met, Nigeria would speed up its energy access by 2030. If not, Nigerians will continue to suffer from electricity deficiencies.

Solar

Another potential viable in the nation is solar. Solar energy has proven its ability to reach every nook and cranny of the country. It is safe to say that solar is the answer to the electricity access problem in the nation. Nigeria is blessed with abundant sunlight with about 2600hours of sunshine per year. Although Nigeria is increasing its prowess in this sector, the potentials are not fully harnessed.

Mr Segun Adaju urged the government to utilise the solar resources in Nigeria to solve the electricity access problem for rural communities.

“Solar power can be harnessed because of the country’s location. Instead of building massive power plants or grids, Nigeria should redeploy straight to distributed renewable energy like we have in the movement from telephones to mobile phones,” he admonished.

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.

Africa Under Siege?

Section: ENERGY TRANSITION · April 10, 2021 · No comments |

By Gerard Kreeft

“Africa has abundant natural resources and the associated revenues could be an important motor for development. However, changing global energy dynamics mean that resource-holders cannot assume that their oil resources will translate into reliable future revenues. “

Source: World Energy Outlook Special Report, Africa, IEA, 2019

The COP26 (UN Climate Change Conference) will be hosted by the UK Government in Glasgow in November 2021. TheSummit is to accelerate action towards the goals of the 2015 Paris Climate Agreement.

As part of its Green Energy Roadmap the UK Government and the oil and gas industry reached a historic accord: companies will be allowed to continue oil and gas exploration in the North Sea, but the industry must cut its carbon emissions by 50%. Companies must pass a ‘climate compatibility’ test if they want to continue working in the North Sea. The government and industry have pledged up to £16Billion to help support 40,000 North Sea jobs.

The compromise falls short of the total oil and gas exploration ban that was rumoured some weeks ago. Yet it is a stark reminder that in the UK portion of the North Sea, the oil and gas industry has become a sunset industry. These measures arepart of the UK Government’s commitment to be CO₂ neutral by 2050. How long will it be before North Sea exploration and development is banned totally? Will the industry’s fossil fuel assets help buttress the energy transition to ensure that renewables are a mainstream fuel?

How well is Africa prepared to be CO₂ free by 2050? What contribution can be anticipated from Africa’s oil and gas sector?

Should Africa be given dispensation and consequently more time to rid itself of CO₂ emissions beyond 2050? After all,emission levels in Sub-Sahara’s two major petro-economies- Nigeria and Angola- are negligible when compared to Chinaand the USA. Nigeria emits only 0.73%, Angola 0.25% vs China’s 28% and the USA 15%.

Set this argument aside. Instead make the case for national oil and gas companies using their fossil fuel assets to buttress up their energy transition. Again turn to Sub-Sahara Africa’s two major national oil companies: Nigerian National Petroleum Corporation(NNPC) and Sonangol in Angola.

The case of Nigeria

At the recent AOGS (Africa Oil and Gas Summit)Energy Webinar Series Energy Transition and the implications for Nigeria, the main theme was: “Is Nigeria’s 40Billion barrels proved reserves(or parts of), at risk of being written off someday to be replaced by green energy assets in the portfolio mix of the major oil companies?”.

A key response was that Nigeria should align itself with the Paris Climate Accord and adapt steps for a Green Roadmap: key would be leveraging the oil and gas assets to finance the green economy.

Certainly the discussion that has raged around the Petroleum Industry Bill(PIB), which promises to be a framework for the hydrocarbon industry, is not encouraging. Toyin Akinosho, Publisher, Africa Oil + Gas Report, has delivered a resounding critique. The PIB promises to be an award toNNPC for its continuing incompetence. He cites the following examples:• NNPC is a joint venture that produces 45% of the country’s crude; and concessionaire in the Production Sharing Contract(PSC) arrangements, which delivers 39% of the crude.• NPDC the operating subsidiary of NNPC …”is a massive imcompetent wrecking ball, which has been gifted joint-venture participation in 10 mining leases(OMLs) all of them producing”. • NPDC is seen as a bright star within the NNPC’s portfolio. Why? Because the degree of its performance is in direct proportion with the help it gets from its partnership with private entities.• Tinkering with the legislative structure of NNPC will change little given that its shares will continue to be monopoly control by the Government.

If NNPC is perceived of not having its own house in order how can it expected to be a leader in the Energy Transition? Does it make any sense to give the same driver, who drove the initial bus off the cliff, keys to drive the new bus?

The case of Angola

Since Joao Lourenco replaced Jose Eduardo Dos Santos as Angola’s head of state in 2017, Sonangol, the state oil company, has had a rocky ride. In the past Sonangol had two roles: that of concessionaire, a highly judicious key role which gave it the power and legitimacy it had achieved and being a state oil company with its responsibilities for exploration and development of the resources. The decision to strip Sonangolof its concessionaire role was then taken and given to the newly created ANPG (National Agency of Petroleum, Gas and Biofuels).

In the Angola of today power has become diffused: Sonangolhas been stripped of its concessionaire role and is loaded with a mountain of debt; and the International Oil Companies (IOC’s) have the freedom to explore and market their natural gas. Developing green energy is certainly beyond the competence of Sonangol.

In November 2019 a new National Gas Consortium (NGC) was established, led by ENI as operator in partnership with BP, Chevron, TOTAL and Sonangol for the exploration and production of natural gas. This was previously the exclusivedomain of Sonangol.

Currently a gas processing plant is being constructed toprovide natural gas to Angola LNG, the country’s sole LNG facility. Any excess natural gas would be used by the SoyoPower Plant, which is being expanded and could supply gas to Three Million households in the future.

Angola is not a gas rich country: having only 27 TCF of natural gas reserves which pales in comparison to that of Mozambique which has a gas reserve base of 100 TCF, third largest reserve base in Africa, after Algeria and Nigeria.

Developing a national gas strategy for the country’s industrial development is seen as a top priority. What role does Angola LNG’s future gas supply play in any national gas strategy? Does it make any economic sense to be exporting natural gas when so little is known about Angola’s own future requirements? What is the long-term planning for gas development and monetization? And how does this fit into the national development strategy? If natural gas is viewed as the fuel of choice to help develop an industrial corridor a strategy must be developed.

Green Shoots on the Horizon

In its African Energy Outlook, 2019, the International Energy Agency (IEA) paints a vivid picture of Africa’s current situation and how it could possible develop in the future. The Agency predicts, in its Africa Scenario that one-in-two people added to the global population between now and 2040 will be African.

Nearly half of Africa’s 600Million people did not have access to electricity in 2018, while around 80% of sub-Sahara African companies suffered frequent disruptions leading to economic losses.

The Africa Scenario is a plea for full access to modern electricity by 2030, tripling the average number of people gaining access per year from around 200Million to over 600Million. Grid expansion and densification is the least cost option for nearly 45% of the currently deprived, mini-grids for 30%, and stand alone systems for 25%.

LPG is used by more than half of those gaining access to clean cooking in urban areas in sub-Sahara Africa; in rural areas, home to the majority without access, improved cookstoves are by far the preferred solution.

Although the African economy will grow four-fold by 2040, energy efficiency can limit primary energy to just 50%.

Current electricity demand in Africa is 700 terawatt-hours(TWh) with only North Africa and South Africa accounting for over 70% of the total. In the African Scenario growth could reach 2300TWh. Much of the additional demand coming from middle and higher income households.

Solar is only 5GW, less than 1% of global installed capacity. In African Scenario solar overtakes hydropower and natural gas to become the largest electrical source in Africa in terms of installed capacity.

Tripling of the electricity demand requires building a more reliable power system and a greater focus on transmission and distribution to reduce power outages. Significant scale-up of investment in grids and generation is required given that Africa has 17% of the world’s population and just 4% of the global power supply.

Natural gas meets half of North Africa’s fuel requirements, but in sub-Sahara Africa only 5%. Gas will rise to 24% by 2040, mainly to power industry.

Green Shoots in Nigeria

According to the African Scenario the Nigerian economy will triple and would require less energy demand if the energy mix were more diversified. Natural gas must meet a growing share of energy demand, supported by implementation of the Government Gas Master Plan.

Today 80% of power generation comes from gas, most of the remainder comes from oil with Nigeria the largest user of oil-fired back-up generators on the continent. Natural gas remains the main source of power, although there is a shift to solar energy as the country starts to pivot towards its large solar potential.

Provided that reliability and supply improve, the grid could become the optimal solution to provide almost 60% of people with access to electricity. Nigeria achieves universal access by stepping up efforts to provide off-grid solutions to those that live off-grid.

Nigeria is a major industrial producer and a large chemical exporter and will triple chemical products by 2040 with new methanol and ammonia plants.

The country has the 2nd largest vehicle stock in sub-Sahara Africa: the number of vehicles could grow from 14 to 37 Million by 2040 with only two-times more oil consumption if more stringent fuel standards were adopted.

Universal access is achieved through greater household access to gas networks and LPG in the main cities, and improve cookstoves in rural areas.

Green Shoots in Angola

The Government is pledged to having 60% of Angolan households access to electricity by 2025. According to Angola’s Ministry of Energy and Water the country will by then have an electrical capacity of 7.2 GW, four times the current capacity.

In December 2020 the Lauca Hydroelectric Power Station was completed and can now provide 2.7GW of electrical power to the national grid. A second project, the Baynes Dam, is jointly being constructed by the Governments of Angola and Namibia and will provide 600 MW to both countries.

The Angolan government has partnered with Power Africa, a U.S. Government-led partnership coordinated by the U.S. Agency for International Development (USAID), and the African Development Bank (AfDB) to start a major transmission project, which aims to connect the central and southern power grids of Angola.

The programme will create an interconnected national grid supplying north, central and south Angola to create a 60% electricity access rate by 2025.

Power Africa will also be assisting the AfDB in connecting pre-paid meters. In December 2019, the government was granted a $500Million loan package from the AfDB to finance the program. The beneficiaries of the project include households, industries, businesses and small to medium sized enterprises in Angola, with the aim of increasing access to cheaper, more reliable and sustainable electricity.

Conclusions• The history of both NNPC and Sonangol is a checkered and toxic history. Can they provide the leadership in the energy transition in which oil and gas is promised to be a key element?• A national oil company-be that NNPC or Sonangol- have different agendas than the IOCs. Politics and national lobby groups is the mechanism that steers national oil companies, not shareholder value nor investment returnsthat are the main driving forces of the IOCs.• The IOCs are constantly juggling their portfolios in order to maintain profitability and low carbon emissions. They have no hesitation in abandoning assets which do not meet investor grade, leaving their national oil company partners scrambling. • Doesn’t it make more sense to start from a clean slate? In which renewable energy is marketed and produced without any attachments?• The IEA in its African Energy Outlook recommends that the developed countries should take the lead in providing financial assistance to countries less endowed and more vulnerable. For some time this has been an issue which many developed countries resisted, perhaps frightened of sounding paternalistic and seeming heavy-handed. • Yet given that Africa’s total emissions on a global basis are so negligible and its oil and gas assets will probably be discounted, the economics for accepting payment from the industrialized countries fits into this new market place of the energy transition.• Why not for for example let China write off a portion of Angola’s debt to China which totals some $25Billiongiven that China has more than one quarter of global emissions? This would allow Angola some breathing space and possibly set a precedent for other bilateral emission deals between China and other African countries.

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

Nigeria Puts the Brakes on Ambitious Biofuels Refinery Plan

Section: ENERGY TRANSITION · April 9, 2021 · 1 comment |

By Bunmi Aduloju, NAREP Fellow

It’s been 14 years since Nigeria gazetted its Biofuel Policy and Incentives, but the country can boast of next to nothing in domestic biofuel production.

Nigeria, being heavily dependent on fossil-based fuels, took this bold step in June 2007 to reduce the rate of environmental pollution in the country, as recognised by the United Nations (UN) as a universal problem causing climate change.

In essence, the world wants to cut off fuels that are bad for the environment and biofuels are in tandem with the demand for clean energy, producing less emissions than petroleum-based fuels.

The world’s top five biofuel producers include those countries with comparable populations with Nigeria’s200Million people: the United States (pop:330Million), produced 13 Billion gallons of biofuels in 2019. Brazil(pop: 212Million), produced 8.1Billion gallons of biofuels; Indonesia (pop: 273Million) output 2.3Billion gallons of biofuels and some of Europe’s, largest economies: Germany and France produced 1.2Billion and 0.9Billion gallons of biofuels respectively in 2019.

As the national debate rages in Nigeria about removal on subsidy on crude-derived gasoline, and cleaner and cheaper alternatives are considered, infrequent mention is made of biofuels, not for cost, but for cleaner air.

Nigeria could also be a top producer of biofuels and even an exporter, since the nation is blessed with vast resources in energy crops and biodegradable waste used in their production. Regardless of the many advantages of biofuels, the narrative is entirely different in the nation today.

In 2019, Ibe Kachikwu, Former Minister of State for Petroleum, while speaking at a biofuel sensitisation workshop emphasised the economic value of biofuels.

“I believe biofuel will soon become our foreign exchange earner, if we can put our minds and might into it. We can produce crude and fire gas but, ultimately, the only way to sustainably reach every nook and cranny and every citizen of our country with some level of energy supply, is to look towards natural resources such as solar, wind, water resources and biofuel,” he said.

Biofuel Policy

In the National Biofuel Policy and Incentives published in 2007, a direct reference was made to the government’s mandate to the Nigerian National Petroleum Corporation (NNPC) to create an Automotive Biomass Programme in 2005 which would establish an environment for the take-off of a domestic fuel ethanol industry.

With the Automotive Biomass Programme in place, the National Biofuel Policy and Incentives was gazetted in 2007 to further propel the domestic production of biofuels. It aimed to “achieve 100% domestic production of biofuels consumed in the country by 2020.” While the policy directed several bodies to contribute to this national outlook, the downstream petroleum sector and the agricultural sector have integral roles to play in the accomplishment of the programme.

Unfortunately, there is a gap between the policy demand and actualisation as a result of several underlying issues. Nigeria still relies on importation of fuel ethanol, an additive for gasoline whilst still grappling with non-implementation of its biofuel policy.

The World of Biofuels

Biofuels refer to “fuel ethanol and biodiesel and other fuels made from biomass and primarily used for automotive, thermal and power generation.” It’s main claim to preference over fossil-based fuels is its renewable and environment friendly chemistry.

Fuel ethanol is blended with gasoline for more environmentally-friendly emissions and this blend has proven to improve the quality of fossil-based fuels by oxygenating the fuel thereby resulting in less carbon emissions and higher octane levels.

For this reason, some countries are imposing a mixture of transport fuels with biofuels in order to reduce greenhouse gas emission. In the United States, more than 98% of their gasoline is mixed with ethanol forming a 90% gasoline and 10% ethanol mix.

In Nigeria, the biofuel policy projects a 90% gasoline – 10% fuel ethanol mix while a 20% blending ratio is to be deployed for biodiesel with the Nigerian National Petroleum Corporation (NNPC) enforcing the blending requirements. With the daily national consumption of gasoline estimated by the department of Petroleum Resources, DPR to be 38.2Million litres of gasoline per day, Nigeria would require 3.82 million of fuel ethanol per day to meet the fuel ethanol-gasoline blend goal. This is a huge responsibility for biofuel production in the country considering its present state.

Fuel Ethanol Import, Bad for Domestic Production

In 2018, Nigeria spent $33Million on the importation of ethanol from the U.S and it was the second most imported agricultural product from the U.S into Nigeria, constituting about 48% of total ethanol import into the country, according to the United States Department of Agriculture (USDA), Foreign Agricultural Service (FAS).

This speaks volume about the country’s capacity for the achievement of the 100% domestic production goal. Apart from Nigeria’s failure to achieve its stated goal, importation puts undue pressure on the nation’s economy and weakens local production initiatives. With over-reliance on foreign imported fossil-based fuels and its economic impact on the nation, it is wise to avoid trailing the same path with biofuels.

Despite Local Abundance, Crop Feedstock Derivatives Imported

Since crop feedstock used for the production of biofuels have to be cultivated in large scale, there’s been growing concerns about its competition with food production in the country, as all the biofuel feedstock cited in the policy are food crops except jatropha. Apart from that, Nigeria is capable of cultivating the designated biofuel feedstock, including oil palm, jatropha, cassava and sugarcane.

Nigeria is the largest producer of cassava, producing about one-fifth of the world’s total production, according to the Food and Agriculture Organisation (FAO). “It is incongruous that the world’s largest producer of cassava spends $600Million annually to import cassava derivatives”, the Governor of the Central Bank of Nigeria (CBN), lamented at a meeting in 2019.

FOURTEEN YEARS AFTER, UNFINISHED PROJECTS.

In 2012, Global Biofuels Ltd signed a ₤2Billion deal with the Nigerian Government for a biofuel production complex at Ilemeso, Ekiti state, Nigeria. TV

Similarly, Kogi State Government, under the leadership of Yahaya Bello signed a MoU with the Nigerian National Petroleum Corporation (NNPC) for the establishment of biofuel projects in the state.

Foreign investments and private sector investment have also been made since the policy was published in 2007.

The NNPC signed MoUs with State Governments for the building of fuel ethanol plants and cultivation of biofuel feedstock, some of which include Kogi, Kebbi, Gombe, Benue, Anambra, Cross Rivers and Ondo

Despite these initiatives, the NNPC has still not kicked off large scale commercial production of biofuels as directed by the policy.

In press release after press releases and statements after optimistic statements , Maikanti Baru, former Group Managing Director (GMD) Nigerian National Petroleum Corporation (NNPC), -2016-2019- disclosed that the first large scale commercial biofuel venture as an alternative to fossil fuel was going to commence.

On the 28th of February 2018, he also revealed at the 39th Kaduna Trade Fair that NNPC was driving investment in renewable energy to develop biofuel production through the Renewable Energy Division in a press release.

Both reports were bound by the same promise to kick start large scale biofuel production with a bleak timeline for accomplishment.

In 2021, the Gombe State Government reportedly expressed willingness to partner with the NNPC to actualise the sugarcane fuel ethanol project in the state in 2021. In the same report, the Group General Manager, Renewable Energy Division (RED) of the Nigerian National Petroleum Corporation (NNPC), David Bala Ture, revealed that despite efforts to actualise the biofuel project in Gombe State, it had not come to fruition for the past 15 years.

This is the backstory of many biofuel projects in the country. Some projects are abandoned, others are suffering from lack of cooperation from the various parties involved in the deal and some others, lack of technological advancement.

An effective policy, however, will solve a number of these problems.

Although Nigeria has a biofuel policy in place, it has not fully implemented its policies since 2007. In fact, in 2010, the policy was reviewed by the Petroleum Products Pricing Regulatory Agency (PPPRA) and a number of committee members, to address the loopholes in the official gazette. However, there has been no concrete agreement between the key players and the governmental bodies involved to utilise the policy’s directive and this has caused setbacks in the implementation of the policy.

The private sector has been making efforts to produce fuel ethanol and biodiesel but lack of proper infrastructure is deterring large scale production by private companies.

Part of the challenge, argues Ejikeme Nwosu, Director, Lumos Laboratories Nigerian Limited, who has worked on conversion of waste to energy sources in the last 14 years, is the lack of infrastructure and grants to private initiatives for the production of biofuels. “The private sector is filled with masterminds ready to work with the sector once the policy is fully implemented and when the government pays more attention to them,” Nwosu explained.

This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.

Decklar Moves A Rig for Oza-1 Re-entry

Section: Oil patch Sub-Sahara · April 9, 2021 · No comments |

Canadian minnow Decklar Resources has contracted a 1300 HP trailer-mounted drilling rig that is currently located in Port Harcourt, approximately 60 km from the Oza Oil Field in Nigeria’s Niger Delta Basin.

The drilling rig will be used for the re-entry and testing of the Oza-1 well, then immediately followed by the drilling of a horizontal development well from the Oza-1 drilling pad.

Oza field is a marginal field operated by Millennium Oil &Gas, currently producing no more than 400Barrels a day.

Decklar Resources has consummated a risk service agreement with Millennium Oil &Gas and its partners on the field, to fund and technically operate a revamp which will lead to increase in output.

The company says that drilling of additional development wells is planned after completion and analysis of the re-entry and horizontal wells at the Oza-1 location.

It is anticipated that the drilling rig will commence its mobilization to the Oza Field in the week of April 12, 2021, with the move expected to take approximately seven days.

Further, the camp to house the personnel engaged to provide support for operations and related logistics facilities is currently being moved and set up at the Oza Oil Field.

Additionally, equipment and supplies with longer lead times that are needed to test and complete the Oza-1 well as part of the re-entry activities have been ordered, secured, and are expected to arrive in Nigeria over the next two to five weeks. Service contractors have been sourced and contracted for the near-term operational activities.

Angola’s Onshore Kwanza Basin offers an underexplored basin with a world class petroleum system.

Section: Geosciences · April 8, 2021 · No comments |

By Matt Tyrrell and Alessandro Colla, Trois Geoconsulting BV; Mike Oehlers, Tectosat Ltd

Seasoned explorers of Africa and the Atlantic margins will be familiar with the quandary of choosing between offshore and onshore acreage. Offshore acreage typically offers large, inexpensive seismic datasets with which to identify prospects, but the costs of drilling and developing these require significant inward investment. Conversely, onshore acreage allows numerous wells to be drilled at a low cost, but the ability to locate and de-risk prospects is limited by the expense and paucity of exploration datasets, particularly seismic.

This quandary is particularly apparent in the coastal basins of West Africa, where the Mesozoic sedimentary successions, including salt, extend into the onshore domain. In this basin, seasoned explorers will be tantalised by the opportunity to drill salt-induced prospects within a proven petroleum system and will be seeking the necessary datasets with which to de-risk them.

There are, however, onshore basins where this quandary is not so apparent; where extensive high quality datasets are available and early exploration has suitably de-risked proven pre- and post-salt petroleum plays. One such example is the Onshore Kwanza Basin of Angola – a Mesozoic salt basin with numerous undeveloped fields, a library rich in accessible yet low-cost exploration datasets and local refineries and markets for hydrocarbons once they are produced.

Furthermore, a licence round that opens towards the end of 2020, supported by new oil and gas laws and fiscal incentives, provides the opportunity for oil companies to secure rights to this acreage, appraise discovered fields and potentially fast-track commercially viable hydrocarbon production.

Underexplored Pre-Salt

To understand the future potential of the Onshore Kwanza Basin, we must first understand its exploration history.

A key milestone occurred in 1955 when the post-salt Benfica oil field was discovered just south of Luanda, after which exploration drilling peaked; by the late 1970s 133 wells had been drilled. This era of activity saw the discovery of 11 oil fields, as well as a few gas fields, with the largest containing more than 200 MMboe, made possible by the availability of 11,500 line-km of dynamite 2D seismic data. The last onshore field discovery was in 1972 and the last well was drilled in 1982, from when on interest in the onshore declined, in part due to socio-political stability risks but more likely due to the early successes of offshore exploration. Only nine oil fields have ever been reported as having been put onto production, which include the Cacuaco and Puaca fields, both with pre-salt reservoirs.

Although at first it appears that the Onshore Kwanza has been considerably drilled, analysis of well penetrations and results tells a story of high success rates in post-salt wildcats contrasted with a prospective yet significantly underexplored pre-salt succession. Of the 237 wells drilled, just 28 penetrated beneath the salt; four pre-salt fields were discovered prior to 1971 (Cacuaco, Uacongo, Puaca and Morro Liso) despite only three wells testing a meaningful section of pre -salt stratigraphy. When our seasoned explorers analyse the results of these pre-salt wells they must be left pondering what might have been found had the operator drilled a little deeper.

An initial observation is that the majority of pre-salt penetrations were drilled from wellheads located for post-salt prospects with only a handful of wells spudded with a pre-salt objective. Furthermore, assumptions about 1960s and 1970s technology and know-how suggest that modern field appraisal methodologies could reveal where discovered fields may actually be commercial, whilst advanced well stimulation techniques could lower the commercial threshold.

Updated Datasets Support Exploration

In 2010 and 2011, 2,581 line-km of high quality 2D seismic data was acquired followed by the acquisition of high resolution aeromagnetic data. A new GIS GeoDatabase named KMAP-2020, commissioned by Sonangol in 2015, was then completed as part of the reassessment of the remaining oil potential ahead of licence rounds. This product, available for the whole onshore basin or for individual blocks, includes outcrop information, petrographic studies and palaeontological reports from recent field trips together with seismic profiles, well stratigraphy panels and geosections.

The KMAP-2020 database has recently been further refined by the inclusion of modern satellite imagery supplied by specialist, Tectosat Ltd. Using Landsat imagery, SRTM DEM, ASTER and PALSAR Radar data*, the whole basin has been remapped at a much more comprehensive 1:50,000 scale involving interpretation at 1:25,000 scale, with additional integration of lithological detail from some 3,000 field sample points.

The resulting updates to the surface geology maps within the KMAP-2020 database have positive implications for de-risking the underlying petroleum systems. Halokinetic activity is evinced in anomalous domes and basins showing salt withdrawal and folding adjacent to the main bounding faults of the Tertiary troughs.

Fault expressions mapped at surface have been used to understand structural controls related to various tectonic episodes. Where it is shown that many of the Tertiary-aged faults are soft-linked to deeper syn-rift structures, the charge of post-salt reservoirs with pre-salt oil can be de-risked.

Similarly, areas of Tertiary uplift are observed in the vicinity of Blocks 11 and 12 where present-day river systems are seen to have incised; this uplift may have hinged to the north at the Cabo Ledo fault. These details are key in determining long-distance migration paths from known source kitchens, including the offshore, into pre-salt and post-salt structures; indeed, the presence of basin margin oil seeps together with the pre-salt Cacuaco Field north-east of Luanda suggest that the sub-salt section should be suitably charged.

Underexplored Area in New Licence Round

An integration of past exploration results, available seismic and well datasets with the KMAP-2020 database (which includes the satellite imagery interpretation) demonstrate that the Onshore Kwanza Basin is a world class petroleum basin that in recent decades has been considerably underexplored.

The post-salt section has numerous anticlinal closures that are untested; where these have been drilled the structures exhibit good reservoir qualities and host viable oil fields, such as those at Quenguela and Benfica. Where sampled, the pre-salt is shown to exhibit good quality carbonate reservoirs formed by coquina.

Exploration

shoals with vuggy porosities as well as fluvial-deltaic sandstones. The hydrocarbons encountered here are light oils with gas and with no known encounters of CO2 or high sulphur content.

When the results of the updated ArcGIS geological study are combined with available seismic and well datasets, conclusions can be drawn that suggest that the upcoming licence round may be the trigger for the first commercial production of oil from onshore Kwanza.

Recent announcements by the newly formed ANPG (National Agency of Petroleum, Gas and Biofuels) have defined a strategy for the allocation of petroleum concessions including open acreage within all of Angola’s basins. Concessions will be awarded through a process of public tender, restricted public tender and direct negotiation over a period of seven years, starting in 2019 and culminating in 2025.

The blocks offered by public tender are those that are deemed exploration blocks that have not formerly been abandoned and restored to the state. The blocks of the Onshore Kwanza Basin have been announced as a part of the 2020 licensing round, which will open in the fourth quarter of 2020. Blocks KON5, KON6, KON8, KON9, KON17 and KON20 are offered by public tender and these blocks all offer excellent potential for exploration as well as opportunities to appraise and develop discovered fields.

In August this year, the ANPG held a Clarification Session as a precursor to the opening of the round; during this session senior members of ANPG gave informative presentations and clarified the timeline for the submissions of bids and signature of the contracts.

Exceptional Opportunity

The history books of exploration bear witness to a multitude of junior exploration companies that secured onshore acreage, within a known petroleum province, yet were unable to successfully demonstrate to investors and potential farm-in partners that they could cost effectively de-risk a drilling location.

The Onshore Kwanza Basin is different in that it offers the opportunity to secure acreage containing a post-salt field or prospect that can potentially be appraised and brought into production, providing cash-flow to fund further pre-salt exploration where the prize may be bigger. The 2020 Angola Licence Round, which kicks off April 30, 2021, should therefore be in the plans of all junior and mid-sized oil companies.

* SRTM DEM (Shuttle Radar Topography Mission – Digital Elevation Mapping), ASTER (Advanced Spaceborne Thermal Emission and Reflection Radiometer), PALSAR (Phased Array type L-band Synthetic Aperture Radar)

This paper was first published in the October 2020 edition of GEOExPro magazine, https://www.geoexpro.com/articles

Nigeria’s Power Minister’s Bold Electricity Framework Stands on a Shaky Base

Section: Power Deficit · April 8, 2021 · No comments |

By Toyin Akinosho

Saleh Mamman, Nigeria’s Minister of Power, who has only spent close to 20 months in office, identifies liquidity issue as the most important challenge of the country’s electricity supply industry.

Nigeria generates around 5,000MW of electricity, which is inefficiently transmitted and poorly distributed.

Mamman has constructed a framework for the sector with, Infrastructure Alignment as the Number 1 focus. He wants to fix the infrastructure gap in Transmission and Distribution, by executing the Electrification Plan, which is, largely the Siemens Plan he met on the table.

That plan, which will cost around $2Billion aims to refurbishsome very important equipment and construct new ones, in order to deliver far more generated electricity than its being done now

Saleh’s second focus is a soft power item: Market Efficiency and Transparency..involving the refinement of the commercial technical, and regulatory components of transaction agreements; promoting fiscal discipline and effectively utilizing all sector loans (World Bank and Payment Assurance Facility) as well asenforcing market discipline and contract effectiveness by the regulator.

This is the area that the private sector part of the chain -the Generating Companies (gencos) and the Distribution Companies (discos) -has seen the most cause to criticize government for not addressing. So, it has to be addressed. But it can be far more challenging to deliver than building infrastructure and it is a perpetual work in progress. What it needs, for a start, is the high visibility of the Minister’s body language. And Saleh has shown a particularly good example.

In a recent case he queried the changes to the minimum capacity quantities of two power plants: Olorunsogo and Omotosho, by the Transmission Company of Nigeria (TCN). He publicly criticised the company’s non-compliance with the rulings of the Nigeria Electricity Regulatory Commission (NERC)-arguing, forcefully that such attitude of a government owned company to the regulator, “poses not only operational challenges but also reputational implications for the sector, and by extension, the Federal Government”. Saleh directed that NERC’s rulings “should be obeyed”.

The Saleh Blueprint’s third thematic focus area: Corporate Governance/Sector Policy Coordination may come across as different from the second, but the way to address it is similar: largely by the Minister’s own body language. In fact, if Mamman Saleh forcefully backs the NERC as a regulator, and vigorously promotes its independence, NERC would have little reason to think it has to court the National Assembly (the parliament) for approval on any issue. The same way the Minister addressed the case of TCN versus NERC case, and came out courageously to respond to the National Assembly’s suggestion to postpone the idea of cost reflectivity, his interventions can send out positive message about law and order on several other interface issues.

The Nigerian government has finally shown the politically will to allow a cost reflective electricity tariff, after significant pressure, ntably from the IMF..

The last two focus areas in Saleh’s Blueprint, are equally challenging: Increase Energy Access, which talks of extending the net of electricity offgrid and the Execution of Legacy Projects. These are two focus areas whose execution can readily slip because most of the work is outside the minister’s ready grasp.

For the Increase in Energy Access, which in the framing in Saleh’s blueprint, is largely about renewables and minigrids, significant inflow of capital is required, outside those already committed to the Siemens Plan and the Pre-Siemens funding on Transmission infrastructure. It is true that the Minister’s success in other areas, especially Market Efficiency and Transparency and Governance, will help in unlocking the vault, but these things have to be happening around the same time, so some Big Bold New Idea has to be seen by the Renewables Community and Private Equity Funders and Development Financiers around the World.

Regarding the Legacy Projects, a lot is riding on trust by the investing community, because, truly, in the year 2021, the Nigerian state shouldn’t be funding, from the treasury, a mammoth project like the 3,500MW Mambila Plateau Hydroelectric power. Yes, if that community sees that the needle is moving in the right direction in terms of Market Efficiency (Focus area Number 2) and Governance (Focus area Number 3), they will show interest. But we still need to provide solid commercial case

That is why we argue Saleh Mamman’s framework has a bit of challenge in detail.

I am not looking for nuts and bolts, but there is little inkling of what we can do differently to pull the likes of Mambilla, which will make a significant difference in generation capacity, even to communities not being served at the moment.

Nigeria’s BIG plan to unlock the suppressed generation capacity is the SIEMENS plan. But what are the equivalents of this idea for Renewable IPPs and the Legacy Projects? How do investors see clear line of sight to recouping their money?

We all know what happened about Renewables in South Africa between 2012 and 2015. The country was on the road to becoming one of the world’s largest renewable industries, without a single cent of government spend. And there were increasing localization achievements from Bid window to bid window -this was at government’s insistence and the investors were willing. Then (the power utility) Eskom started to talk down the commerciality and government, treating Eskom -as the be all and end all- made the mistake of listening too earnestly to Eskom. And all that investment dried up.

Finally, the Saleh Framework Plan is significant for what it says as it is for what it does not say.

One crucial thing it does not say is how the Ministry of Power will gain some handle on Gas to Power. I think that successive Power ministers have been too shy about demanding to understand the link between the reservoirs that geologists find, (and which engineers develop) and the Power Plants.

The mistake that is largely made is that “Oh: that broken link is a standard problem. Once it is fixed; everything will be alright. And the Ministry of Petroleum will fix it”.

No please, it’s a long, ongoing process of request, engagement, understanding, fixing, mitigation, all the time.

And it is better for the Power Ministry to be fully attentive, with its own men, to the little details. Because, when you make those transmission and distribution gains after the Siemens Plan is implemented, you will find that you’d be struggling to get the gas to generate the power you thought was there ready to be generated.

Olusegun Obasanjo, Nigeria’s President from 1999 to 2007, used to superintend a monthly, fortnightly meeting with gas producers, who were invariably the major oil companies. He convinced two of them (ENI, Shell) to build a power plant each.Those are today, some of the country’s most reliable plants and they most readily receive natural gas in the country.

I believe that, with how far Nigeria has come, the least the Minister of Power could do is to insist on a monthly meeting with the Petroleum Ministry, and every company that has a Gas Processing Plant (not all have) and every company that supplies some molecules into those poorly maintained, gas pipelines.

This article was initially published in the November-December 2020 edition of Africa Oil+Gas Report

Sasol ‘Outperforms Previous Best Efforts’

Section: In the news · September 8, 2014 · 1 comment |

Wants to be a trusted partner to countries seeking to add value to their hydrocarbon reserves.

Sasol CEO David Constable heartily declared the company as having “outperformed our previous best efforts”, with the annual report citing synfuels production of 7.6 million tons, the highest in a decade.

Africa’s largest petrochemicals company increased earnings attributable to shareholders for the year ended 30 June 2014 by 13% to $2.75 billion. Headline earnings per share increased by 14% to $5.59 and earnings per share increased by 12% to $4.52, over the same period.

Mr. Constable claimed the credit. “The all-encompassing changes we have introduced in the last three years, have set the scene for us to deliver on our strategy as a more efficient, effective and competitive organization”, he said. The CEO assumed the position on July 1, 2011, three years and two months ago. “The benefits of the detailed work we have done to reposition, restructure and re-energise the company are already evident in our performance, and in the commitment of our people”.

Sasol recorded an operating profit, after remeasurement items, of $3.88 billion for the year, up 7%, excluding our share of profits of equity accounted joint ventures and associates of $380 Million, which includes the company’s ORYX GTL plant. “This achievement was on the back of an overall improved operational performance”, Constable said. “Operating profit was boosted by a 17% weaker average rand/US dollar exchange rate (R10,39/US$ at 30 June 2014 compared with R8,85/US$ at 30 June 2013), and a progressive improvement in chemical prices, while the average Brent crude oil price (average dated Brent was US$109,40/barrel at 30 June 2014 compared with US$108,66/barrel at 30 June 2013) remained flat”. The report said the company’s share price increased by 47% over the financial year closing at $68.82.

Constable talked up more of his tenure at the helm. “Over the last three years, the compounded annual growth rate of headline earnings per share increased by 21%, and dividends by 18%. This outstanding performance sets the platform for what is the beginning of a new era for the group. In this new era, our focus will be on becoming a leading monetiser of natural resources, and a trusted partner to countries seeking to add value to their hydrocarbon reserves.”

Sinopec Pays $3.1 Billion For A Chunk Of Egypt

Section: In the news · August 30, 2013 · No comments |

Pompey's Pillar in Alexandria..Photo by Toyin Akinosho

Chinese behemoth Sinopec is paying $3.1 billion for 33 percent of Apache Corp’s hydrocarbon assets in Egypt. The two companies say that this is the first step of a global strategic partnership to pursue joint upstream oil and gas projects. Apache will receive the money in cash, subject to customary closing adjustments, in exchange for Sinopec gaining a 33 percent minority participation in Apache’s Egypt oil and gas business. Apache will continue to operate its Egypt upstream oil and gas business.

The Egypt partnership is subject to customary governmental approvals and is expected to close during the fourth quarter, with an effective date of January 1, 2013.

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MODEC Wins FPSO contracts for TEN Project in Ghana’s Deepwater

Section: In the news · August 5, 2013 · 1 comment |

Japanese contractor MODEC has won the contracts for the supply, charter and lease, operations and maintenance of a Floating Production, Storage and Offloading (“FPSO”) vessel for the Tweneboa, Enyenra, and Ntomme (“TEN”) fields in the Deepwater Tano contract area in water depth averaging 1,500m.
The contracts were awarded to TEN Ghana MV25 B.V., a subsidiary of MODEC, by Tullow Ghana Limited, a wholly owned subsidiary of Tullow Oil plc, Modec said in a statement. Deepwater Tano contract area is held by Tullow (47.175%) as Operator, Kosmos Energy (17%), Anadarko Petroleum (17%), Sabre Oil & Gas Holdings Ltd, a wholly owned subsidiary of Petro SA (3.825%), and the Ghana National Petroleum Corporation (15%).
“MODEC is responsible for the engineering, procurement, construction, mobilization and operation of the FPSO, including topsides processing equipment as well as hull and marine systems. SOFEC will design and provide the mooring system”, the statement said. “MODEC will convert the VLCC Centennial J into an FPSO. The FPSO will be capable of handling expected plateau production of 80,000 barrels of oil per day, 170 MM standard cubic feet of gas per day and has storage of 1,700,000 barrels of total fluids”.
Scheduled for delivery during 2016, the FPSO will be installed in the TEN field and is designed to remain operational in the field for up to 20 years. This is the second vessel MODEC will provide and operate in Ghana following the FPSO Kwame Nkrumah MV21 for the Jubilee Field development, which was awarded in 2008. MODEC is currently operating the FPSO Kwame Nkrumah MV21 for Tullow as Operator of the Jubilee Field.
Toshiro Miyazaki, President and CEO of MODEC said, “MODEC is very proud to have been selected by the TEN field partners and GNPC to provide and operate the FPSO for TEN, a world class facility in a world class field. We are equally pleased to be a part of the team that will provide a needed energy resource for the benefit of the people of the Republic of Ghana.”
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Stuart Connal Makes It To The Board Of Seplat

Section: Petroleum People · July 10, 2013 · No comments |

Stuart Connal, the former Centrica Boss who joined SEPLAT as Chief Operating Officer in November 2010, has been appointed to the board of directors of the company. Connal joined the board at the last Board meeting in Paris in June 2013.

A Chartered engineer with over 30 years in the oil and gas industry, Connal was Managing Director and Country Manager of Centrica Energy in Nigria for four years, establishing Centrica’s first ever international office.
He was appointed, along with Edward Skene by Maurel et Prom(M&P) as consultant to the management of SEPLAT, a Nigerian company in which the French owned M&P owns 45% interest. Skene was appointed as Chief Finance Officer.

Both men, reporting to Austin Avuru, CEO of SEPLAT, were later made full time staff of the company. But only Connal has now made it to the board. Prior to joining Centrica, Connal had held a number of senior positions including Engineering and Construction Manager for the Deutag Group in Norway, working on New Field Developments for Norsk Hydro, Statoil and Esso Norge. Prior to this, he worked with Shell on the implementation of the Long Term Field Development Strategy for the Brent field. His early engineering experience was gained working with some of the major engineering companies including Aker Kvaerner, Amec Process and Energy, Brown and Root and Mc Dermot.

LPG Production to Commence in Mozambique in 2024

Section: Gas Monetization · September 26, 2023 · No comments |

Sasol says it will start the first, in-country production of Liquefied Petroleum Gas (cooking gas) in Mozambique by March 2024.

The product is part of the deliverables of the field development plan for the Production Sharing Agreement (PSA) in the northern region of Mozambique’s province of Inhambane.

That FDP aims to optimally develop the light oil and gas resources contained in the Inhassoro, Temane and Pande fields.

The LPG processing facility has capacity for 30,000 tons of LPG per annum. “The equipment is being installed in the factory under construction for the production of the field”, according to Radio Mozambique. Mateus Mosse, director of Cooperative Relations at Sasol. says that the pace of the work is satisfactory and believes that the deadlines established for the completion of the works will be met.

“What Sasol will produce in terms of cooking gas corresponds to around 60 to 70% of the country’s demand. It is true that the economy is growing, this could perhaps reduce demand to 50%, but it is already significant in terms of contribution to the country”, Mosse told the country’s government owned radio “Let’s stop importing 50% of the cooking gas that the country needs, as there is a lot to gain. First, we will stop importing a significant amount of cooking gas; second, we will have a Mozambican company buying gas from Sasol and reselling it; we will have other distribution companies and cooking gas resellers purchasing in the country”, he said.

In 10 Months of Barging Crude, Newcross Distances itself from the ‘Jinx’ in Eastern Nigerian Onshore’s NCTL Pipeline

Section: In the news · September 26, 2023 · No comments |

Of the four Nigerian owned, acreage holding producers who inject their crudes into the Nembe Creek Trunk Line (NCTL), Newcross E&P Ltd has emerged the one with the truest grit.

In August 2022, it exited the line, which has lain prostrate since 2021 and contracted a shuttle tanker MV Bryanston, to ferry its barged crude to the Bonny Terminal.

Since its December 2022 gross output of 5,074BOPD (Net-2,283BOPD) from the Oil Mining Lease (OML) 24, Newcross has maintained gross production higher than 10,000BOPD for the entire…

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NCDMB, NNPC, Oil Majors, in League to Streamline Contracting Process

Section: In the news · September 26, 2023 · No comments |

By Abdulwaheed Sofiullahi, Reporter, SOEs

The Nigerian Content Development & Monitoring Board (NCDMB) has formalized a Memorandum of Understanding (MoU) with some of the country’s hydrocarbon producers, including state owned NNPC Ltd as well as five International Oil Companies (IOCs).

The MoU is aimed at reducing the contracting cycle to a maximum of 180 working days.

The agreement, released on September 26, 2023 at the NNPC Towers in Abuja, focuses on the efficiency goals outlined in the Petroleum Industry Act (PIA), to establish an industry framework for optimizing the contracting cycle.

Key highlights of the framework in the MoU include reductions in the contracting cycle for open competitive tenders, selective tenders, and single sourcing tenders to 180, 178, and 128 working days, respectively, compared to the existing best effort performance of 327, 333, and 185 working days, respectively.

“An optimized contracting cycle is poised to enhance the ease of conducting business, lower costs, and drive efficiency, ultimately leading to increased production, higher revenues, and improved profitability”, according to a statement issued after the signing.

Signing on behalf of NCDMB was the agency’s Executive Secretary, Simbi Kesiye Wabote. The NNPC Ltd was represented by its Executive Vice President, Upstream, Oritsemeyiwa Eyesan. The participants described the MoU as a forward-looking step that will significantly enhance the nation’s crude oil production.

Representatives of IOCs, including the Managing Directors and Country Chairs of Shell, ExxonMobil, Chevron, TOTALEnergies, and ENI, pledged their commitment and support for the MoU’s implementation for the mutual benefit of all parties.

“This framework aligns with the Nigerian Upstream Cost Optimization Program (NUCOP) and is in accordance with the directive from the President for NNPC Ltd. and NCDMB to collaborate with the industry to improve the petroleum sector’s performance”, the statement added.

Sasol: Pilot Successful, Green Hydrogen Production Starts Early 2024

Section: ENERGY TRANSITION · September 26, 2023 · No comments |

Sasol, the South African synfuels giant, expects to commence consistent production of green hydrogen in early 2024, once the 69 Megawatt Msenge Emoyeni Wind Farm, in the Eastern Cape, begins supply of renewable energy to Sasol’s Sasolburg site via a wheeling arrangement.

The company says it has proven the concept, when it produced its first green hydrogen, under a pilot phase, using a 3MW solar photovoltaic facility in its factory in Sasolburg, in the country’s Free State province, in June 2023.

It had used the pilot project to repurpose an operational electrolyser to use renewable electricity to split water into hydrogen and oxygen. The green hydrogen produced in Sasolburg will be used in mobility applications.

“There is a demand for green hydrogen to decarbonise the mining industry, and in other mobility applications,” declares Sasol CEO Fleetwood Grobler.

“Once operational, the (69MW) Msenge wind farm together with the Sasolburg solar farm will provide sufficient renewable power to commercialise green hydrogen in South Africa”, Grobler assures.

“This is a huge step forward in the energy transition, not just for Sasol but also for South Africa,” Grobler explains.

Fuel for Thought: Liquefied Petroleum Gas

Section: Power Deficit · September 23, 2023 · No comments |

PARTNER CONTENT

By: Gorgui Ndoye

The past several years have shown that a range of fuel options for power generation is an important hedge against instability. Fuel flexibility is a hallmark of Capstone microturbines, which can run off a variety of sources, from natural gas and propane to methane, hydrogen, and more.

Today we’re spotlighting liquefied petroleum gas (LPG), a widely available fuel that is an excellent alternative to diesel and other expensive, “dirty” fuels. This primer explains the types of commercially available LPG and how they can integrate into Capstone microturbine systems.

What is LPG?

Using LPG in Microturbines

LPG is a mixture of propane (C3), butane (C4), and small quantities of various other hydrocarbons, such as propylene and butylene.

LPG is transferred and stored as a pressurized liquid; however, its boiling point is such that it evaporates easily under ambient temperature and pressure. The molecular composition of LPG determines the dew point, heating value, density, and many other properties, as well as the percentage of contaminants. These values determine whether a fuel can be used in an engine or turbine. For this reason, it is important to know the composition of the LPG before designing the fuel delivery system. Because the LPG composition can vary significantly between fuel types, Capstone enhanced the fuel capabilities of the C200 and C1000 series microturbines to use a variety of LPG.

The four most common commercially available types of LPG are Special Duty Propane (HD-5), Commercial Propane (HD-10), Propane-Butane Mixtures (PB Mix), and Commercial Butane. LPG can also be mixed with conditioned air to make an LPG/Air Mixture. The addition of air may alter the overall fuel properties to a more desirable level for operation. Capstone’s microturbines can run using HD-5, PB Mix, or LPG/Air Mixtures.

When comparing LPG to Natural Gas (NG), it’s important to note the heating value difference. NG has an average heating value of 1,000 Btu/scf. SD-5 is roughly 2,500 Btu/scf, and Commercial Butane is over 3,000 Btu/scf. Therefore, the heating value of LPG is 2.5 to 3 times greater than NG. So, LPG requires much lower volumetric flow rate to achieve the same engine output. LPG is also stored as a liquid, which compresses the fuel volume 250:1—without costly cryogenics required by LNG. These factors offer a small footprint for LPG compared to NG’s need for pipelines and large infrastructure, and LPG can be transported easily and stored in tanks, making it a good diesel replacement.

Using LPG in Microturbines

Special Duty Propane

Special Duty, or HD-5, Propane is defined as greater than 90% propane and less than 5% propylene. This grade is ideal for all types of engines and turbines due to the burn’s cleanliness and the low level of contaminants relative to diesel.

All Capstone microturbines have a version that can operate using HD-5 Propane.

Propane-Butane Mixtures.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

Propane-Butane Mixtures, or PB Mix, have no standard specification for their compositions and can be a problem for gaseous fuel operation due to the low dew point of butane. The higher the concentration of butane, the lower the dew point falls, and the more heat tracing and insulation needed with the fuel delivery system. This causes a higher risk of fuel condensation, which may lead to engine problems. The LPG-capable C200 and C1000 series microturbines were designed with a versatile fuel system. This includes internal heat tracing and fuel line insulation, which reduce the risk of condensing vapor from heavier fuels. The goal of the heat tracing and insulation is to maintain the supplied inlet fuel temperature without needing to increase the fuel temperature or vaporize condensed liquids.

The LPG-capable C200 and C1000 microturbines are approved to operate using a Propane-Butane Mixture of up to 40% butane. This does not mean that PB Mixtures containing greater than 40% butane are disqualified. Capstone applies the same limitations towards propylene, limited to less than 5%, as well as all other contaminants listed in the Special Duty Propane specification.

LPG/Air Mixtures

Certain LPG types that are not suitable for microturbines may be approved when mixed with air. Alternatively, the mixture may attempt to match the properties of a more standard fuel, such as NG. LPG/Air mixtures are not standard and may require complex fuel delivery systems. The approval of these fuel types depends on review of the fuel properties and composition. Detailed analysis would be needed to determine feasibility for use in microturbines.

Real-World Application

In March 2023, a 600 kW, C600S, LPG-fueled system was commissioned at a remote food processing facility in Bamako, Mali. Like many land-locked countries, Mali relies on expensive, “dirty” fuels like diesel and heavy fuel oil, so this project was important in demonstrating the benefits of a system whose fuel is less expensive and more environmental.

The new system also improves reliability, which addresses issues of load shedding and blackouts the facility had previously experienced. Because the microturbines also require very little maintenance compared to other technologies like diesel generators, power availability and cost savings were also improved.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

“The Mali project is a model for other customers and power companies, showing the benefits of LPG as an alternative fuel,” said Gorgui Ndoye, business development director for Capstone Green Energy. “There is tremendous opportunity to use LPG in many regions around the globe, but it can play an especially important role in Africa as part of the continent’s energy transition.”

Better for Business and the Environment.

It’s difficult to underestimate the positive impact that added reliability and cost savings have on the bottom line. Often, the combination of LPG and microturbines offers significant upside—including cleaner fuel and lower emissions. What’s more, once a customer decides to go with Capstone, we can fast-track and deploy nearly anywhere within three months of order.

The world’s energy landscape won’t become more predictable. Smart power security decisions made today will set businesses up to confidently navigate the future. An LPG-fueled microturbine system could be the answer.

Contact:

rentals@CGRNenergy.com

Renewable Energy Wheeled for the first time through Cape Town’s Grid

Section: Power Deficit · September 23, 2023 · No comments |

The first electrons of renewable energy have officially been wheeled via the City of Cape Town’s energy grid, as part of the city’s plans to end power outages, which plagues South Africa.

Growthpoint Properties (JSE: GRT) became the first party to wheel renewable electricity in the city in collaboration with licenced electricity trader Etana Energy (Pty) Limited (Etana), a joint venture in which the South African owned Neura Group and H1 Holdings hold 49% and 26% respectively and UK based Chariot holds a 25% interest.

Wheeling is a process where electricity is bought and sold between private parties, using the existing grid to transport power from where it is generated to end-users that can be long distances apart.

“It creates greater access to affordable renewable energy and contributes to resolving the country’s energy crisis”, UK based Chariot says in a statement.

“As part of the City’s wheeling pilot project, in which Etana was selected as a participating trader, solar energy generated at Growthpoint’s The Constantia Village shopping centre in Constantia is being exported into Cape Town’s electricity grid for use at Growthpoint’s 36 Hans Strijdom office building in the Foreshore”.

Solar power from The Constantia Village was successfully injected into the City’s energy grid for the first time in September 2023.

Etana Energy says it is pleased that the city selected it as a trading partner, and we look forward to providing further energy support to the region for the foreseeable future.

“This electricity licence not only enables us to instigate this trading, but it also has the potential to help to unlock the development of further large renewable projects in South Africa. We are looking to supply greener power across the national grid for commercial and industrial requirements so this early-stage trading is a key step within our longer term plans for this business.”

STAC Marine Wraps Up Purchase of Abo FPSO for $20Million

Section: In the news · September 21, 2023 · No comments |

The Nigerian marine operator STAC Marine Offshore Limited, has finalised the purchase of the Abo Floating Production Storage Offloading (FPSO) vessel from BW Offshore, the Norwegian provider of floating productions solutions.

As part of the transaction, BW Offshore has entered into a bareboat charter with STAC to allow for uninterrupted operations for the client during a transition period of maximum two months. Upon expiry of the bareboat charter, STAC will assume responsibility for operations of the unit.

STAC is a member of the Nigerian Transport Group (STAC).

BW Offshore has managed the Abo FPSO since the Abo deepwater field came on stream in 2003.

In the last five months, it had been seeking to end the contract with ENI, the Italian operator of the field. It has had three short contract extensions between June and September 2023.

This sale of the vessel to a Nigerian firm, effectively removes the responsibility of running the FPSO, from BW Offshore’s shoulders.

Originally recognised as the “Gray Warrior“, a Suezmax tanker constructed in 1976, the vessel underwent conversion at Keppel Shipyard before beginning its operations in April 2003. “Abo FPSO has now reached a commendable milestone, having completed two decades of service on the Abo field. This achievement underscores its enduring contribution to the oil and gas industry in Nigeria”, BW Offshore says in a statement.

Why Less Looks Like More: A Performance Review of Nigeria’s Power Generation Capacity

Section: Power Deficit · September 21, 2023 · No comments |

By Adeniyi Adeoloye

The Nigeria power sector is encumbered right through the entire value chain.

The figures for installed generation capacity, the grid transmission, and what the distribution companies can deliver to the end users, are common knowledge. But there’s a vast gulf between the capacity and the delivery and the specific details of this gap is absent from the conversation.

Many have dismissed the transmission segment as the weak link in the power industry value chain. The call has led to pleas for government to let go of operating it in order to drive efficiency and deliver optimum value. There has been a scathing searchlight on the distribution and transmission links of the sector. But then, the generation segment is as broken.

Nigeria, like many countries, organises its energy mix around energy sources that are abundant within its borders. Hydro power and gas fired plants dominate the energy mix in Africa’s most populous country. Save for the emissions during their construction and location outside demand centres, hydro is largely seen as a clean means of power generation. On the other hand, gas has been given green credentials by the European Union due to its less polluting nature than coal and since labelled a transition fuel. So by and large, the grid emission factor of the power generation systems in Nigeria based on energy source are in relatively good stead.

What are the numbers like? By the tally, there are 23 power generating plants connected to the grid in Nigeria with installed capacity of 10,396 MW and available capacity of 6,056 MW. Of this, gas fired plants account for 8,457.6 MW with available capacity of 4,966 MW while the remainder is hydropower with installed capacity of 1,938.4 MW and available capacity of 1,060 MW. The large chunk of the country’s generation is gas fired. The ownership of these plants cuts across government and the private sector. Nigerian Bulk Electricity Plc (NBET) undertakes Power Purchasing Agreement (PPA), with the generating companies and sells the energy purchased to the distribution companies via Vesting Contracts. A total of 16 generation companies have PPA with NBET.

Performance of Government Run Power Plants

Government hatched the National Integrated Power Project (NIPP) in 2004 in a bid to stabilize electricity supply in anticipation of the takeoff of the private sector led structure of the Electric Power Sector Reform Act (EPSRA) of 2005. The primary idea of NIPP was to build 7 medium sized gas fired power plants in gas producing states alongside crucial transmission infrastructure required to move the added power to the national grid. The Niger Delta Power Holding Company Limited (NDPHC) was set up to house and manage the NIPP assets with market oriented practice. Available information by NDPHC indicates it owns 10 thermal plants – Calabar (563 MW), Omotosho (500 MW), Sapele (450 MW), Egbema (338 MW), Omoku (225 MW), Alaoji (960 MW), Ihovbor (450 MW), Gbarain (225 MW), Gerugu (434 MW) and Olorunsogo (675 MW). Of this ten, eight of them except Egbema and Omoku have “interim agreement” with government owned Nigerian Bulk Electricity Trading Plc (NBET) that buys power from Independent Power Producers (IPP) and successor generation companies from the unbundling of Power Holding Company of Nigeria (PHCN) and resale to Distribution Companies who deliver to end users and other large consumers who take electricity directly from the grid.

The eight plants having interim agreements with NBET have total contract capacity of 4,257 MW and tested capacity of 1762 MW with average generation capacity of 488.15 MW as at year 2021 according to data by NBET. The data further shows average generation of these plants is a paltry 11% of net contract capacity, and about 27% of tested capacity. Plants with installed contract capacity of 500 and above didn’t perform any better. Alaoji with net contract capacity of 960 MW and tested capacity of 212.33 MW averaged an output of 58. 19 MW. Olorunsogo (675 MW, 212.67 MW and 23.07 MW), Calabar (563 MW, 339.55, 236.02) and Omotoso (500 MW, 219.61 MW and 43.24 MW) for net contract capacity, tested capacity and average generation capacity respectively. The Ihovbor Plant with contract capacity of 450 MW and tested capacity of 202.34 MW last done in 2021 had average generation capacity of 16.87 MW in year 2021. This is an abysmal low of capacity utilisation. Across board, NDPHC managed plants are poorly performing.

And talking about testing, the data also established year 2015 as the last test date for all NDPHC plants with the exception of Alaoji plant whose capacity test was carried out in June 2021. The lag in test capacity is against what is stated in a March 2022 draft power purchase agreement for brownfield power plants by NBET which states “the Tested Capacity of the Plant shall be verified at least annually by further Capacity Tests that will establish the revised Tested Capacity”. Usually there are diverse reasons to appraise the performance of a plant other than meeting contract guarantees. Performance tests for a brownfield power plant can be done to verify its capacity and heat rate before an acquisition in order to determine its asset worth. Testing is also useful for the goal of maintaining a Power Purchase Agreement, tariff up-gradation as well as to ascertain the performance differences brought by major repairs or component upgrades.

Review of Successor Gencos

Successor Gencos are power generation companies created in the aftermath of the unbundling of PHCN. There are eight of these plants around the country namely: Kainji (760 MW), Jebba (576 MW), Shiroro (600 MW), Egbin (1100 MW), Sapele (1020 MW), Delta (900 MW), Afam IV-V (776 MW) and Gerugu (414MW). Tese are nameplate capacities. With the exception of Kainji, Jebba and Shiroro that are hydro power, the rest are gas fired. Many of the plants have been fully or partially sold, and others under long term concession. All of the plants have Power Purchase Agreement with NBET with total contract capacity of 6,146 MW, last tested capacity of 2,853.72 MW and average generation capacity of 2,010.4 MW in year 2021. The average generation capacity of these plants is 32% of contract capacity and 70% of tested capacity. On a plant by plant basis, the Sapele plant is an overwhelming underperformer given its contract capacity of 1020 MW and test and 2021 average generation capacity of 52.29 MW and 46.39 MW, being last tested in June 2021. This translates to a miserly 4.5% average generation capacity to contract capacity. Afam IV-V didn’t fare any better with contract capacity of 776 MW and test and average generation capacity of 121.9 MW and 66.75 MW respectively and last tested in July of 2021. For context, the output from Afam IV-V is a beggarly 8.6% of its contract capacity.

Test dates for the plants was between June and August 2021. Over two years ago. Still far behind the annual recommendation of NBET. The performance of plants in this category outmatch those of the NIPP plants managed by NDPHC despite the sub par productivity of Sapele, Kainji, and Afam IV-V respectively.

A look at Plants in other Categories

There are five plants that are classified by NBET as having active PPA namely: Okpai operated by Agip, Afam VI run by Shell, Omotosho Electric, Olorunsogo and Azura Edo IPP. All of these plants are gas fired with total contract capacity of 2,188 MW, tested capacity of 1,815.61 MW and average 2021 generation capacity of 1,338.68 MW. The average generation capacity of these plants with respect to tested capacity is 71% and 61% with respect to contract capacity – an indication of better performance. Of plants in this category, Azura Edo IPP with contract capacity of 450 MW and test capacity of 452.6 MW and average generation capacity in 2021 at 420.84 outperforms it peers. In context, average generation capacity with respect to test capacity and contract capacity stands at 92% respectively with last capacity test carried out in June 2022. Shell run Afam VI has contract capacity of 650 MW, tested capacity of 464.96 and average generation capacity of 261.04 MW in 2021 with last test date of July 2021. In performance terms, the average generation capacity with respect to contract capacity and tested capacity stands at 40% and 71% respectively. For Agip run Okpai with contract capacity of 480 MW, it tested capacity is 464.96 MW with average generation at 261.04 MW. Last tested in July 2021. This translate to 56% and 54% of average generation capacity with respect to tested capacity and contract capacity respectively. Without doubt, Azura leads the pack in terms of production efficiency.

State Government owned plants Ibom Power, Mabon, Omoku FIPL, Trans Amadi FIPL, AFAM (Rivers IPP) FIPL, and Eleme have combined contract capacity of 870 MW, with tested capacity of 451.88 and average generation of 185.09. The average generation capacity of Ibom power of 12.53 MW compared to test and contract capacity of 112.83 MW and 190 MW respectively, translating to 11% of average generation to test capacity is an indication of operation plunging into an abysmal depth. The Mabon and Eleme are new plants in the inventory of NBET with their capacity test yet to be carried out.

The foregoing is the state of things with the plants based on data from NBET. Cash liquidity constraint is a major issue given collection inefficiency by distribution companies. This has a ripple effect on the sector, leading to inability of operators to pay gas producers. Additionally, the insufficiency of the transmission company to transmit contracted or test generation capacity due to infrastructural gap and vandalism has left the country with more than 20 plants with test capacity of 6,884.76 MW out of contract capacity of 13,461 MW and an average generation of 4,022 MW in 2021 to back up power from the grid with gasoline or diesel generators. The factors causing this inefficient operations has to be reigned in rather than pushing the much needed reform to turn things around into the long grass as done by successive governments. Economic growth, its attendant job creation and prosperity will continue to be an illusion with this sort of underwhelming productivity of the power generating plants.

“Key Parts of a Power Purchase Agreement” According to NBET

Tariff Structure – Provides the details of how NBET will pay for the duration the PPA is calculated.

Risk Allocation – Identifies all project related risks and allocates these risks to parties best able to bear them.

Conditions Precedent – Provides all the conditions precedents (CPs) which either the Buyer (NBET) or Seller (Owner of plant) must satisfy before the PPA can become effective.

Tenor of PPA – A standard NBET PPA has a 20 year tenor. There are clauses within the PPA to handle early termination due to either a Buyer’s or Seller’s default.

Project Documents – All documents that are connected to the PPA such as Engineering, Procurement and Construction, Gas Supply Agreement (GSA), Gas Transport Agreement (GTA), Operations and Maintenance, Long Term Service Agreement, Financing documents e.t.c.

Commissioning & Testing Procedure – Contains a set of guidelines for plant testing and commissioning.

Operation & Maintenance – Contains details of the maintenance and operational obligations of the Seller throughout the tenor of the PPA.

Conflict Resolution – Indicates clear procedures for conflict resolution in case of disputes and/or conflicts on invoices.

Metering – Sets out the rules about metering. However, in case of conflicts between PPA provisions and the metering code, the metering code supersedes.

Liability & Indemnification – Enumerates the parties responsible for certain failures and provides indemnification to both parties.

Insurance – States the required insurance coverage to be put in place by the Seller and how the proceeds will be administered.

Scheduling Notices – Provides a methodology by which the Buyer nominates for the dispatch of Net Electrical Output to be made available at the delivery point by the seller.

Force Majeure – Provides details of events to be considered as force majeure and possible payments during the occurrence of such events.

Adeniyi Adeoloye is a consulting Editorial associate at the Africa Oil+Gas Report.