All articles in the In the news Section:


Siemens’ Spin-Off of Energy Unit Gets Unanimous Approval

By Mackson Orija

A large majority of Siemens shareholders voted Friday July 10, 2020, to approve the spin-off of the company’s energy business to Siemens Energy AG.

“This step paves the way for the establishment of an independent company rigorously focused on the energy sector”, the German conglomerate said in a release.

“In the future, Siemens AG will concentrate on Digital Industries, Smart Infrastructure and Siemens Mobility”, the company explained.

In total, 61.94 % of the capital stock of Siemens AG entitled to vote was represented at the shareholders’ meeting, which was held as a virtual event due to the coronavirus crisis.

Approval of the Spin-off and Transfer Agreement between Siemens AG and Siemens Energy AG was the only item on the meeting agenda.

The agreement was approved by a majority of 99.36 percent of the capital stock represented. The highest number of participants following the Extraordinary Shareholders’ Meeting online was 3,870 at the July 10, 2020 Extraordinary Shareholders’ Meeting.


400Million Barrels of Oil Extracted from Ghana Since 2010

By Toyin Akinosho

Ghana has produced ~392Million Barrels of Oil since extensive commercial production started in November 2010.

The flagship asset, Jubilee field, delivered 284,016, 968Barrels, from November 28 2010 to January 31, 2020.

The TEN cluster of fields, which is operated by Tullow Oil, the same company that operates Jubilee, has produced 73,266, 506 Barrels between August 18, 2016 and January 31, 2020.

The ENI operated Sankofa Gye Nyamme (SGN) twin fields delivered 34, 790, 660Barrels between May 1, 2017 and January 31 2020.

Average production for each of the three fields in January 2020 were: 63,839Barrels of Oil Per Day (BOPD) for Jubilee; 52,300BOPD for TEN and 55,279BOPD for Sankofa.

SGN is the country’s top gas producer, delivering in excess of 60Million standard cubic feet per day.

 


Assala Has Vivid Plans Post COVID-19

Assala Energy increased production of the Shell assets it bought in Gabon from 40,000BOPD to 55,000BOPD in the space of two years.

The London headquartered company claims it installed new equipment and brought down the cost per barrel to $12.

It is hoping to ride the storm of steep drop in prices, exacerbated by COVID-19, even with all the volatility.

Assala pumped $60Million into the five acreages in 2018 and spent $240Million more in 2019, in the process, drilling 20 new wells and optimizing 60 existing wells.

It had a war chest of $300Million for 2020, of which it had spent $70Milion in the first quarter alone.

So what will happen now?

If it survives the next 12 months, its plan is to continue from where it stopped.

The company was raring to go before COVID-19 happened. In late 2019 it acquired three onshore exploration licences from the Gabonese authorities: Mutamba-Iroru II, Nziembou II and Ozigo II, in addition to the five licences it purchased from Shell: Rabi Kounga II Toucan II Bende M’Bassou Totou II, Koula/Damier and Gamba/Iyinga. It also holds interests in four non-operated licences (Atora, Avocette, Coucal and Tsengui.

This story was originally published, for the competitive benefit of paying subscribers, in the May 2020 issue of the monthly  Africa Oi+Gas Report.

 


Technip Gets the $2.5Billion Contract for Egypt’s Assiut Refinery

TechnipFMC has now signed the much-anticipated major Engineering, Procurement, and Construction (EPC) contract with Egypt’s state owned Assiut National Oil Processing Company (ANOPC) for the construction of a new Hydrocracking Complex for the Assiut refinery.

The $2.5Billion hydrocracker will upgrade residual oil from the 90,000BOPD Assiut refinery, in the town of Assuit, in Upper (southern) Egypt.

The work also involves Egyptian state-owned contractor ENPPI.

“This EPC contract covers new process units such as a Vacuum Distillation Unit, a Diesel Hydrocracking Unit, a Delayed Coker Unit, a Distillate Hydrotreating Unit as well as a Hydrogen Production Facility Unit using TechnipFMC’s steam reforming proprietary technology. The project also includes other process units, interconnecting, offsites and utilities.

The complex will transform lower-value petroleum products from Assiut Oil Refining Company’s (ASORC) nearby refinery into approximately 2.8Million tons per year of cleaner products, such as Euro 5 diesel.

 


Ben van Beurden: His Final Hurrah?

By Gerard Kreeft

 

 

 

 

 

 

Departures in troubling times can be sudden and abrupt. Therefore no one should be shocked nor surprised about the possible resignation or sacking of Ben van Beurden, Shell’s Chief Executive Officer. 

In a lengthy interview in the prestigous Dutch financial publication Het Financieele Dagblad of 4 July 2020,  van Beurden goes to great length to explain the dilemma Shell is facing:

  • The need to re-organize itself so that it can become a greener company;
  • Whether Shell’s headquarters ( now in the Netherlands) should be moved to the UK;
  • The struggle of deciding to reduce its golden dividend (the first time since WW II);
  • Writing down of some $20 billion in assets;
  • How to face the Energy Transition.

Het Financieele Dagblad also reveals that total investments, between 2016 and 2019, were $89Billion, of which

Ben van Beurden,Shell CEO

only $2.3Billion was directed to new energy. In March 2020, Shell’s  share price on the New York Stock Exchange was $25/ share compared to a high of $70/share in May 2018.

Shell is not alone in the dilemma it faces. The other majors, including BP, Chevron, ENI, ExxonMobil, Equinor and TOTAL, face similar hurdles. Instead of (again) having a discussion on how to green Shell and the rest of the sector, it is more relevant to accept the basic premise, long discussed in Africa Oil + Gas Report, that an oil company, by its very nature, cannot be green. 

Oil companies are by their very definition focused on a fossil fuel. Their reserve count (Reserve Replacement Ratio) is purely based on a fossil fuel. Clean energy—wind,sun or hydropower—cannot be part of the mix. The US SEC stock market regulator leaves no doubt about that!  At present the RRR rate for the industry is 7%, a historic 20 year low. The norm is 100%, meaning that oil companies previously were able to fully replace all of the oil and gas that they produced annually. There is no evidence that Shell and the rest of  the E+P sector are making any effort to broaden the basic definition of RRR  to include renewables and thereby also  bolstering fossil fuel reserves.

The concept of the ‘Integrated Oil Company’ has become untenable. The extended oil price crisis between Russia and Saudi Arabia, coupled with COVID-19, have had disastrous consequences for the oil majors as well as national oil companies. Exploration budgets have been frozen, people sacked,  dividends to shareholders reduced or postponed, and assets written down. Future signs are not encouraging as evidenced by:

  • Rystad Energy predicting a write off of 14% of the current world’s oil reserves.
  • Goldman Sachs estimates that borrowing costs for fossil-based projects is as high as 20% compared to as low as 3% for clean energy projects.

In a shrinking E+P market, size and valuation still matters. The three pillars of the value chain- Upstream, Midstream and Downstream-provide enough clues about the tensions facing the sector.

Heightened Integration

There is already an informal integration of sorts within the Upstream portion of the value chain. In most offshore jurdisictions, offshore concessions are shared among the majors and state oil companies in order to minimize project risks.

We will probably witness heightened project co-operation among the majors in an attempt to maintain or reduce project costs. At a regional or country level, we should anticipate increased project co-operation. Areas of co-operation could  Include  seismic surveys, project management, rig-sharing and marine operations. Such integration will also require the buy-in of the drilling contractors, service providers and marine contractors.

Specialization

Deepwater exploration  and project management could perhaps be delegated to companies who are best in class.

For example in Sub-Sahara Africa, TOTAL, with its deepwater track record in Angola Block 17, could certainly play a strategic role in determining how future deepwater projects are managed. Its Brulpadda Deepwater Project in South Africa( drilled to a final depth of more than 3,600 meters), bears testimony to the company’s deepwater agility. In Nigeria, expect Shell, with  its dominant offshore assets, including Bonga to possibly seek more co-operation with other majors. Expect BP’s Orca-1 deepwater play in Mauritania to have a stringent project development budget.

Alliances, Mergers and Takeovers 

What will be the tipping point when cost savings and joint-co-operation have run their course? A matter of the last man standing?

Very unlikely.

Instead, anticipate in the coming months, strategic alliances and acquisitions to ensure market size that matters. The oil majors are notorious in ensuring that energy scenarios are developed and implemented. Think of Shell’s takeover of British Gas in 2015. The planning was meticulous and carefully rehearsed.  Major shakeouts on a massive scale can be expected in the coming months.

The Winners and Losers

Imagine this to be a gigantic  game of high stakes poker. Not necessarily that the winner takes all but the prizes are there for the taking. Some observations.

Deepwater Developments

In Sub-Sahara Africa, TOTAL,  with its Angola Block 17 experience could well be nominated to be the company of choice for exploration, given its technical prowess and ability to innovate.

Nonetheless, other majors also have considerable strengths: Shell’s Bonga Project in Nigeria  coupled with its deepwater  experience  in the Gulf of Mexico. ExxonMobil with its Block 15 experience in Angola and offshore Guyana with its 16 oil discoveries.

Finally, anticipate that one or two of the majors will be become dedicated deepwater exploration companies on behalf of the majors; also look to further integration of oil and gas services.

Natural Gas and LNG

Given that natural gas is viewed as the cleanest  hydrocarbon, this portion of the value chain could become even more competitive and crowded:

Shell’s market share of the gas value chain  extends from the Middle East through to Asia Pacific and the company operates 20% of the global LNG fleet ; Chevron with its Australian Gorgon and Wheatstone LNG projects is an important gas player in Asia-Pacific and is also a key shareholder in Angola LNG; ExxonMobil developed Asian markets with its Arun LNG project in Indonesia and in the 1990s involved with RasGas(Qatar). 

Given that natural gas is viewed as a transitional fuel, all of the majors will want to profile their companies as energy friendly. This scramble could become very ugly as they compete with one another.

Petrochemicals

in its 2019-2020 analysis of the Chemical industry, Deloitte encourages companies to extract more growth out of their existing assets and resources. For example, investing in high-performance plastics for new  vehicle models.

Both Shell and ExxonMobil have key global  positions in the chemical sector. In 2002 Chevron and Phillips merged their chemical operations.

It should not be surprising that  mega-mergers occur  to include the chemical businesses of the majors. Perhaps, not surprisingly BP has just announced selling its chemical business to Ineos for $5 billion.

Finally  mega-mergers leading to more specialization offers the oil and gas sector the best chance for maintaining a large market share with economies of scale. Doing-more-with-less could become the new motto of the sector.

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

 

 

 

 

 


North Africa’s PetroStates are The Region’s Economic Laggards

Algeria and Libya, the two net exporters of crude oil in North Africa, will experience the highest contraction of their economies in the region.

Libya, which is mired in civil war on top of the challenges of COVID-19 and fall in demand for crude oil, will contract by 58.7% in 2020, by IMF estimates.

Algeria’s GDP will drop by 5.2%, says the global lender.

While Algeria is not at war, its political system is delegitimised by weekly protests and political tensions, which do not appear likely to go away anytime soon.  Unemployment in the country runs at 11.1% and youth unemployment stands at 26.4% for the under 30s, who make up two-thirds of the country’s population of 41 Million.

Meanwhile, Egypt, a net oil importer with a robust hydrocarbon industry and a diversified economy, will experience a 2% growth rate in 2020. It is the bright star in the region.

Tunisia and Morocco, no petrostates, no oil exporters, will also fall, with the former contracting by 4.3% and the latter dropping by 3.7%.

The IMF also predicts that, at 20% of GDP, Algeria’s budget deficit will be the worst in North Africa. The country, which is Africa’s third highest oil producer, will experience a high current account deficit, at-18.3%, in the year.

This article was first published in the May 2020 edition of the Africa Oil+Gas Report.


Explosion Kills Seven People on NPDC’s Benin River Valve Station (BRVS)

The Nigerian National Petroleum Corporation (NNPC) has reported an explosion incident which occurred on the Gbetiokun field, in Oil Mining Lease (OML) 40, operated by the Nigerian Petroleum Development Company (NPDC), on behalf of the NPDC/Elcrest Joint Venture.

The incident, which occurred on Tuesday July 7, 2020 during the installation of a ladder on a platform (Benin River Valve Station) for access during discharging of Gbetiokun production, unfortunately caused 7 fatalities, a release by Kennie Obateru, NNPC Group General Manager, Group Public Affairs Division, has said.

The release stated that detailed investigation of the cause of the explosion has commenced, while the Department of Petroleum Resources has been duly notified and Form 41 was being prepared for the Industry regulator as required in circumstances of this nature.

The bodies of casualties have been deposited in a morgue in Sapele, while families of the personnel involved are being contacted by their employers: Weld Affairs and Flow Impact, which are consultants to NPDC.

The release stated that all personnel on board the platform had been fully accounted for.

Mele Kyari, NNPC Group Managing Director, in the statement commiserated with the families of the bereaved, praying that God grants them the fortitude to bear the irreparable loss of their loved ones.

 


AFC Takes Djibouti’s First IPP To Bankability

Africa Finance Corporation has worked up a $63Million strategic investment to construct and operate a 60MW wind project in the Ghoubet area, near Lake Assal in Djibouti.

AFC has made this investment as lead developer together with Great Horn Investment Holdings (GHIH) and inviting further investment from Climate Fund Managers (CFM), and FMO, the Dutch entrepreneurial development bank.

AFC has led the development of the project since 2017, developing it from concept to bankability, securing a 25-year take or pay power purchase agreement with Électicité de Djibouti as the off-taker, an implementation agreement and with the Government of Djibouti backed by a Government Guarantee. The Project also has MIGA guarantee cover. The wind project is expected to begin commercial operations in 2021.

AFC says it adopted, along with its partners, an all sponsor equity financing for this transaction, which enabled the start of construction within two years, a significant reduction from the typical 3-5 years development cycle. As part of this investment, Oliver Andrews, Chief Investment Officer, as well as Amadou Wadda Head of Project Development at AFC, have joined as nominee non-executive directors to the Board of the project and the holding company, Red Sea Power SAS, and Djibouti Wind LP.

Currently Djibouti’s power sector faces significant challenges, with less than 100 MW reliably available for the population. Its electricity demand is also expected to considerably increase due to various large-scale infrastructure projects including ports, free-trade zones and railways that the Government of Djibouti has undertaken.

 


Nigeria Plans Hike in Local Content Fees in New Legislation

A doubling of the tariff paid by oil and gas operators into the National Content Fund is one of the key highlights of the ongoing revision of the 10-year-old Nigerian Oil and Gas Industry Content Development (NOGCD) Act in the country’ bicameral legislature.

The document, which has reached its second reading in the Senate, the upper house, proposes an increase, from one percent to two percent, “of every contract awarded to any operator, contractor, subcontractor, alliance partner or any other entity involved in any project, operation, activity or transaction in the upstream sector and designated midstream and downstream projects operation, activity or transaction in the Nigerian oil and gas industry shall be deducted at source and paid into the Nigerian Content Development Fund, established for purposes of funding the implementation of Nigerian content development in the Nigerian oil and gas industry”.  This is the amendment of Section 105 of the original act, which was enacted in 2010.

The new law also seeks to specify what percentage of a company’s gross earnings it must allocate for research and development and goes ahead to mandate companies to fund the country’s research needs. The amendment of  Section 38 says that: ”All operators shall set aside, annually and for the purpose of carrying out research and development activities in Nigeria, minimum 0.5% of the gross revenue received by the operator; The funds set aside under subsection(1) shall be applied as follows (a) fifty percent shall be allocated to Research and Development programmes in Nigeria; (b) Fifty percent shall be applied to research and development activities within the facilities of the operator established in Nigeria.”

The extant law also pays heed to Research and Development R&D, but neither decrees how it is funded, nor determines how much of a company’s earnings must be set aside for funding.

It simply states, in the same section: “The operator shall submit to the Board and update, every six

months, the operator’s Research and Development Plan (R and D Plan). (2) The Rand D Plan shall-

(a) outline a revolving three to five-year plan for oil and gas related research and development initiatives to be undertaken in Nigeria, together with a breakdown of the expected expenditures that will be made in

implementing the R and D Plan; and (b) provide for public calls for proposals for research and development

initiatives associated with the operator’s activities”.

The introduction of administrative sanction in Section 68 is another amendment that sticks out. In this proposal, the influence of the National Content Development Monitoring Board (NCDMB) has been expanded to include prosecutorial powers.

It says:  “A person who submits a plan, returns, report or other document and knowingly makes a false statement, commits an offence and shall be liable to administrative sanction which may include a fine of not more than five percent of the project sum, cancellation of the project or any other sanction as may be prescribed by the Board.  A person who submits a plan, returns, report or other documents and knowingly makes a false statement, and fails to provide satisfactory reason for the violation shall be liable to administrative sanctions including cancellation of project, withdrawal of certificates or any other sanction as may be prescribed by the Board.”

The story was earlier published in the June 2020 edition of the Africa Oil+Gas Report

 


COVID Will Not Stop First Oil From Senegal in 2023

Australian explorer Woodside Petroleum insists that COVID-19 would not stop it from reaching first oil from the Sangomar Field Development Phase 1 by 2023

The first oilfield development in Senegal “remains on track for 2023, in line with previous guidance”, Woodside declares.

“Woodside and its joint venture partners took an unconditional final investment decision for the Sangomar Field Development Phase 1 and commenced execution phase activities in January 2020”, the company explains.

“Since then, Woodside has taken early action to proactively manage the emerging impacts of COVID-19 on the supply chain and project schedule. We are working with project contractors, the Government of the Republic of Senegal and our joint venture partners to optimise near-term spend whilst protecting the overall value of the investment and deliver first oil in 2023”.

© 2020 Festac News Press Ltd..