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.
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.
Africa Finance Corporation has signed a Joint Development Agreement with Brahms Oil Refineries Limited to act as co-developer on the development and subsequent financing of a petroleum storage and associated refinery project in Kamsar, Guinea-Conakry.
This will include a 76Million litre crude oil storage terminal; 114.2Million litre storage terminal for refined products; ancillary support transportation infrastructure, and 12,000 barrels oil per day modular refining facility.
Through this joint development, AFC will invest in the project development workstreams that should ensure the Project reaches financial close in 2020.
Brahms Oil Refineries is a part of Brahms Group, a Switzerland based diversified company with a strong industrial & international finance network and an excellent knowledge of Sub-Saharan Africa.Once operational, the Project will have a refinery capacity that is the equivalent of one-third of the country’s demand for refined products, thereby reducing its reliance on imported refined products, improving the country’s balance of payments, and reducing foreign currency demand. It will also allow for direct & indirect job creation and enhance the development and productivity of other sectors, especially mining, which today accounts for 15.3% of the country’s GDP but could contribute even more if the country had the necessary infrastructure to maximise and locally beneficiate its natural resources. The Project is strategically located in Kamsar, which is one of the larger mining regions in the country. To increase its impact on Guinea, AFC is considering several projects in the country to create an integrated ecosystem. This would include, alongside this Project, a 33MW solar project port, and other mining projects, all of which will complement AFC’s earlier investment in Alufer’s Bel Air bauxite mine.
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.
The Nigerian Content Development and Monitoring Board (NCDMB) has signed equity investment agreements with two companies-Duport Midstream Company for the establishment of an Energy Park in Egbokor, in the country’s midwest and Eraskon Nigeria Limited, for a lubricating oils blending plant in Gbarain, in Nigeria’s south central east.
The planned Energy Park comprises a 2,500BPD modular refinery, as well as a thirty million standard cubic feet of gas a day (30MMscf/d) gas processing facility, which will include a CNG facility and 2MW power plant.
The lubricating oils’ blending plant will have the capacity to produce 45,000litres per day and enhance the availability of engine oils, transmission fluids, grease and other products.
Simbi Wabote, Executive Secretary NCDMB, explained that the investments were part of the approvals granted recently by the Board’s Governing Council chaired by Timipre Sylva, Minister of State for Petroleum Resources, He clarified that the investments were coming under the Board’s commercial ventures programme and were in sync with the NCDMB’s vision to serve as a catalyst for the industrialisation of the Nigerian oil and gas industry and its linkage sectors.
The Duport partnership, Wabote indicated, is in furtherance of the Board’s strategy to enhance in-country value addition by supporting the establishment of processing facilities close to marginal or stranded hydrocarbon fields.
NCDMB has already had partnered with the Waltersmith Group and Azikel Petroleum Company for the establishment of modular refineries in Imo State and Bayelsa State respectively.
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.
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.
The Governing Council of the Nigerian Content Development and Monitoring Board (NCDMB) has approved the expansion of the Nigerian Content Intervention Fund from $200Million to $350Million.
The enlargement of the Fund by $150Million was part of the decisions taken at the recent NCDMB Governing Council meeting, which held virtually on June 16, 2020. The meeting was chaired by Timipre Sylva, the country’s Minister of State for Petroleum Resources and Chairman of the Council.
The Council approved that $100Million from the additional funds would be deployed to boost the five existing loan products of the NCI Fund, which include manufacturing, asset acquisition, contract financing, loan refinancing and community contractor financing.
The Council also approved that $20Million and $30Million respectively should be deployed to two newly developed loan product types – the Intervention Fund for Women in Oil & Gas and PETAN Products, which include Working Capital loans and Capacity Building loans for PETAN member companies.
PETAN is Petroleum Technology Association of Nigeria, a body of Nigerian owned oil service engineering contracting firms.
The NCI Fund was instituted in 2017 as a $200Million Fund managed by the Bank of Industry (BoI), engaged to facilitate on-lending to qualified stakeholders in the Nigerian Oil and Gas industry on five loan product types. The NCI Fund is a portion of the Nigerian Content Development Fund (NCDF), aggregated from the one percent deduction from the value of contracts executed in the upstream sector of the oil and gas industry. About 94 percent of the NCI Funds has been disbursed to 27 beneficiaries as at May 2020. NCDMB has received new applications from 100 companies for nearly triple the size of the original fund.
Guidelines for the NCI Fund provide that beneficiaries of the Manufacturing Loan and Asset acquisition Loan can access a maximum of $10Million respectively. Beneficiaries of Contract finance Loan can access $5Million while beneficiaries of the Loan Re-financing package can access $10Million, with beneficiaries of the Community Contractor Finance Scheme limited to ₦20Million.
The maximum tenure for all loan types is 5 years and applicants cannot have two different loans running simultaneously.
At the onset of the Fund, the applicable interest rate for the various loan types was pegged at eight (8) percent, except the Community Contractor Finance Scheme, which was five (5) percent.
However in April 2020 as part of NCDMB’s response to mitigate economic impact of the coronavirus pandemic, the Governing Council approved reduction of the interest rate from eight (8) to six (6) percent per annum for all four of the loan products. The Board also extended the moratorium for all loan products.
Hesham Mekawi has decided to retire. The Egyptian engineer, who is BP’s Regional President for North Africa, is leaving after a career with the European oil giant spanning over 30 years.
Mekawi will leave at the end of 2020 to pursue non-executive director opportunities. He will continue in his current role until 1 July 2020 and will then spend 6 months as a senior advisor to ensure the smooth transition of leadership.
Hesham joined BP in 1990 and, in the early stages of his career, held a variety of commercial, economic analysis and business development roles in Cairo, Houston, Chicago and London. He led the consolidation of BP Egypt, BP Algeria and BP Libya to create the expanded BP North Africa Region in 2014. Hesham transformed the North Africa business by identifying and progressing complex growth opportunities and actively managing the portfolio.
Over the past 5 years, BP has invested $14Billion in Egypt delivering at its peak 60% of Egypt’s annual gas production together with its partners. Hesham has been recognized many times over the years, both internally and externally. Of particular note is that he and his team were awarded BP’s Helios award for “BP at its best”, in 2011.
Bernard Looney, BP CEO, commented that “Over the years BP has counted on Hesham’s vision and leadership to maintain and grow our business in North Africa. Hesham has always shown outstanding performance and progressive leadership supported by longstanding relationships with key stakeholders and business partners. His deep commitment to the development of people has served as an example to us all. Hesham has been instrumental in delivering on our plans over many years – regardless of the circumstances. We will miss him.”
One month after it announced the waiving of its fees for oil service companies in the country, Equatorial Guinea has granted E&P companies a two-year extension on their exploration programmes.
The grant, the country says, “will also ensure flexibility on the work programmes of producing companies to ensure growth and stability in the market”. In late March, the Ministry of Mines and Hydrocarbons MMH said it took the unanimous decision to waive its fees for service companies for a duration of three months, adding that it recognised the fact that the oil sector continues to be the largest private sector employer in the country and “we want to give our local services companies the means to weather the storm and avoid any jobs being lost”. It said it was “the first action to be taken to support oil & gas services companies in the wake of the oil price drop caused by the coronavirus pandemic”.
Oil prices have headed farther south in the four weeks since that first announcement, with the horizon even cloudier. Yesterday’s press release announcing the grant of extension of tenor of acreage licences came less than a week after the Petroleum minister, Gabriel Mbaga Lima Obiang, suggested at a webinar that countries should be granting extensions for E&P licences at this time, as companies would be unable to carry out work programmes with any clarity until 2021.
“The Ministry of Mines and Hydrocarbons remains concerned about the resounding impact of the drop in oil prices, COVID-19 and its dramatic consequences on our hydrocarbons industry”, says the release.
“At a time of great uncertainty, we have an obligation to make bold, decisive, and pragmatic policy decisions to get the industry moving again,” the statement explains, adding that the government is fully committed to safeguard local oil & gas industry, its companies and its employees.
“The granting of these extensions has been deemed suitable to create an enabling environment for international and African companies to keep investing in Equatorial Guinea and ensure a quick recovery of our industry.
“The MMH will continue working with oil companies benefitting from such incentives to make sure that the recovery of Equatorial Guinea’s oil sector is made on the back of local content promotion, increased technology transfers, and procurement of additional local goods and services. A particular emphasis will be put on educating, training and promoting local workforce to help further reduce operational costs for international companies while maximising the creation of local value and revenue”.
With these proposals, the Equatoguinean authorities say they guarantee existing investments into Equatorial Guinea, while empowering local companies to assist their foreign partners in safeguarding and increasing their operations in the country.
“Some of these companies operating in Equatorial Guinea notably include ExxonMobil, EGLNG, Marathon Oil Corp, Atlas Petroleum, Kosmos Energy, Noble Energy, Glencore, Royal Gate Energy, Gunvor, Trident Energy, etc.
“Such historic measures are being rolled out as Equatorial Guinea implements a series of landmark projects across its upstream, midstream and downstream industries. The backfill project is already ongoing to pool supply from stranded gas in the Gulf of Guinea and replace declining output from the Alba Field. Meanwhile, the ongoing Year of Investment has generated strong interest from various existing and new players in Equatorial Guinea to build and expand midstream and downstream infrastructure and maximise local processing and transformation of domestic crude oil and natural gas.”
