All posts tagged feature


Why the Current Energy Market Reminds us of ‘Tulipmania’

By Gerard Kreeft

 

 

 

 

 

 

 

Tulipmania  got its name from the Dutch tulip market bubble, which occured in the early to mid-1600s, when speculation drove the value of tulip bulbs to extremes. At the height of the market, the rarest tulip bulbs traded for as much as six times the average person’s annual salary.

Translated otherwise: tulips sold for approximately 10,000 Dutch guilders, equal to the value of a mansion on Amsterdam’s Grand Canal. The mania and crash occured in the short period of 1636 – 1637 when contract prices collapsed abruptly and the trade of tulips ground to a sudden halt.

The Tulipmania bubble of the 17th century is an apt description of the gas and oil sector of the last 75 years. The great divide is the 2015 Paris Climate Agreement.

Post-Paris there are two very differing scenarios emerging. Scenario Renewable, as the name suggests, is a proponent of renewable energy—be that hydrogen, wind, geothermal and solar energy. Scenario Oil, also as the name suggests, is a staunch believer in oil production.

Can the two scenarios be reconciled with each other?

Scenario Renewable is playing out in various versions in Europe. Offshore- wind, solar and hydrogen projects are key ingredents for Europe’s major oil and gas companies who include BP, ENI, Equinor, Shell and TOTAL.

A key strategic question is juggling funding to ensure that both oil and gas projects and renewables can be managed and implemented. Whether both types of assets can be financed and managed successfully under one roof remains unanswered.

To date, all of Europe’s majors are playing their cards close to their chests, hoping their twin stakes—oil & gas and renewables—will ensure them the best of both worlds; a continuous stream of good margins from their oil and gas assets and stable revenues from their renewables. The makings of the energy company of the 21st century.

A competing factor are Europe’s energy companies—Iberdrola, Engie,Vattenfall, RWE, Orsted, Enel—who have already drawn up their green strategies.

Increasingly, the lines of demarcation are being drawn up.

Scenario Oil is best represented by the American oil companies ExxonMobil, Chevron, and such large independents as Occidental, Marathon and Devon Energy, whose portfolios only include oil and gas projects. Any discussions about the energy transition are confined to within the scope of oil and gas. In other words: no Plan B.

Begining this October, Chevron surpassed ExxonMobil in terms of market capitalization. Since the start of 2020, ExxonMobil has lost 50% of its market value, compared with Chevron’s 39%. ExxonMobil was also forced out of the Dow Jones Industrial Average due to its sharply diminished market capitilization.

Simon Flower, Chairman & Chief Analyst of the consultancy firm of Wood Mackenzie stated in a recent study that ExxonMobil is exposed to high-cost, low margin assets, principally oil sands and other areas including Alaska.

According to the study, ExxonMobil’s cash margins are the lowest of the majors based on $30 per barrel. ExxonMobil owns 60% of the majors’ lowest assets based on $30 barrel.

In a scathing report on ExxonMobil’s CEO Darren Woods, IEEFA (Institute for Energy Economics and Financial Analysis, based in Cleveland, Ohio, USA) has asked the Board that Woods be sacked.

IEEFA maintains that ExxonMobil defined itself as the oil industry’s  global leader which all others followed. In the short span of three years (2017-2019) Woods has presided over a significant deterioration of the company’s finances.

“By both short- and long-term financial measures, ExxonMobil has shown significant signs of slippage against past performance. Faced with the same market challenges as its peer-competitors (Shell, TOTAL, BP and Chevron), Woods’s tenure has been marked by a faster rate of decline or deeper losses in profits, cash and shareholder value. Based on actual performance, IEEFA recommends that the board of directors move to replace Woods.”

Yet Chevron should not gloat. Some 50% of its oil production comes from only two key regions, making it very vulnerable in terms of diversity of supply, as highlighted:

Tengiz in Kazakhstan which in 2018 celebrated its 25th anniversary and geared to produce up to 1MMBOPD (oil equivalent). With its highly sulfur-rich oil, Tengiz could well become an ugly duckling.

Africa: Nigeria, Angola,Republic of Congo and Egypt- having a daily net oil production for Chevron of 412,000BPD (oil equivalent). Sub-Saharia Africa could also turn sour. Angola, where Chevron is a major oil producer, once the darling of the continent, has seen its oil production continuing to slip downward, now at 1,200,000 BPD.

Yet, with both ExxonMobil and Chevron there is a complete lack of any strategic discussion as to whether renewable fuels play a role. Their entire energy transition strategy is solely done within the confines of the fossil bubble.

The Spoiler: Saudi Aramco

The spoiler in both energy scenarios could be Saudi Aramco, the state oil company of Saudi Arabia. Consider the following: Saudi Aramco has 20% of the world’s oil reserves, can produce oil for only $4.00 per barrel and can quickly increase production up to 13Million barrels per day.

Regardless how low the oil majors manage to bring down their barrel of oil production price, who can compete with production costs of only $4.00 per barrel? If you are the Minister of Energy in a petro-economy, does it not make more sense to close shop and simply import Saudi oil?

The  low oil price and COVID-19 have also impaired the US shale operators, seen by the Saudis as competition needed to be sidelined. The Deloitte study entitled “The Great Compression: Implications of  COVID-19 for the US  shale market” is forecasting impairments of up to $300Billion and that 30% of shale operators are technically insolvent.

If COVID-19 and the oil spat continue for a longer period, will the Saudis  pump more oil to ensure market share and economic gain? Even at the cost of taking a wrecking ball to OPEC and the international majors?

Saudi Aramco’s message is very simple: pump the oil while it still has economic value. In 15-20 years it could become a vast stranded asset.

Saudi Aramco also has extensive downstream ambitions: possibly investing in China’s Zhejiang refinery and petrochemicals complex south of Shanghai.

Aramco is also in talks with Reliance Industries to buy a 20% stake in its oil-to-chemical business in India.

Finally, Saudi Aramco has also unveiled its renewal strategy, launching a $500Million fund to promote energy efficiency and renewables. It aims to generate 9.5 GW of renewable energy by 2030.

Saudi Arabia’s Vision 2030 outlines the country’s three objectives wanting to create a :

Vibrant society

Thriving economy

Ambitious nation.

Expect Saudi Aramco to take an aggressive marketing stance in the coming months in order to be able to finance its domestic agenda.

Conclusions

How can Europe’s majors avert a modern version of tulipmania by continuing to fund both renewables and oil and gas projects and still be competitive?

Will we see more  spin-offs and specialization? For example, to ensure that deepwater projects can be cost effective. In the meantime, offshore wind projects are rapidly gaining due to economies of scale.

What is the role of Europe’s green energy companies?

How should the oil and gas majors co-operate with Saudi Aramco?

What will be the role of Saudi Aramco in the energy transition?

In 15-20 years will the tulip be a symbol of value or a bad memory?

Gerard Kreeft,  BA ( Calvin University ) and  MA (Carleton University, Ottawa, 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.

 

 

 

 


EUNISELL CREATES NEW BUSINESS MODEL FOR OIL COMPANIES, OVERCOMES DEVELOPMENT FINANCE BARRIERS FOR NOCs

PARTNER CONTENT

Eunisell Production Solutions has pioneered a new business model, enabling NOCs to realise their development goals and bring their fields up to optimum operating potential, without relying on external investment. 

The delay between when the blocks are awarded and when development commences, is a tangible concern for any investor or financial institution. Obstacles to the execution of development plans for these assets has indicated an insecurity of when a return on investment might be achieved, thus uncertainty and reluctance are created.

To solve the challenge, Eunisell delivers four key business benefits: 1. Faster delivery of first oil revenues. 2. Enhanced production from proven fields. 3. Engineered solutions for long term development and 4, Innovative technology.

NOCs are already reeling from the impact of Covid-19 on the industry and depressed oil prices. This means that owners will continue struggle to finance the development of their fields. Any financial assistance in that scenario would be limited at best and come at a heavy cost.

Added pressure comes from Government where owners are expected to deliver on the agreed development and output or risk losing their concessions as witnessed in recent times with the cancellation of 11 operators’ licenses. With the economic and global status quo, options are limited, if any, and this is why Eunisell has stepped in. Eunisell has been providing services based on experience, technology, economics and now, business innovation, to assist NOCs to develop their fields profitably over a measured period.

Service companies are able to design and deliver EPCC projects that will provide long term production and income for the NOCs. The problem is that these projects are inherently costly and require large payments at numerous milestones before production is actually achieved. The procurement and construction phases of these projects are extremely capital intensive and protracted.

By providing solutions, there is a positive impact on Nigeria’s GDP in addition. More oil yielded by NOCs translates into additional national revenues. Having large potential reserves not being produced, simply because a way cannot be found to bring the needed investment, facilities and technology to operators, is a negative influence on our industry, and Nigeria’s economy.

Each one of these assets or the assets currently included in the Marginal Field Bid Round that can be brought to production and developed to its full potential, represents significant increments to foreign exchange and taxes for government. Furthermore, there’s increased employment, community development and growth for the local economies.

The positive effect of bringing these fields to potential is enormous for all levels of the economy. Eunisell is in effect, acting as a technical partner, engineering and delivering the means to bring the existing production to market rapidly, generating revenue and enabling further development.

Compared to existing EPCC projects, Eunisell’s solution requires only a relatively minimal initial cost and is delivered in weeks rather than months. This immediate approach enables concurrent development of the asset. Eunisell will design and deliver the fit-for-purpose production management project, leaving operators to concentrate on long-term production expansion plans.

By working with the field owner, Eunisell assures that the solution provided serves not only short-term output yields, but is designed to meet the field’s expected potential and beyond. By providing the technical solutions and funding the development through rapid delivery of production, the capital required for field development is reduced to manageable levels. Further, the return on the original capital investment is achieved in a significantly shorter period of time.

With Eunisell’s model for success, we are using production costs to partner with the operators to develop the asset. And with Eunisell’s production enhancement and production delivery capacities, these costs can be further reduced to make depressed oil prices viable and enable funding development of Nigerian assets for the benefit of all.

Eunisell Production Solutions

www.eunisellproduction.com

info@eunisell.com

+234 908 765 9938

 


Nigeria’s Regulator to Take over Frontier Exploration, in the New Law

Exploration of frontier basins shall fall under the purview of the Upstream Regulatory Commission, if the Petroleum Industry Bill, under consideration at the National Assembly, becomes law in its current form.

In the wordings of the law, the Commission is now empowered to carry out the functions that the state hydrocarbon company, NNPC, currently performs through its subsidiary: Frontier Exploration Services. One passage in the PIB  that expressly indicates this is Section 9, part of which says:Where data acquired and interpreted under a Petroleum Exploration Licence is, in the judgment of the Commission, requires testing and drilling of identifiable prospects and leads, and no commercial entity has publicly expressed an intention of testing or drilling such prospects, the Commission may engage the services of a competent person to drill or test such prospect and leads on a service fee basis”.

The NNPC is performing this exact function in the ongoing drilling of Kolmani River 3, the second appraisal of the gas discovery made by Shell in 1999.

NNPC reported last year that the first appraisal, Kolmani River 2, in the Gongola Basin, encountered both oil and condensate apart from gas and that they were significant finds. The corporation did not disclose specific petrophysical details of the find, a situation that has aggravated the uncertainty in the conversation around likely economic sizes of hydrocarbon reservoirs in Nigeria’s inland basins.

NNPC is also carrying out exploration activity in the Chad Basin further northwards and has had to stop its seismic operations after insurgents attacked and killed technical workers and some of the security forces.

The PIB says that the function of the Upstream Regulatory Commission, with respect to Frontier Basins shall be to – (a) promote the exploration of the frontier basins of Nigeria; (b) develop exploration strategies and portfolio management for the exploration of unassigned frontier basins in Nigeria; (c) identify opportunities and increase information about the petroleum resources base within frontier basins in Nigeria; (d) undertake studies, analyse and evaluate unassigned frontier basins in Nigeria. The law also says that there shall be maintained, a Frontier Exploration Fund, which shall be 10% of rents on petroleum prospecting licences and petroleum mining leases.The Commission shall manage the Frontier Exploration Fund in accordance with regulations made under this Act”.

 


GNPC Has Not Achieved Operatorship Status, PIAC Declares

Ghana National Petroleum Corporation (GNPC) says it has achieved the first part of the objective of “becoming a stand-alone Operator by 2019 and a world-class operator by 2027”.

But the Public Interest Accountability Committee (PIAC) demurs, arguing that GNPC is yet to achieve anywhere close to any of the objectives. But the PIAC does not explain its disagreement with GNPC’s claim to operatorship.

According to GNPC, the role of Operator will allow it to retain maximum benefits for Ghanaians including the ability to:

  •  align reserve management policies with national development policy
  • control technical operations and contracting processes
  •  allow better support of local content development
  •  build effective systems and processes
  •  appropriate a greater share of revenue and benefits for the nation.

“In GNPC’s assessment of progress against its overarching goal, it asserts that it has attained operatorship, citing its role in the Voltaian Basin and the OGH_WB_01 – Shallow water Block”, PIAC says in its annual report.  “GNPC further points to its role in managing interests in various assets, including the Saltpond Field decommissioning activities as well as the Corporation’s capacity along the upstream value chain, and capabilities in the upstream petroleum industry, as it is a party to all upstream Petroleum Agreements in Ghana as well as its plans to operate two onshore blocks by 2021 as evidence of its operatorship status”.

PIAC says that its “assessment of GNPC’s claims in the light of the definition of operatorship under Act 919, found no evidence to support GNPC’s claim of attaining operatorship”.

This story was initially published in the August 2020 issue of the Africa Oil+Gas Report


Morocco, Considering COVID -19, Grants Licence Permit Extension

Moroccan authorities have extended the permit for the onshore Sidi Moktar acreage by 24 months, as a result of COVID-19 issues.

The beneficiary of the consideration is Sound Energy.

The company says the extension is a result of regular dialogue with the regulatory authorities, L’Office National des Hydrocarbures et des Mines ONHYM, which has now added 24 months to the initial period of the Petroleum Agreement in order for the Company to complete the committed work programme.

London listed Sound Energy was awarded the petroleum agreement related to the 4,712 square kilometre Sidi Moktar permit on 12 February 2018, with an initial period of 2 years and 6 months.  The Company holds an operated 75% position in the permits with the remaining 25% held by ONHYM.

The acreage is in the Essaouira basin, central Morocco

Subject to the issuance of the Joint Arreté signed by the Minister  in charge  of Energy and Minister in charge of Finance, the length of the initial period will now be 4 years and 6 months, commencing 9 April 2018. The work programme commitments for the initial period remain unchanged.  The lengths of the first and second complimentary periods, which would commence upon the successful completion of the recently extended initial period, remain unchanged at 3 years, and 2 years and 6 months, respectively.

 


Welltec Solves Geothermal Problems with Oil Industry Technology

Welltec, the Denmark headquartered oil service provider, says that the cleaning tools it manufactures have proven highly successful during testing for something other than oil wells: geothermal well cleaning applications.

The Well Miller® has capabilities for:
–          Silica removal – a common cause of geothermal production issues
–          Rigless intervention
–          Minimal footprint – lightweight yet high capacity tools
–          Saving time and money through fast

The Well Miller Reverse Circulating Bit (RCB) is a combinable milling tool enabling the simultaneous milling, break-up, and extraction of scale. The RCB also features a turbine section allowing well fluid to be circulated through the milling bit, and for any cuttings or debris to be collected into bailer chambers for later recovery once tools are rigged down at surface.

In testing, the RCB was run against a cured blend of silica pieces (Si02), sand, and epoxy resin, to replicate the most challenging silica clean-out scenario found in a geothermal setting.

“Not only was the removal of the silica replicant compound successful, the mill bit showed almost no signs of wear, thanks to highly resistant Tungsten Carbide milling teeth”, Welltec reports I a case study.

Overcoming Challenges

Welltec says it is already helping clients with geothermal well construction by providing the Welltec Annular Barrier (WAB®) for zonal isolation – a life of well solution.

“In terms of maintenance and intervention, Silica scale is one of the main flow production issues found in Geothermal wells.  In particular, the challenge faced with this type of material stems from its strength and high level of resistance, making it incredibly difficult to mill through”, the company explains.

Geothermal Potential

Welltec believes that Geothermal energy offers the highest capacity energy form within the renewables market.  ”With the ongoing development of Enhanced  Geothermal Systems (EGS), the future potential is further expanded and can help to facilitate an even more efficient and sustainable way to harness the Earth’s natural energy source,” the company declares on its website.

Collaboration in the Field

Welltec continues to collaborate with industry experts and provide technology for research projects with allocated funding from the U.S. Department of Energy. In a project led by the University of Oklahoma and Veizades & Associates, Welltec will be testing its latest Welltec Annular Barrier (WAB) in multiple zones of interest at the Coso Geothermal Field, California.The WAB will be applied to achieve zonal isolation and improve mass flow through stimulation in a high temperature environment.

Academic contribution

Welltec has recently co-authored an academic paper with Energy Development Corporation (EDC) of the Philippines, presenting highly successful well repair operations from the field. The paper highlights the benefits of repairing wells to re-establish production rather than abandoning them for new ones– in doing so, the WAB can prevent casing collapse and deformation caused by trapped water.

The case will be presented at the 42nd New Zealand Geothermal Workshop on 24-26 November, 2020.


Egypt’s Alexandria Refinery Gets $250MM Financing for Upgrade

By Ahmed Gafar, Editorial Assistant

Egypt’s state-owned Alexandria Petroleum Company (APC) will receive a quarter of a billion dollars ($250Million) from the European Bank for Reconstruction and Development (EBRD sovereign loan.

The loan is partial financing of the $647Million in water and energy efficiency upgrades at the company’s diesel refinery (Alexander Refinery).

The project will bring operations at the facility in line with European environmental safety standards and reduce emissions, the bank said.

Alexander Refinery, established in 1954, is operated by APC with a crude design capacity of 100,000 BPSD. It typically processes light Western Desert crude oil and heavy Kuwait crude oil. It began life as a small refinery with 250.000 ton/year capacity for satisfying Alexandria city and West Delta area needs from the petroleum products. APC refining capacity increased up to 4.7Million ton/year by executing three crude distillation units No. 2, No. 3 and No. 4 in the years 1963, 1968 and 1982 respectively. In 1979, a solvent production complex started in operation under the license of UOP to produce Hexane, Petroleum Ether, and Petroleum solvents. In 1982, the lube oil complex started in operation with design capacity 100.000 ton/year bright stock oil, based on fuel oil feed from Kuwait crude oil origin and in 1983 the vapour recovery unit started operation to produce Stabilized Gasoline and LPG.

Finally, in 1989, the Hexane and Kerosene complex started with annual production capacity of 22.000 ton / year hexane or 18.000 ton / year of treated Kerosene under the license of IFP, while in 1997 the spent oil re-refining unit started in operation with capacity 30.000 ton/year of spent oil and under the license of KTI. Bitumen blending, oxidation and solidification unit started in operation to produce solid bitumen packages in 25 kg blocks.

The EBRD says: “Raising the quality of fuel produced by the refinery will cut down on greenhouse gases, while the construction of a new wastewater treatment facility aims to lower the risk of seawater pollution and a new energy management system will help to reduce fuel consumption”..


Natural Gas Base Price Inches Up in Nigeria, according to the PIB

By Toyin Akinosho

The domestic base price, the price at which Nigerian gas producers are to sell to Power Plants, will be $3.2 per Million British Thermal Units (MMBtu), beginning from January 1, 2021, if the Petroleum Industry Bill (PIB) is passed into law in its current form.

But the price at which the gas-based industry, comprising companies which produce methanol, fertilizer (urea, ammonia), polypropylene, etc., will purchase natural gas, can be as low as $1.5 per MMbtu, the incoming law says. That price is special and it is calculated from a formula.

Gas users outside the power sector and the gas-based industry will pay at least $0.5 higher than $3.2 per MMbtu, and their cost of purchase will depend on negotiations with their suppliers.

The domestic base price -$3.2per MMBtu- which is specified in the third schedule of the bill, currently being debated at the Nigerian National Assembly, shall be increased every year by $ 0.05 per MMBtu until 2037, when a price of $ 4.00 per MMBtu will apply for that year and future years.

The Midstream and Downstream Regulatory Authority, “may, by regulations, change the domestic base price and the yearly increase) to reflect changed market conditions and supply frameworks”, says the bill, submitted two weeks ago by President Muhammadu Buhari.

“The objective is to establish a fully functioning free market in natural gas for domestic supplies. This is to be achieved through the voluntary supplies. Where insufficient voluntary supplies are occurring, the Authority may increase the domestic base price and, or the yearly increases. At the same time, the Authority shall monitor the gas prices in other major emerging countries and ensure that Nigeria continuous to have a price level for natural gas that is less than the average of these emerging countries in order to promote the non-oil sectors in the Nigerian economy”.

Timipre Sylva, Minister of State for Petroleum, had given hint of the gas pricing framework last August during a conversation with the Nigeran Association of Petroleum Exlorationists (NAPE). The bill, he explained, “will establish a gas base price that is higher than current levels (The current domestic base price is $2.5 er MMbtu)  for producers and this base price will increase over time”.

Sylva said: “This price level should be sufficiently attractive to increase gas production significantly since this gas price will be comparable with gas prices in other emerging economies with considerable gas production.

“The price will be independent of all gas prices for LNG export and is therefore a stable basis for enhanced domestic gas development, regardless of international oil or energy development”.

 


Pavel Oimeke Returns as Head of Kenya’s Energy and Petroleum Regulator

Pavel Oimeke has returned to his position as Director General of Kenya’s Energy and Petroleum Regulatory Authority (EPRA), after the Employment and Labour Relations Court in Nairobi cleared him for reappointment.

Jackton Ojwang, retired Supreme Court Judge and chairman of the EPRA board said in a statement that Mr. Oimeke could now return to his job.

Oimeke, a trained engineer initially appointed on August 1, 2017, was to have commenced the second three-year term at the head of the agency on August 1, 2020, but an EPRA board meeting decided to send him on leave pending the outcome of a case where a petitioner, Emmanuel Wanjala, challenged his second term in office.

Mueni Mutung’a, the EPRA Secretary and Director of Legal Affairs, has been acting as Director General since August 17, 2020.

EPRA, a Kenyan state corporation established under the Energy Act, 2006, is the sector regulatory agency responsible for economic and technical regulation of electric power, renewable energy and downstream petroleum subsectors.

“His reinstatement follows a court order issued by in Nairobi on October 6, 2020,” Mr Ojwang’ said in a statement. “Mr Oimeke had stepped aside in August 2020 pending the hearing and determination of a court case contesting his appointment as director-general”.

 


Angola Signs Three New Deepwater Contracts with ExxonMobil

Angola’s National Oil, Gas and Biofuels Agency (ANPG) has signed three Risk Service Agreements with ExxonMobil and Sonangol Pesquisa e Produção, SA (Sonangol P&P), the operating arm of the state hydrocarbon company.

Deep water blocks 30, 44 and 45, covering over 17,800 square kilometers are located between 50 and 100 kilometers from the Angolan coast, in water depths ranging from 1,500 to more than 3,000 meters.

ExxonMobil will operate the three blocks, with 60% interest, while, Sonangol P&P “will have an associative participation of 40%”, a statement by ANPG declares.

Paulino Jerónimo ANPG ‘s Chairman of the Board of Directors, remarks that ExxonMobil’s presence in the Namibe Basin, where the country has never found hydrocarbon, is a key advantage. It would, he argues, help the country  to deepen the geological knowledge  in the largely unexplored basin.

“The success of the work carried out in Angola by international operators, many of whom already have a consolidated presence in the country, is an extremely important factor for the development and credibility of the Angolan oil sector”, Jerónimo notes.

“We will work with the Angolan government and ANPG to identify the border areas with the best resource potential, applying our proven experience and our cutting-edge technology,” says Andre Kostelnik, ExxonMobil’s General Manager in Angola, adding that ” these new concessions are the result of the long success history of our exploration and production activities in Angola.”

Sebastião Gaspar Martins, Chairman of the Board of Directors of Sonangol, in turn, considers the extension of prospecting and exploration activities to an area unexplored in Angola to be extremely important. “We are excited to be a part of this challenging project”, he explains.

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