Under the EU’s proposed Green Deals, means member states including Germany need to significantly tighten their carbon emission reduction targets, e.g. through an accelerated build-out of renewable energy sources and by using hydrogen as fuel for transport and industrial processes.

Early coal-exit without compensation

Independent experts monitoring the German Energiewende noted: “The coal phase-out planned in Germany must be improved based on the decisions on the European Green Deal.”

The exit from the fossil fuel, in their view, “has to happen significantly quicker and be largely driven by market-based CO₂-price signals”, and – if possible – without compensation payments for operators.”

To date, the German coal exit commission recommended shutting the last coal-fired power plant by 2038 at the latest. Experts, however, criticize this timeframe arguing without the legally regulated exit path. Many German coal-fired power plants would have exited the market earlier, they argue, mainly due to higher emission prices under the European emission trading scheme (EU-ETS) and a “relatively sharp drop in gas prices.”

Instead of sticking to a firm phase-out schedule, experts propose more flexibility of the phase-out path, transparent and flexible agreements with operators, the earlier introduction of recovery-relevant pieces of the support package for coal regions and closer cooperation with international partners.

Replace EEG levy with national ETS surcharge

Experts criticised Germany’s disorganised system of energy prices, levies, taxes and other instruments. Though the government had initiated certain changes on energy pricing and the renewable levy cap, critics call for a more “systematic and comprehensive reform.”

The electricity tax should be decreased to the European minimum and levies on electricity, such as the renewables surcharge and combined heat and power (CHP) levies, should be abolished “as fast as possible”, financed by a CO₂ price on fossil fuels and the general German budget.

To finance further reduction they even propose an additional CO₂ levy in the sectors already covered by the EU emissions trading system (ETS) which could bring the price up to about 50 Euros per tonne of CO₂. The ETS allowance price has been 20-25 €/t CO₂ over the past couple of months.

While the experts do not demand a certain carbon price, “50 Euros per tonne of CO₂ continues to be an appropriate price level,” the Commission head Andreas Löschel noted. He added that low oil, gas and wholesale power prices currently created a window of opportunity to steer future investments in the right direction.

The South African energy department in December issued a request for information (RFI) to source between 2,000 and 3,000 megawatts (MW) of power generation capacity at the least cost. That RFI calls for start of commercial operation, following financial close, of either three to six month or six to twelve month.

Eskom currently has a shortfall in generation of well over 2,000 MW which puts supply security at risk as energy demand rises over the summer.

Suitable locations for new ships identified

“In our proposal, we have spelled out what is possible, where and how we would look to do it,” said Patrick O’Driscoll, global sales director at Karpowership. Several locations have been identified as potential mooring points for the new ships, suitable to inject the electricity generated offshore into the South African power grid.

Karpowership has a fleet of 22 ships, which have a combined generating capacity of 3,500MW, with the largest single ship generating 470MW – about a tenth of the 4,800MW Eskom’s Medupi and Kusile power stations each generate.

Each ship can provide a range of power supply options between 30 MW and 600 MW, and could be hired by Eskom for different time spans. O’Driscoll pointed out using gas-fuelled power ships would be “very affordable” compared to Eskom’s currently dispatched diesel-fired emergency gensets.

Cheaper fuel costs, short delivery times

Eskom currently needs to spend billion of South African rand annually to buy diesel for emergency power units, mostly driven by open-cycle gas turbines. Karpowership underlined that the operational cost of one of its gas-fuelled ships will be “significantly less, maybe even half the cost of those [Eskom’s] peakers.”

Speed of delivery is crucial for emergency power solutions; hence O’Driscoll pointed out that a Karpowership was recently delivered and operated a 120 MW contract in Senegal within just nine weeks. In addition, the 235 MW Powership Ayşegül Sultan is moored off Dakar since August 2019, contracted to supply 15 percent of Senegal’s electricity needs for 5.5 years.

Headquartered in Istanbul, Karpowership is the only owner, operator and builder of the first Powership fleet in the world. It has 25 powerships, all built in Turkey, in operation and an order book to build new vessels in excess of 4,400 MW.

“As BP along with the rest of the world navigate the energy transition, we will need timely, objective and comprehensive data on the global energy system,” CEO Bernard Looney commented,

Calling the world’s emergence from the Covid-19 pandemic “a pivotal moment” for global economies, he underlined that “for BP, the pandemic has only reinforced our commitment to our ambition to become a net zero company by 2050 or sooner.”

A week ago, BP announced to plans to cut 10,000 jobs in reaction to a global slump in oil demand. The company’s gas and LNG business unit, in contrast, benefitted from a rise in trade despite markedly slower growth in consumption.

Demand rebounds, lead by U.S. and China

“Global natural gas consumption growth averaged 2 percent in 2019, below its 10-year average and down sharply from the exceptional growth seen in 2018 (5.3 percent),” the BP Statistical Review reads. “In volume terms, demand grew by 78 billion cubic metres (Bcm), led by the United States (27 Bcm) and China (24 Bcm).”

China’s growth in gas consumption, however, has slowed down significantly compared to the previous year, as the effects of Beijing’s coal-to-gas switching are fading. Weather-related effects (less unusually hot or cold days) also led to a 10 Bcm fall in Russia’s domestic gas consumption - the largest decline of any country last year.

Supply far outweighs demand

On the supply side, gas production was up 132 Bcm or 3.4%, outpacing the growth in consumption.

Supply from the United States made up nearly two thirds of net global growth in gas supply, according to BP figures with the volumetric increase of 85 Bcm just shy of 2018’s record increment (90 Bcm).

Australia added another 23 Bcm and China some 16 Bcm to the global gas supply in 2019, the Review states. Much of the surplus supply was used for to feed a rising number of liquefaction terminals.

Global LNG export volumes grew by 54 Bcm, or 12.7 % last year, the largest annual increase ever, driven by record volumes from the United States (19 Bcm) and Russia (14 Bcm) as well as continued growth from Australia (13 Bcm), BP analysts noted. In terms of LNG imports, nearly all incremental supply was seen headed to Europe in 2019, not Asia as was the case in years before.

“European LNG imports rose by 49 Bcm, representing an unprecedented 68% increase,” BP analysts said. Growth was widespread, with 11 Bcm headed to the UK, some 10 Bcm to France and 7 Bcm to Spain.

Called ‘A250 Stade-Landesbergen’ project, Tennet’s latest grid expansion foresees the construction of a 145km power line between Dollern and Landesbergen. It is part of a government-led wider grid expansion plan, designed to remove existing grid bottlenecks and facilitate an efficient flow of wind power from the north to the south of the country. 

“The energy transition in Germany will only be successful if the increase in offshore wind energy and solar energy is integrated with the expansion of the grid. The TenneT A250 grid expansion project is therefore a critical factor in Germany’s drive to achieve its climate goals,” commented Dr. Thomas Brandstätt, board chairman at Tractebel Engineering.

Tractebel Engineering will lead the project over the next six years under an EPCM (or Engineering, Procurement and Construction Management) contract, whereby Tractebel’s Lahmeyer unit will be working with external partners including ERM Group and EQOS Energie Deutschland.

Under the contract, Tractebel is responsible for the complete project management for the construction of essential parts of the overhead line, including the management and coordination of the planning, design and construction.

Headquartered in Brussels, Tractebel is one of the world’s leading engineering companies with over 5,000 employees and a turnover of 671 million Euros in 2019. The Lahmeyer Group was acquired in 2014 by Tractebel which in turn is part of Paris-based ENGIE Group.

The chemical separation process is carried out in a special dehydrogenation plant from where the hydrogen gets transported to the nearby power generation unit. The demo plant is meant to supply up to 201 tons of hydrogen by the end of 2020.  

The green energy project enjoys the support of the Japanese government which seeks to turn the country into a hydrogen-based economy and coined the phrase of a “decarbonised society”. Several hydrogen pilot projects are supported by state funding.

Coal-to-hydrogen

The Australian-owned industrial gas company Coregas is working on converting brown coal to hydrogen for export to Japan under the so-called Hydrogen Energy Supply Chain (HESC) project.

Liquefied hydrogen produced from brown coal at Larobe Valley, Australia, will be shipped to Japan to fuel electric vehicles and power stations.

Construction works are well underway, with Coregas responsible for FEED (front-end engineering and design) of the liquefaction plant. The $500 million project is scheduled to start operations in winter 2020.

At the Latrobe Valley gasification plant hydrogen will be produced from syngas, formed by reacting brown coal with oxygen under high pressure and temperature. The output of high purity gas will then be compressed and transported to a new hydrogen liquefaction and loading terminal at the Port of Hastings.

Japan needs to import nearly 95% of its energy as fossil fuels and as the country is moving away from nuclear and coal, hydrogen is seen as a green alternative fuel. The government aspires to produce a substantial share of green energy from renewabes and hydrogen-based projects by 2040 to meet much of the demand from industry and transport.

To that end, ExxonMobil will need to ensure a continuous stream of LNG supply – either from its Golden Pass LNG venture in the U.S. or sourced through natural gas exploration offshore Vietnam, or from neighbouring countries.

The government in Hanoi is also keen for ExxonMobil to go ahead with a proposed 4,000 MW integrated LNG-to-Power plant in the northern part of Vietnam. The 4,000 MW venture is meant to be built in the northern port city of Haiphong, adding and could e completed between 2025 and 2030.

ExxonMobil has been seeking to progress oil and gas production activities offshore Vietnam for several years, though with little success. Pre-FEED was competed on the Ca Voi Xanh field in 2018, but activities stalled ever since even though the field is though large enough to provide electricity for a city the size of Hanoi for more than 20 years.

Hanoi seeks to double power gen capacity by 2030

Vietnam’s vibrant economy is facing severe energy shortages from 2021 as construction of new power plants cannot keep up with rising electricity demand. The government in Hanoi hence set out guidelines to boost generating capacity from currently 54 GW to 125 GW by 2030.

The construction spree is meant to raise the share of renewable energy sources to nearly 20 percent by 2030, while reducing reliance on emission-intensive thermal fuels. Coal, in particular, currently accounts for 38 percent of Vietnam’s installed power generation capacity.

Natural gas is meant to become one of the backbones of Vietnam’s future electricity mix, with the government supporting initiatives to develop LNG regas to import up to 8 million cubic metres of gas per annum.

Bac Lieu LNG-to-Power project already underway

In Vietnam’s southern province of Bac Lieu, Delta Offshore Energy is busy developing a $4 billion LNG-to-Power project, with up to 2 million tonnes per annum (mtpa) of LNG supply lined up under a contract with Australia-listed LNG Ltd, the former developer of the U.S. Magnolia LNG venture.

In May, however, the Magnolia LNG venture was sold to a privately-held energy infrastructure firm as cash-strapped LNG Ltd saw itself incapable of realizing the 8.8 million tons per year export project.

Administrators from PricewaterhouseCoopers arranged a sale to Global Energy Megatrend Ltd, with offices in London and Lafayette, Louisiana.

The upgrade of the Kossodo plant was stipulated by SONABEL, Burkina Faso’s national energy supplier, whereby the local company Tecmon BF is acting as main contractor. The company’s UK branch Tecmon Projects Ltd is now building up a solid group of EPC companies with a view to build and upgrade power plants and transmission lines across Africa.

Ending power shortages

Currently, only 30% of Burkina Faso’s population has access to electrical energy. The government now wants to change this and is planning to significantly increase generation capacity in the next years in an effort to end recurring power shortages and brownouts.

In Kossodo, the customer is currently relying on three MAN 18V51/60TS engines with two-stage turbocharging.

Gensets of this design have both a low- and a high-pressure compressor, which operate in series to deliver an increase in power density and efficiency. This simultaneously guarantees maximum fuel efficiency and a more compact system design.

Enhancing efficiency

Waldemar Wiesner, MAN’s power plant sales manager for region MEA (Middle-East Africa) is convinced that not only the reliability of the company’s engines, but also its high service quality was decisive for winning this order.

“SONABEL has chosen an innovative engine setup for the power plant in Kossodo, making it, by far the most efficient power plant in the country and clearly meeting the emission guidelines of the World Bank,” he said, adding: “As soon as the Kossodo power plant is extended, nearly 50% of Burkina Faso’s installed capacity will be based on MAN technology.”

The upgraded plant will also be by far the most efficient power plant in the country and clearly meet the emission guidelines of the World Bank.

SONABEL has relied on power plant engines from MAN since 1978. In total, the German OEM supplied power gen technology for five plants – all of still in operation.

Siemens will upgrade operations of the Moyle interconnector with is HVDC Classic system. Hauke Jürgensen, Head of Large Transmission Solutions at Siemens Energy explained “the upgraded system will provide more operational stability to weaker AC grids and will operate in a wider range of AC grid system conditions.” So in the future, more energy can be transmitted from Scotland to Northern Ireland and vice versa.

Enhancing ancillary services, adding overload function

Under the Moyle refurbishment contract, Siemens scope of supply is defined as; the detailed design, manufacturing, factory testing, installation, and commissioning of the control and protection system (including the replacement of auxiliary supplies, valve base electronics, and the measurement system), and the supply of a control training simulator.

The upgrade improves the dynamic performance of the interconnector, enabling Mutual Energy to offer enhanced ancillary services and accommodate more in-feed of variable renewable generation. By introducing an overload capability, the upgraded Moyle Interconnector will also have greater operational flexibility.

Paddy Larkin, Mutual Energy CEO, singled out the Moyle Interconnector as a “vital energy asset” for supply security in the region. “The new system will allow us to adapt to evolving security standards and changing grid conditions – best serving the needs of our customers and Northern Ireland’s energy requirements.

“It was crucial for us to ensure downtime during works was minimized so as to not impact operations,” he stressed adding “we’re pleased to have a partner that can honour that requirement.”

The ADB’s self-imposed ‘Strategy 2030’ calls for climate finance from the bank’s own resources to reach $80 billion between now and 2030. It also committed to focus at least 75% of its operations to support climate change mitigation.

Over the past three years, however, the bank has heavily invested in fossil gas and related infrastructure across Asia and is now facing the reality of stalled construction in several places and rising environmental costs.

Critics call for policy shift

A network of over 250 civil society organizations across Asia have used the occasion of the Asia Clean Energy Forum (ACEF) 2020, organised this week as a virtual conference from Manila, to call on the bank to “make an immediate shift towards renewable energy pathways for a Paris Aligned COVID-19 recovery.”

The future of ADB Energy investments should be in renewable energy and community microgrids, they say with “no space for fossil fuels especially coal.”

Independent data suggests renewable energy will create more jobs and is cheaper to produce. “The age of fossil fuel baseload power generation has come to an end,” critics underlined urging the ADB to “take action to align its investment policies with the 1.5 degree target of the Paris Agreement.”

Established in 1966, the Asian Development Bank is owned by 68 members, with 49 originating from the region. ADB President Takehiko Nakao underlined that in addition to clean energy targets, “a sustainable and secure energy supply remains essential as more than 350 million people still lack access to electricity in our developing member countries.”

Raising funds through USAID and KfW

To raise more investment for energy projects in Asia and the Pacific, the ADB has entered partnerships with both the United States Agency for International Development (USAID) and the German Kreditanstalt für Wiederaufbau (KfW).

Under the USAID partnership, the bank seeks to mobilize $7 billion worth of investment designated to boost clean power gen capacity by 6 Gigawatts (GW) and increase regional energy trade by 10% over the next five years.

KfW and ADB some month ago agreed to expand their co-financing partnership in Asia-Pacific with an additional $2 billion over the next 4 years. The funds are meant to be used to promote sustainable economic development, a cleaner environment, and renewable energy.

The additional funds from Germany will build on a $2 billion co-financing partnership, launched in 2014, and renewed in 2017 for an additional $2 billion. This partnership yielded 14 projects focused on education, energy, health, industry and trade, and public sector management. The $4 billion provided by KfW for these projects was complemented with $5.8 billion from ADB.

The Floating Data Centre Park, under development by Keppel and Royal Vopak, is designed to assess the commercial viability of establishing LNG and possibly hydrogen infrastructure for power plants. The huge data centre will be situated at the 32 hectares offshore supply base at Loyang, Singapore.

Aspiring to partly fuel the data centre by hydrogen, MHI and Keppel are exploring the onsite production of hydrogen through the process of steam methane reforming (SMR), and the subsequent use of the fuel in trigeneration generator sets.  

As combustion fuel, hydrogen has clear advantages over fossil fuels given that it produces no emissions when burnt. A tri-generation plant produces heat, power and cooling, so the supported data centre can not only reduce its reliance on the grid but also use the chilled water produced by the plant to cool the data centre's computer systems.

Producing hydrogen through SMR

As part of the cooperation, Keppel and MHI will also export producing hydrogen through the steam methane reforming (SMR) process.

Methane hereby reacts with steam under 3-25 bar pressure in the presence of a catalyst to produce hydrogen, carbon monoxide, and a small amount of carbon dioxide. The process is endothermic, so heat needs to be supplied externally to get the chemical reaction going.

Keppel CEO Wong Wai Meng underlined company’s commitment to adopt sustainable energy solutions. “The exploration of hydrogen infrastructure is part of our strategy to work towards decarbonisation,” he said, adding “We’re happy to collaborate with Mitsubishi Heavy Industries and tap on their vast experience and technology capabilities in our journey.”

MHI-AP chief regional officer Yoshiyuki Hanasawa underlined Mitsubishi’s long-term expertise in hydrogen and the company’s “focus on providing reliable and innovative cross-industry solutions aimed at ensuring a smooth energy transition.”

Following the acquisition on January 15, Rolls-Royce renamed Qinous as Rolls-Royce Solutions Berlin and is now investing to expand the business into a Microgrid Competence Center. The move is a sign of the growing importance of distributed energy systems in Rolls-Royce’s future product portfolio.

Made-to-measure microgrids

The offering of the Berlin microgrid specialist ranges from simple storage solutions to complex microgrids that combine battery storage with wind or solar PV units as well as with diesel or gas gensets. It includes energy supply systems that are either grid-connected or are fully independent.

Given that Rolls-Royce itself produces key components like battery storage, microgrid control systems and generator sets, the integration of Qinous’ know-how allows offering the customers a turnkey solution for microgrids. The expanded Quinos business unit hereby is “not merely a supplier of modules from the MTU product range,” Andreas Görtz, VP of the Power Generation business unit pointed out.

“We're giving the customer a turnkey total solution that is integrated perfectly from both a technical and economic perspective,” said Cordelia Thielitz, who heads up the Microgrid Solutions business unit at Rolls-Royce.

Tapping new income streams

In Germany and the U.S., microgrid solutions are particularly attractive for industrial applications due to their potential to reduce emissions while guaranteeing a stable energy supply. Moreover, micogrids can open up new income streams for power plant operators.

Used as self-sufficient, distributed power grids, these power systems enable remote mines or villages, without public grid access, to cover their electricity needs in an economical and more sustainable way.

Boosting the supply of batteries

Rolls-Royce is also growing its range of battery storage systems which will be produced at its Bavarian facility in Ruhstorf. The storage solutions are rated from 40 kVA to 2,000 kVA, and have capacities ranging between 50 kWh and 2,600 kWh.

The MTU-branded battery products are available as 20-foot and 40-foot containers, or compact versions. The scalable units can be adapted flexibly to meet customers’ performance needs. Battery storage is a core component of microgrids, and is also used as integral equipment in solar parks for ensuring grid stabilization, or as charging infrastructure for electric vehicles.

Mazar-e-Sharif’s electricity supply currently hinges largely on hydropower and the Northern Fertilizer and Power Plant (48 MW, pictured). Hence the new Ghazanfar Group’s IPP project is urgently needed to avert power shortages. All electricity produced by the 59 MW gas IPP will be bought by the Afghan utility DABS.

Developed as a greenfield plant, the IPP will be fuelled by natural gas sourced from the Sheberghan fields. The developers expect to generate around 400 GWh of electricity annually for the residents of Mazar-e-Sharif, Kabul, and Jalalabad.

Afghanistan's first IPP

The Mazar-e-Sharif gas power plant is Afghanistan’s first long-term public-private partnership, financed through a $21.2 million senior loan of the International Financial Corporation (IFC) and $1.5 million of client risk-management swap.

In addition, the IFC mobilised $41.2 million in parallel loans from other lenders, including the Germany’s DEG and the Asian Development Bank (ADB). The financing package also includes a $12 million guarantee from World Bank affiliate IDA, designed to give developers short-term liquidity for payment obligations to the Afghan utility and power offtake DABS.

Nena Stoiljkovic, the IFC’s vice president for Asia and Pacific, said “the project sends a clear signal to the world that internationally bankable deals with the private sector are possible in Afghanistan.

Once onstream, the 50 MW cryogenic energy storage will be one of Europe’s largest battery storage systems and help achieve the UK’s net-zero carbon goals.

“This new cryogenic energy storage plant will deliver much needed long-duration energy storage and provide valuable services to the National Grid,“ said Javier Cavada, Highview Power CEO.

In-operation date in 2022

Highview has teamed up with the UK independent developer Carlton Power to build and operate the energy storage facility at Trafford Energy Park, just outside of Manchester. Situated in Carrington Village, it will be one of Europe’s largest battery storage systems.

Construction of f the CRYOBattery facility at Trafford Park is expected to start later this year and enter commercial operation in 2022.

It will use existing substation and transmission infrastructure, with its income derived from several markets, including arbitrage, grid balancing, and ancillary services such as frequency response and voltage support.

Cheap, large and long-duration storage technology

In terms of technology Highview cryogenic energy storage systems use liquid air as the storage medium which allows them to store large quantities of energy for a long-duration. The facilities can offer multiple gigawatt-hours of storage. That represents weeks’ worth of storage, not just hours or days.

“At giga-scale, CRYOBatteries paired with renewables are equivalent in performance to – and could replace – thermal and nuclear baseload power in addition to supporting electricity transmission and distribution systems while providing additional security of supply,” Highview stated.

At approximately £110/MWh for a 10-hour, 200 MW / 2 GWh system, the CRYOBattery is said to offers a “competitive levelised cost of storage for large-scale applications.”

Aiming for 1 GWh storage capacity in the UK

Carlton Power has developed more than 5 GW of generation projects (CCGTs, OCGTS, and solar) across the UK and Europe with more than 2.5GW already in commercial operation.

In the UK, Highview and Carlton Power plant to co-develop up to four additional CRYOBattery projects with a combined capacity of over 1 GWh.

Spot prices at the NOVA/AECO-C (AECO) trading hub used to be between $1 per million British thermal units (MMBtu) and $2/MMBtu below Henry Hub spot prices from mid-2017 until late 2019. However, from October 2019 through March 2020, there was little difference in spot prices at those two points.

Canadian gas put into storage

In April and May - at the height of the coronavirus lockdowns - AECO natural gas spot prices increased while Henry Hub gas prices plunged.

The narrowing of AECO and Henry Hub prices was first noticeable when the Canadian in September last year, when the Canadian Energy Regulator approved a temporary service protocol (TSP) for the NOVA pipeline system. The TSP increases service flexibility on the pipeline by handling gas flows to storage facilities at times when the system is constrained.

In March and April 2020, Alberta’s natural gas inventories were at multiyear lows of slightly more than 300 billion cubic feet. Hence, most production from Western Canada was put into storage and not exported to the United States.

Imports not seen to recover before 2021

Imports of Canadian gas at the border crossing in Montana and North Dakota were 0.4 Bcf/d and 0.3 Bcf/d less in January through May 2020, compared with the first five months last year, U.S. Government data shows.

Gross imports of Canadian pipeline gas are expected to fall from 7.4 Bcf/d in 2019 to 7.0 Bcf/d in 2020 - the lowest level since the mid-1990s. Demand for Canadian gas is forecast to start recovering with the upcoming winter season and could reach an estimated 7.9 Bcf/d in 2021.

BNP Paribas acted as the structuring bank, bookrunner, mandated lead arranger (MLA) and lender for both credit facilities. Euler Hermes was joined by HSBC Bank as bookrunner for the agent of the SACE export credit and by and by Natwest as bookrunner and MLA for the Euler Hermes export credit.

In-service date in late 2023

Viking Link – the UK’s first subsea power cable to Denmark – will stretch over 474 miles from the Lincolnshire coast to Revsing on the Danish west coast. It is being built by a joint venture between National Grid and the Danish TSO Energinet.

The interconnector will be formed by two parallel HVDC (High Voltage Direct Current) cables, manufactured and installed by Prysmian Powerlink and NKT HV Cables. The former will deliver four of the five cable lots, while NKT will supply the onshore cable lot in Denmark. Siemens, meanwhile, will supply and install equipment for two converter station in Lincolnshire and Revsing.

Due completed before the end of 2023, the interconnector is meant to 1400 MW cable will supply renewable energy (mostly wind power) to 1.4 million households in Britain.

Britain’s 6th interconnector to Europe

For Britain, Viking Link will be the sixth interconnector to Europe. National Grid already has three operational interconnectors to France (IFA), the Netherlands (BritNed) and Belgium (Nemo Link). Two further projects are under construction to France (IFA2, operational 2020) and Norway (North Sea Link, operational 2021).

Following the completion of Viking Link, National Grid will have 7.8 GW of interconnector capacity – enough to power 8 million homes. The TSO aspires to source 90% of its electricity imports from ‘zero carbon sources’ by 2030.

“Britain’s energy system is in the midst of a rapid and complex transformation. We know we have a critical role in the acceleration towards a cleaner future,” Katerina Tsirimpa, Head of Corporate Finance for National Grid commented. “This green loan represents an important contribution towards our net zero commitment.”

Natural gas is the largest source of electricity in most advanced economies but also used to be one of the most expensive options to generate peakload power. Hence, higher output from hydro or nuclear used to mainly reduce the amount of dispatched gas-fired generation.

In 2019, coal was still the largest source of electricity at 36%, IEA figures show, followed by natural gas at 23%. However, analysts stressed both gas- and coal-fired generation are set to fall in 2020, largely due to a sharp reducing in global electricity demand due to lockdowns in April, May and parts of June to contain the outbreak of the coronavirus.

Lockdowns slash NYC’s energy use

In New York, one of the cities most affected by the virus, the lockdowns slashed daily electricity demand on weekdays between 11% and 14% in March and April, according to government figures. Downtown New York, the NYISO Zone J, was hardest hit with demand up to 16% lower than temperature-comparable historical demand.

Downtown New York, the NYISO Zone J, normally consumes about one-third of total NYISO supply but business closures curtailed daily weekday electricity demand by 16%, compared to normal levels.

The NYISO grid operator said “the reduction in electric demand from commercial customers is a leading driver of overall reduced electricity consumption.” More than half of New York State’s electricity sales go to commercial end-users, a percentage only exceeded by the District of Columbia (72%) which includes Washington DC.

Coal power feels the pinch in India

In India, nationwide lockdowns have rendered coal-fired power plants uncompetitive compared with gas or renewables. In the first 33 days of the 2020/21 fiscal year, coal-fired generation was down just shy of 30 Terawatt-hours (TWh).

Coal-fired generation has borne the brunt of the Covid-19 power demand loss, running at half the capacity rate assumed in the Indian Central Electricity Authority’s modelling guidelines used to evaluate the financial and operating performance of new coal-fired power plants.

Fuel pricing trends for new power projects clearly favour renewable energy over coal, particularly when it comes to expensive non-mine mouth or import coal-fired power proposals. Investors, including India’s domestic banks, are increasingly reluctant to provide financing for coal power projects, given the very cost-competitive low-carbon alternatives.

A landmark 2GW solar tender awarded by NHPC in April 2020 priced at a near record low of Rs2.55/kWh, fixed flat for 25 years.

Siemens claims the SeaFloat barge-mounted power plant will supply the Dominican Republic with electricity at a lower cost than a land-based fossil power plant. Installed on behalf Seaboard, an independent power producer (IPP), Estrella del Mar III will be moored offshore Santo Domingo.

Cheaper than land-based plant

Once operational in spring 2021, the floating power plant will provide the Dominican Republic with “a quality proven power plant at a lower cost in comparison to a similar land-based power plant,” the project partners stressed.

Due to site constraints with limited free land, the customer selected a SCC-800 2x1 SeaFloat concept with two Siemens SGT-800 gas turbines and one SST-600 steam turbine. The turbine gensets are of single lift package design for floating applications, utilizing a frame-based design with a three-point mount. “This allows increasing the plant size in comparison to a land-based power plant,” Siemens underlined.

Turnkey ‘plug and play’ concept

Siemens will realize the project under a turnkey ‘plug and play’ concept, whereby the German OEM will design and build the 145 MW combined-cycle power plant.

Singapore-based ST Engineering.will be responsible for the engineering design, procurement and construction (EPC) of the floating power barge, the balance of plant and the installation works.

Fluence Energy, a JV company of Siemens and AES, will provide a 5MW/10 MWh battery that will be integrated in the power plant for frequency regulation control, allowing it to operate at full capacity with highest fuel efficiency.

Variations of the SeaFloat concept

Siemens SeaFloat power plants are adaptable for various needs. While most market requests are for the SGT-800 gas turbine, further solutions are available based on the based on the SGT-A65 and SGT-8000H series.

Mobility is one of the strength the floating power barge. SeaFloat power plants can be moved to any site that is accessible by sea or major rivers and require almost no investment for land acquisition. Short lead times can be achieved given that the plants are largely built from standardized equipment in leading shipyards.

Typical applications for this concept are power supply for island nations or industrial areas on shorelines or major rivers as well as brownfield sites.

Myanmar used to rely on hydropower to cover most of its electricity demand, supplemented by low efficiency open-cycle gas power plants that operated mostly during the dry season (November - May). In recent years Myanmar suffered repeated power shortages due to rising electricity demand, hence it resorted to building some integrated LNG-to-Power plants as the fastest way to boost generating capacity and meet demand.

Work underway for two new FSUs

Yangon LNG, Myanmar’s first LNG import facility includes a Floating Storage Unit (FSU) where to store imported LNG before it gets transferred onshore and regasified for use as a fuel for power generation. Due to the shallow depth on the Yangon River, the FSU can only accommodate small-scale LNG vessels.

Mid-scale vessels can currently use a temporary jetty at Thilawa port. A permanent jetty is expected to be in service in July 2020 and will accommodate regular-size FSU vessel with a capacity of 2.8 Bcf. 

In addition, the Myanmar government is supporting plans to build a second FSU associated power plant (1,230 MW) at the mouth of the Yangon River, near Kanbauk. The project is at a development stage and due operational by 2024. A small-scale LNG vessel is meant to shuttle LNG between the two FSUs at Kanbauk and Thilawa.

Two power plants to start up this summer, third in 2024

LNG imported at the older Yangon regas facility will supply integrated LNG-to-power projects nearby – the 400 MW Thaketa power plant, the 350 MW Thanlyin plant and the 1,250 MW Thilawa. Both the Thaketa and Thanlyin plants are expected to enter service this summer.

The larger Thilawa combined-cycle gas power plant is the planning stage and scheduled to start operations in 2024.

If the three plants run at a 45%–55% annual capacity factor, they will require between 160 million cubic feet per day (MMcf/d) and 200 MMcf/d of natural gas supply, an equivalent of 21 to 26 LNG cargoes per year (assuming LNG vessels of 2.8 Bcf capacity), averaging about two cargoes per month.

Plans for further integrated LNG-to-Power projects

Several other LNG import facilities and accompanying gas-fired power plants are currently being developed in Myanmar, though development of some projects is slow.

In the southwest, the Rakhine LNG import facility is currently under construction. It will supply the Kyaukpyu natural gas-fired power plant (150 MW capacity) due operational by the end of 2020.

The Mee Laung Gyaing LNG import terminal and a 1,390 MW gas-fired power plant are proposed in the Ayeyawady region. The project will utilize a Floating Storage and Regasification Unit (FSRU) and is expected to come online by 2024.

The new site in Hamakawasaki, just outside Kawasaki City, will be equipped with Toshiba’s advanced fuel cell production technology which helps streamline processes and reduce production costs.

Tenfold rise in production capacity

The new research and manufacturing facility at Hamakawasaki can scale up to approximately ten times the current production capacity, subject to product demand. Hydrogen, supplied at low cost via pipeline from a nearby electrolyzer, will be used for inspections and experiments related to fuel cell production.

Toshiba’s latest H2Rex technology is a clean generator that emits only water. The pure hydrogen fuel cell system has been developed from decades of research dating back to the 1960s.

Fuel cells generate electricity through electrochemical reactions between the stored hydrogen and atmospheric oxygen. Fuel Cell Stacks are comprised of multiple unit cells which are composed of positive electrode, negative electrode, and electrolytes in-between both types of electrodes.

Over 120 H2Rex units sold

Toshiba ESS has already sold and delivered over 120 units ‘H2Rex’ pure hydrogen fuel cell systems. Customers are wholesale food markets, hotels, convenience stores, and sports facilities.

In China, Toshiba has entered a partnership to develop fuel cell system and stacks with a local startup called More Hydrogen Energy Technology Co.“We are working towards expansion of our cell stack technology in the Chinese market,” said Yoshihisa Sanagi, General Manager of the Hydrogen Energy Business Division at Toshiba ESS.

By deploying hydrogen energy technology at scale, Toshiba seeks to “contribute to the growth and maturation of renewable energy sources worldwide,” he concluded.

The initial schedule was for 35 days but was extended to 69 days due to the customer’s expanded work scope and the 14-day quarantine before the project started. Engineers from GE and FieldCore implemented safety measures to ensure the steady operation of the plant outage. They managed to deliver the project more than one day ahead of schedule.

On-site engineers actively quarantined

The COVID-19 outbreak brought “unexpected and unprecedented difficulties” for the inspection project, Xu Yong, General Manager at Shenzhen Baochang Power Plant Co., said, stressing GE’s ability to do it safely and in a timely manner was critical to the success of the project.

“During the most severe period of the pandemic, our 21 on-site engineers volunteered to go to the site and actively quarantine while solving logistical problems and guaranteeing the end result,” said Xu Xin, China OTR leader, GE Gas Power.

The upgrade was important to ensure the Baochang Power Plant was back up and running “as quickly as possible,” he stressed and “the collaboration with Shenzhen Baochang was crucial to monitor and cope with the fast-moving situation”

Most complex overhaul of 9E turbine

The latest modernization project was complex and involved a lot of lifting work, with works focused on replacing the aging parts of the two turbine units.

According to GE, it was “the most complete inspection of the gas turbine, through overhaul and necessary replacement for all detachable parts.” These made up more than 300 items, including the large axial, rotor, hot gas path, compressor, combustion and the turbine’s air inlet system.

In Shenzhen, Guangdong Province, GE has the largest installed base for the 9E gas turbine in China. In April 2019, GE announced that it had successfully completed the world’s first installation of its DLN1.0+ with Ultra Low NOx combustion upgrade on nine GE 9E gas turbines at five power generation enterprises to help improve air quality and public health throughout China by reducing nitrogen oxide (NOx) emissions.