Low demand, combined with abundant supply from wind and solar power sources, has pushed most thermal coal power plants out of the merit order, as they have become unprofitable to operate. Gas generators bear the brunt of pressure from lower demand and upswings in renewable production - although this pressure has been somewhat mitigated by reduced output from nuclear in France and Great Britain.

Relatively high-cost thermal generation continues to run in periods of high renewable supply, suggesting the thermal fleet lacks the necessary flexibility or sees insufficient commercial incentive to respond. Other must-run restrictions may also have a bearing, analysts noted, stressing hydro and cross-border flows are a key provider of flexibility.

Negative power prices

On May 1, a public holiday in Europe except for the UK, strong renewable supply coincided with low demand which led to <1 EUR/MWh power prices across major markets. Germany, in particular, continues to see negative day-ahead prices with 179 such hours in the year-to-date. By comparison, the whole of 2019 saw 212 negative hours, according to WoodMac figures.

Risks monitored by Wood Mackenzie are the impact of low demand and ocassionally negative prices on commercial frameworks, notable for renewable support mechanism. This trend will impact UK’s Renewables Obligation markets, resulting in lower ROC prices. At the same time, it will raise levy rates faced by German consumers under EEG arrangements as renewables power is now sold under lower Feed-in Tariffs which get balance by higher levy charges.

Economics favour gas

The relative economics of gas and coal generators continue to hold firm in favour of gas. Clean sparks spreads, the profit margin for burning gas to generate electricity, remain some 11 to 14 EUR/MWh more attractive than low efficiency dark spreads (in markets paying ETS prices alone) and around 5 to 9 EUR/MWh ahead of even the most efficient hard coal burners in the fleet.

Great Britain has recorded 31 days of coal-free generation – a new record. It is questionable, however, if support for an accelerated Green Deal be fiscally feasible given tightened government budgets following lost tax revenues and bailouts of sectors deeply impacted by the recent lockdowns.

In the Appalachian region, low natural gas prices are discouraging producers from engaging in natural gas-directed drilling, and in the Permian region, low oil prices reduce associated gas output from oil-directed wells. In 2021, forecast dry natural gas production averages 84.9 Bcf/d, rising in the second half of 2021 in response to higher prices.

Overall U.S. dry gas production reaches a record of 92.2 Bcf/d in last year, but is forecast to plunge to 89.8 Bcf/d in 2020 due to low oil prices, with monthly production falling from an estimated 93.1 Bcf/d in April to 85.4 Bcf/d in December.

On the demand side, the EIA expects total gas consumption will average 81.7 billion cubic feet per day (Bcf/d) in 2020, down 3.9% from the 2019 average primarily because lower lower manufacturing activity due to the coronavirus outbreak.

LNG will are forecast to average 5.8 Bcf/d in the second quarter and 4.8 Bcf/d in the third quarter of 2020. U.S. gas exports are declining through the end of the summer in reaction to lower global demand, with some LNG buyers having deferred or cancelled cargoes.

Heightened uncertainty

The EIA stressed its Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because the effects on energy markets of mitigation efforts related to the COVID-19 outbreak are still evolving. Lockdowns to contain the spread of the pandemic caused significant changes in energy supply and demand patterns.

Crude oil prices, in particular, have fallen significantly since the beginning of 2020, after demand fell off a cliff when most countries went on lockdown during March and April. Brent crude oil traded as low as $18 per barrel in April, down from an average of $64/b in 2019.

Analysts at the EIA said prices are likely to recover to an average $23/bbl during the second quarter of 2020, before increasing to $32/bbl during the second half of the year. Global oil inventories fill up fast which puts upward pressure on prices, but much depends on whether reduced travel and fuel use will persist as some restrictions related Covid-19 remain in place.

The TTF near-curve market, notably contract for Jun-20, Jul-20, Aug-20 and Sep-20, have held below prices at the U.S. Henry Hub plus 15% – the value of LNG for long-term offtakers from Cheniere facilities on an FOB basis. “European gas prices do not cover the logistic costs for shipping an U.S. LNG cargo to Europe,” analysts noted, expecting “further cargo cancellations.”

With European economies falling into recession, energy demand will remain subdued even though lockdowns are gradually lifted. France allowed some retail businesses to reopen on May 11 and Italy began to reopen its industries already on April 27. Similarly, Germany, Denmark, Norway, Switzerland and Austria all started partially reopening business in the second half of April.

Demand subdued as recession looms

“The easing of lockdowns helps with a gradual recovery of gas demand but residential social distancing measure stay in place,” analysts commented, anticipating that European industries and businesses will recover slowly to pre-crisis levels.

The year-on-year demand destruction across much of western Europe, when adjusting for heating demand, on 15 March–15 April averaged 32% for power, 17% for industrial gas and 9% for residential use, according to Energy Aspects figures.

“There is some scope for the TTF Q3-20 to drop further to send additional signals to reduce US imports,” analysts noted, pointing to limited demand from storage. After record injection rates in April, most underground storage facilities in Europe are filling up fast.

Storage to be filled by August

Modelling by Energy Aspects has facilities in Northwest Europe completely filling by August. Injections will slow as site pressures build, and Europe’s storage operators say that aggregate injection capacity falls to around 63% when stocks hit 90% of capacity.

The demand reduction has resulted in Europe struggling to absorb LNG supply, which has caused congestion at European terminals. Kpler cargo-tracking data indicated 17 vessels as floating storage on 5 May, of which 10 were positioned around Europe or off Africa’s western coast, with most having loaded from Nigeria’s 22 mtpa Bonny facility.

The floating storage has been mostly associated with deliveries targeting the UK, Spain and France’s 7.2 mtpa Montoir terminals in recent weeks. Energy Aspects says there will likely be “at least some EU unloading congestion in April–May after Northeast Asia markets crashed earlier this year on COVID-19–linked market weakness.”

Spending on low-carbon technologies has increased substantially in recent years to reach $19.7 billion and 94% of total budget. In the United States, budget into low-carbon RD&D were boosted by an additional $479 million; while Norway freed up $242 million for a large-scale wind demonstration project.

Spending on hydrogen and fuel cells kept their share at 3% in overall budgets since 2012, but their share is likely to increase as many government are about to launch “"green stimulus" programmes to restart their national economies after the coronavirus crisis.

The U.S. Department of Energy (DOE) hydrogen production is a critical component of the H2@Scale initiative, backed by $64 million in government funding. The investment supports transformational research and development of hydrogen concepts that will increase the scale of hydrogen production, storage, transport, and use. In August 2019, the DOE freed up $40 million funding for 29 dedicated projects on hydrogen production and utilization, including grid resiliency.

In Japan, the ministry of economics, trade and industry (METI) announced earlier it will spend at least 108 billion yen ($975 million) on hydrogen projects over a two-year period ending March 2020. In a renewed roadmap, METI defines new target on three basis technology and seeks to establish a breakdown of costs. Industries and researchers are convened on a regular basis to review their progress in each area stipulated by the roadmap.

In contrast, Germany has not yet adopted any clear hydrogen which had originally been expected a year ago. Ministries have in recent weeks come significantly closer to reaching an agreement, but the government has been slow to act as it seeks to integrate financing on hydrogen into a national “green stimulus” program.

“The goal of the federal government is to use green hydrogen, [produced from renewable electricity through water electrolysis] to support a rapid market ramp-up for it and to establish corresponding value chains”, the draft law reads.

The Social Democrats (SPD), in coalition with Chancellor Angela Merkel’s conservative CDU party, have set out plans for for Germany to increase green hydrogen production capacity to at least 10,000 MW by 2030. Added to this are hydrogen imports sourced on designated European market, where the SPD supports incentives for large-scale projects of more than 100 MW.

Promising technology, job machine

Green hydrogen is increasingly seen as silver bullet to decarbonize Europe’s heavy industry and aviation. The Germany government is also seeing hydrogen as a promising growth market for much of the country’s engineering-focused industry.

Merkel has voiced the hope that Germany could create hundreds of thousands of jobs by the middle of the century if it can hold onto its current share of the global market for electrolysers that produce hydrogen, which stands at around 20%. The National Hydrogen Strategy is expected to become part of a "green stimulus" programme to restart the economy after the coronavirus crisis.

Germany has pledged to become carbon-neutral by 2050 and to reach this goal hydrogen could gradually replace natural gas in the power sector. However, to produce the necessary volumes of green hydrogen, technology costs for both renewables and electrolyzes would have to fall substantially.

The German industry said to become carbon-neutral it would need to invest of around 45 billion Euros in new infrastructure and processes. In addition, it would need more than 600 TWh of electricity per year from the mid-2030s – more than Germany's entire current power production – mainly to produce hydrogen and other renewable fuels.

Aiming for 80 GW hydrogen capacity

A hydrogen road map by the research institute Fraunhofer ISE expects a production capacity of 50 to 80 GW in Germany alone by 2050. To reach these volumes, annual growth rates in the double-digit megawatt range must be achieved immediately, and in the 1 GW range by the end of the 2020s, researchers pointed out.

Manufacturers of electrolysis and fuel cells could earn an estimated additional 32 billion Euros, researcher suggest, provided the global installed electrolysis capacity will reach 3,000 GW or more by 2050.

“Despite the sudden fall in commodity prices as a result of the [Covid-19] crisis, our trading activities posted an extremely satisfactory result,” RWE CEO Markus Krebber said, noting a “strong trading performance” and a “good result for gas and LNG”.

Putting on a brave face, he pointed at RWE’s “robust business model” which helped the overall group achieve “significant gains across all key earnings figures even in these challenging times.” RWE Group achieved €1.3 billion in adjusted EBITDA (earnings before interest, taxes, depreciation and amortisation) in the first quarter of 2020, an increase of about 19% compared with €1.1 billion for last year’s corresponding period. Adjusted net income totalled €603 million.

Net debt rose by €1.7 billion to €8.7 billion largely due to timing effects of hedging transaction. Payments for collateral owing to the drop in commodity prices also resulted in “substantial cash outflows,” RWE said. Looking ahead, the Essen-based utility confirmed its 2020 outlook with adjusted EBITDA expected between €1.2 billion and €1.5 billion.

Higher generation earnings

Optimised power plant dispatch helped RWE achieve a strong gain in its Gas/Biomass/Hydro segment despite a volatile market environment.

The reinstating of the UK capacity market, where payments were suspended due to a review by European institutions, swept some €42 million in capacity payment into RWE’s coffers in the same quarter. The company hopes to achieve up to €650 million in earnings in its generation segment for the full year.

Strong spending in wind and solar

The Essen-based utility, formerly known for its focus on coal-fired power generation, is reinventing itself and aspires to become one of the world's leading renewable power providers and become carbon neutral by 2040.

Venturing into green energy, RWE committed to invest €5 billion in some 4GW of new wind and solar power capacity to grow the portfolio to over 13 gigawatts (GW) by 2022. Construction of the Triton Knoll offshore wind farm in the UK has been underway since January, and FID for the German North Sea project Kaskasi was reached in April.

Much wind and sunshine in the first quarter as well as the commissioning of new capacity made adjusted EBITDA in this segment jump 20% to €209 million in the first quarter. RWE expects to reap earnings of €500 million to €600 million for this segment in the year underway.

Resolute coal exit

To achieve its goal of being carbon neutral by 2040, RWE stressed it is “resolutely and responsibly phasing out electricity generation from coal.”

In the UK, it already shut down its last coal fired plant and the first closure of a coal power block in Germany is scheduled for December. After months of debate and lobbying, the parliamentary procedure regarding Germany's coal exit is now meant to be completed before the summer.

Designed for variable power generation, Wärtsilä 31SG gas-drive system can be synchronised to the power grid within 30 seconds, and reach full load within 120 seconds. The new plant will allow swb Bremen react quickly to balance the rising volumes o of volatile power from renewable sources with no risk of downtime.

Start-up scheduled for 2023

The 105 MW gas drive power plant is meant to be completed within the next two-and-a-half years, replacing a 119 MW hard coal unit (Block 15) at Bremen Hastedt. The municipal utility still operates a 303 MW hard coal unit (Block 6) at the city’s nearby port.

"With the decision to replace the hard coal-fired combined-cycle block Hastedt 15 with a highly efficient combined-cycle unit with nine natural gas-powered engines, we have achieved the optimum combination of climate protection, availability and cost-effectiveness,” said SWB managing director generation, Jens-Uwe Freiag.

The engineering division at Uniper will serve as general contractor in overseeing all aspects of the project, while Wärtsilä will supply the technical components and carry out repair and maintenance of the plant to ensure a guaranteed output.

Consortium eyes further projects

The gas-drive power plant in Bremen is the first project in the Uniper/Wärtsilä partnership for cogeneration in Germany. “The conversion from coal-to-gas will allow SWB decrease CO2 emissions by up to 75%,” Uniper stated. Going forward, the two companies aim to pursue other joint projects of this kind.

With about 34 GW of installed generation capacity, Düsseldorf-based Uniper is among the largest global power generators. It is also manages a diversified gas portfolio, with 220 Bcm of natural gas sold last year to customers throughout Europe.

Helsinki-listed Wärtsilä focuses on smart technologies and complete lifecycle solutions both for marine and energy markets. Its technical focus lies on total plant efficiency and data analytics.

The chairman of the Federal Reserve, Jerome Powell, has warned the coronavirus crisis could lead to a prolonged recession if not more fiscal stimulus measures are put in place swiftly.

Unprecedented downturn

“The scope and speed of this downturn are without modern precedent, [and] the job gains of the past decade have been erased,” Powell said, indicating that more than 20 million American people have lost their jobs since the start of the pandemic two month ago.

The FED chair underlined the current downturn is solely attributable to the virus and the steps taken to limit its fallout. To date, Congress has provided roughly $2.9 trillion in fiscal support for households, businesses, health-care providers, and state and local governments—about 14% of GDP.

Travel restrictions and business lockdowns not only brought the U.S. economy to a near-halt in April but also caused a substantial drop in emissions. However, even before the effects of coronavirus crisis became apparent in mid-March, the U.S. government had expected a decline in energy-related emissions which kept falling from their 2007 peak.  

Clean air thanks to lockdowns

Stay-at-home orders, travel restrictions, and work-from-home arrangements reduced demand for motor gasoline, diesel and jet fuel. Petroleum is the largest source of emission in the United States, accounting for 46% of the 2019 total, according to the U.S. Energy Administration (EIA).

Natural gas-related emissions, accounted for a third of last years’ total. Compared with petroleum and coal, EIA expects a relatively smaller decline in natural gas consumption and its related CO2 emissions (both 4% lower) in 2020.

Power generation consumes the largest volumes of gas, and although electricity output is forecast to fall 5% this year due to the recession, the EIA expects only a 1% decline in gas-burn due to relatively low natural gas prices compared to thermal coal. The closing or reduced operation of many nonessential businesses, combined with generally warmer weather this year, will likely lead to a falling gas use by the commercial sector.

Come 2021, the EIA sees energy-related CO2 will increase 5% – a proportionally smaller rise than the forecast 6% GDP growth as businesses, industries, and institutions resume normal operation.

Higher domestic gas prices increase the prospects of Bangladesh to secure spot LNG cargoes in the second half of this year. Wood Mackenzie expects the gas demand to peak this year to 27 million tons of oil equivalent (mtoe).

Two thirds of power generation in Bangladesh currently comes from domestic gas supply, which is depleting. To meet this gap, additional volumes will be needed as early as 2022.

Growing working age population, urbanisation and rising income levels in Bangladesh have pushed up energy demand, with electricity consumption growing 6% annually in the last decade – higher than average GDP. This trend is likely to continue due to the current low per-capita electricity use.

LNG for baseload power

Bangladesh needs a reliable base load capacity for its electrification needs, given that the country’s overall energy demand is expected to rise 27% to reach 55 mtoe in the years through to 2030.

“Coal and LNG imports are thus important to support this as domestic coal struggles with the economics of quality production, while domestic gas is on a steep decline,” said Wood Mackenzie Asia Pacific Head of Markets and Transitions, Prakash Sharma.

“LNG and coal,” in his view, “account for most of the incremental fossil fuel imports between 2020 and 2030.”

Coal use to rise fourfold

Dirty king coal, meanwhile, will see demand rise fourfold to 12 mtoe between 2020 and 2030, according to Wood Mac estimates.

The Bangladeshi government is adding import-based coal capacity to lower power generation cost and increase reliability. The imported thermal coal will mostly originate from Indonesia and Australia.

While the renewables target of 10% of total electricity generation by 2020 “will not be met,” Sharma acknowledges the government’s recently launched Green Transmission Fund “should provide some upside to investments in the renewables sector.” Wind and solar power will make up just 2% of total electricity generation this year, growing to 6% by 2030 and 16% by 2040.

The Thurcroft battery will be monitored remotely from Flexitiricity’s control room and dispatched dynamically both in the UK wholesale markets and in line with National Grid’s balancing mechanism. Hereby, the battery is also capable of providing frequency response services to help regulate the UK electricity system frequency in face of higher renewable energy supply, and keep it within safe operating levels.

As one of Europe’s largest batteries, the Thurcroft lithium-ion battery adds to the 1 GW energy storage capacity installed in the UK and will help National Grid ESO balance electricity demand with rising volumes of flexible supply from weather-dependent wind and solar power source.  

For Flexitricity, the order win to grid-optimize Thurcroft comes on the heels of a similar contract with the Gresham House Fund for their Noriker Staunch energy project.

“Gresham House has plans to grow its energy storage portfolio significantly. We are aiming for more than 360 MW in operational assets by the end of 2020,” said managing director, Ben Guest. Great Britain, in his view, requires at least 10 GW of additional energy storage capacity in the next four years to enable the transition to a renewables-led electricity market. “The UK has an ambition to achieve net zero by 2050 and it is our aim to contribute to this meaningfully, while achieving strong returns for our investors,” he stressed.

Flexitricity, part of the Swiss energy service provider Alpiq Group, has created and now operates the largest demand-response portfolio in Britain. Over the past ten years, the Edinburg-based company has combined several grid-scale and behind-the-meter battery storage projects to a virtual power plant. On April 23, 2020, the company completed the first ever trade in the UK balancing mechanism with its virtual battery storage system, a milestone for the industry.

More than half of the respondents expect hydrogen, mostly produced via electrolysis from excess renewables energy, to become a key part of the power generation mix and a sustainable tool for energy storage.

“The challenge now is not in the ambition, but in changing the timeline: from hydrogen on the horizon, to hydrogen in our homes, businesses, and transport systems,” commented Liv Hovem, CEO at DNV GL – Oil & Gas.

Industry ready to invest

The proportion of forward-looking industry leaders, ready to invest in hydrogen, has doubled from 20% to 42% this year. However, projects are still on a small scale and rather for demonstration purposes, so the industry’s shift to hydrogen is unlikely to help reduce carbon emissions.

Asia-Pacific, the Middle East and Europe are regions where industry is actively supporting the shift to a hydrogen economy. The race is on for developing novel electrolysing technologies, notably in Japan, Germany and the U.S.

Demonstration projects

DNV GL is involved in several projects to test and implement hydrogen, notably:

• The Hy4Heat programme in the UK, which aims to establish whether it is technically possible, safe, and convenient to replace methane with hydrogen in residential and commercial areas. Tests on three specially constructed houses look at a switch from natural gas to hydrogen at DNV GL’s Spadeadam Testing and Research site.
• A project run by Dutch TSO Stedin is demonstrating that zero-carbon hydrogen could help to decarbonize heating in a residential apartment block near Rotterdam, the Netherlands
• In Norway, Gassnova initiated a full-scale demonstration project whereby DNV GL qualified carbon capture technology developed by Aker Solutions, for use at Norcem’s cement plant in Brevik.
• Globally, DNV GL is keen to support governments with technical and market analysis to provide a knowledge base for decisions regarding national hydrogen strategies and supporting policy measures.

Blue vs. green hydrogen

Much ado has been made about blue vs. green hydrogen. Though hydrogen produces from renewables is the ultimate aim, needs to be acknowledged that the sector can only realistically scale up to large volumes and infrastructure with carbon-free hydrogen produced from fossil fuels combined with CCS technology (blue hydrogen).

DNV GL’s predicts that natural gas will become the world’s largest energy source in the mid-2020s, accounting for nearly 30% of the global energy supply in 2050. “Natural gas and hydrogen can play similar roles within the global energy system, and the synergies between them – in application and infrastructure – will drive the hydrogen economy,” analysts said.

Embracing green fuels

Though hydrogen is not yet cost-competitive as a fuel, more and more oil and gas companies are adapting their processes to a less carbon-intensive energy mix. Over the past two years, the number of companies actively involved in hydrogen has risen from 44% to currently over 60%.

To realize the full potential of both green and blue hydrogen (produced via carbon capture storage (CCS), policy makers have to set the right incentives to make large-scale projects forthcoming.

The German industry, for example, said to become carbon-neutral it would need to invest of around 45 billion Euros in new infrastructure and processes. In addition, it would need more than 600 TWh of electricity per year from the mid-2030s – more than Germany's entire current power production – mainly to produce hydrogen and other renewable fuels.

Test operation of the HL-class turbine in the 50 Hertz market, follows the recent first fire and synchronization to the grid of its first 60-Hertz version in a power plant in the United States.

Transport by ship

The SGT5-9000HL measures 13 meters in length, five meters in height, five meters in width, and weighs nearly 500 metric tons. To transport the heavy-duty turbine, it was loaded onto an inland cargo ship in Berlin and is now on rout to Britain.

The turbine will first travel by inland waterways, heading west to the Port of Rotterdam in the Netherlands, where it will be loaded onto a coastal ship for transport to the eastern coast of England. It will travel up the Humber and Trent rivers for approximately 12 days until it reaches the inland port of Keadby, where it will be lifted off the ship and driven to the construction site.

Start-up slated for 2021

Once arrived, the HL-turbine will be put into test operation and subsequently converted to combined-cycle mode. Set to run at over 63% efficiency, it will help SSE save fuel and reduce carbon emissions at Keadby-2 by as much as 3.7 million metric tons per year, compared to coal-fired power plants.

Initial operation of the new turbine in Keadby is scheduled for 2021, and once fully grid-synchronized it will provide provide enough electricity to a city with 3.3 million inhabitants.

SSE Thermal aims will place the turbine into commercial operation in 2022, following successful testing.

Stephen Wheeler, Managing Director, SSE Thermal, said the “first-of-a-kind technology will make Keadby 2 the UK’s cleanest and most efficient gas-fired power station, displacing older, more carbon-intensive generation, and providing vital flexibility for the electricity system.”

In addition to the technology, Siemens is also providing service with its first long-term program (LTP) for an HL-class gas turbine in Europe. Siemens will utilize its advanced digital service solutions, including remote monitoring and diagnostics, to help maintain the availability, reliability and optimal performance of the power plant.

The reach of this rule was widened last year to also include gas infrastructure whose supply originates outside the EU. Projects completed before 23 May 2019 can apply for an exemption and Gazprom had argued the cut-off should be not set at the time of commissioning, but when the project reached financial close.

The decision to build Nord Stream was made years earlier but works on the project were halted when the Swiss pipe-laying company ceased work over the treat of U.S. sanctions. Now, the Russian pipe-laying vessel Akademik Cherski is on route to Danish waters to complete construction of final part of the pipeline.

Gazprom likely to appeal decision

Turning down Gazprom’s application, the German regulator Bundesnetzagentur remained firm that the term ‘completion’ applied to construction and not financial close. It had asked all EU member states to comment on Gazprom’s application but none supported the argument.

Under EU rules, Gazprom would not only unbundle its supply and transport business but also grant third parties access to transport limited gas volumes through Nord Stream-2. The Russian state gas company is now preparing to appeal against the regulator’s decision.

The controversial second leg of Nord Stream will have a capacity of 55 Bcm per year which will effectively double Gazprom’s existing export capacity to Germany. Poland, Ukraine and several other eastern European countries oppose the enlarged interconnector through the Baltic Sea given that it will likely lead to a reduction in gas transit through their countries which lowers their gas transit fees.

Once the engines are manufactured in Friedrichshafen, they are subsequently built into complete systems at MTU’s Augsburg factory.

“Here in Augsburg, the majority of our people now work on the Series 4000 – not just in production, but on R&D activity as well. Our engineers are continuously working on improving the efficiency and performance of the system,” said Bernhard Bächle, head of the Augsburg manufacturing unit.

Series 4000 gas engines are used in array of application, ranging from pure power generation to combined heat and power production, which boosts the systems’ overall efficiencies towards 90%-plus.

Engine model on the market since 2003

Production of the 3000th gas genset is a symbolic milestone for Rolls-Royce, highlighting the growing demand for small and flexible gensets. The very first Series 4000 test gas engine was used at MTU's cogeneration plant 2 in Friedrichshafen back in 2003 – and one year later the engine model went into full production.

In the early years, the gas genset was mainly used to power greenhouses nurseries, especially in the Benelux countries, while in Germany the gas engine systems are mostly ordered from municipal utilities for use in CHP plants whereby the heat is sold to the local industry.

Rising demand for gas gensets to balance renewables

The current mark-4 version of the Series 4000 gas engine can be supplied as a natural gas, biogas or special gas engine with 8, 12, 16 or 20 cylinders, covering a power range from 800 to 2,600 kW and running for up to 8,000 hours per year, depending on the application.

“Today, flexible gas gensets are increasingly used in demand to compensate for the natural volatility of solar and wind power by generating what is referred to as load-balancing power and also for decentralized energy generation in emerging markets,” explained Andreas Görtz, Vice President, Power Generation at Rolls-Royce.

“As one of the core elements of our microgrids – autonomous, decentralized power grids – gas systems can make a significant contribution to the move towards renewable energies.”

The aim of the study is to establish the optimal size of the project, the cost of synthetic biogas for district heating. Once feasible, the two companies intend to jointly develop the project on a commercial scale.

Vantaa to exit coal in 2022

Synthetic biogas is ultimately meant to replace the use of natural gas to produce district heating in Vantaa Energy’s cogeneration plants, thereby reducing the utility’s emissions footprint. CEO Jukka Toivonen underlined the utility’s aim to end the use of coal already in 2022.

“We want to be a driver for change in the energy sector. We are actively and with an open mind seeking the best possible methods of producing energy in a smart and sustainable way and at a reasonable price. This project is an important step towards our goals,” he explained.

Wärtsilä has been working on and investing in Power-to-X research since 2018, gaining a general understanding of the technology. “This co-development agreement will allow us to apply the know-how into a real project. It will demonstrate the feasibility of synthetic fuels as an integral part of power and heat systems, while developing the overall sector coupling concepts going forward, said Matti Rautkivi, director, strategy and business development at Wärtsilä Energy.

Tyr Energy is the cornerstone of Itochu’s investment in Independent Power Project (IPPs) and currently holds interest in 15 projects with over 9 GW gross capacity. For the Hickory Run Energy Center, Tyr led the development, finance arrangement and selected the equipment suppliers as well as construction contractors. It also negotiated the terms and pricing of gas supply as well the power purchase agreement with PJM Interconnection, the largest wholesale power market in the U.S.

Other partners involved in the Hickory Run CCGT are the Japanese utility Kansai Electrical Power and the German manufacturer Siemens, who supplied two SGT6-8000H gas turbines, two heat recovery steam generators and a stream turbine.  EPC works had been carried out by Kiewit Power Constructors.

Apart from equity from Tyr and Itochu, the Hickory Run CCGT project is underpinned with dept financing from BNP Paribas, Bank of America, and Credit Agricole, Mitsubishi Financial Group, Sumitomo Mitsui Banking Corp, ABN Amro, National Australia Bank, Shinhan Bank, and the Japanese development bank.

Following the start-up of the Hickory Run Energy Center, Tyr Energy will manage the power plant asset and seek to maximise earnings on behalf of Itochu. NAES Corp, another Itochu subsidiary, will provide operation and maintenance services.

As one of the leading Japanese general trading companies, Itochu has been expanding its power generation business worldwide in recent year. In North America, it owns 17 power plant projects with a combined capacity of over 7,500 MW. Through NAES, it services over 190 power plants globally, mainly in the U.S., with a gross capacity of 50,000 MW.

With the 'base section' and 'upper cylinder' completed,  and the lower cylinder already in place, the construction of the fourth and final component of the cryostat – the so-called 'Top Lid'– can now begin with MAN Energy Solutions once again responsible for assembly and welding work.

Assembly of the four individual sections is scheduled for late-summer 2020.

Striving to tap a novel energy source

Technical experts from 35 nations are working on the ITER project, aiming to build the world's largest tokamak: a fusion reactor operating on the principle of magnetic confinement. The pilot project is meant to demonstrate that nuclear fusion can be a realistic and CO2-free energy source of the future.

A tokamak is a vacuum vessel in which the atomic nuclei of hydrogen isotopes – deuterium and tritium – fuse into helium. The enormous heat generated by this process will be used to generate energy and mimics the principle by which the sun and other stars function. One gram of fusion plasma contains the energy of approximately twelve tons of coal.

Ultimately, ITER will operate with just three grams of fusion plasma and generate 500 MW of thermal power.

Working with Larsen & Toubro

The cryostat forms the envelope of the ITER machine and provides the ultracold, vacuous environment necessary for the superconducting coils and vacuum vessel to work. In total, the cryostat consists of 54 individual elements produced by Indian company, Larsen & Toubro, and are assembled on the construction site by MAN Energy Solutions.

“It is a special honour for us to be involved in the most ambitious energy project in the world. We are helping to bring the source of solar energy to earth and thus generate CO2-free energy in huge quantities,” said Norbert Anger, Site Manager of MAN Energy Solutions in Deggendorf, where the ITER project is mainly managed within the company.

First fusion plasma planned for 2025

Construction work on the site of the ITER project began in 2012, with the construction of the reactor house starting two years later. The assembly of the ITER machine in the reactor building will begin in late-summer 2020.

With the assembly of the cyrostat, MAN Energy Solution is involved on a core component. According to current plans, the fusion reactor will generate the first plasma in 2025, with the full experiment scheduled to begin in 2035.

The two influential EU member states also tightened their 2030 target from 40% to 55% emissions reduction. Germany's environment ministry called the Paris Climate Agreement a "compass" for policy in the wake of the current crisis.

Industry calls for tax relief

The industry responded swiftly, calling for emergency support measures during the coronavirus crisis such as tax reliefs and rules to boost investments in climate action. Dieter Kempf, head of the German industry association BDI, said private investments in energy efficiency and digitalisation could be boosted by improving amortisation rules for new project finance.

He also stressed that high power prices remain a burden for the competitiveness of German industry. A reduction of the surcharges and levies on electricity, such as grid fees, could instantly put money into the pockets of companies and private households alike.

Taxes and the renewable energy surcharge (EEG levy) have pushed up Germany’s household electricity prices to the second highest level in Europe, topped only by prices in Denmark. While Danish households paid €29.2 per 100 kWh on average in the second half of 2019, prices in Germany averaged €28.7, according to the EU statistics office Eurostat.

European Green Deal

Emergency plans are worked up by governments around the global to cushion the economic effects of the pandemic. The increase government spending is seen by some as a chance to accelerate the transition to green energy sources.

The European Parliament this week passed a resolution insisting the upcoming budget must be in line with the European Green Deal. The legislative body called on the Commission to add the economic fund the long-term EU budget, it must not serve as an argument to reduce it.

“The executives in Brussels must establish a €2 trillion fund by issuing long-dated bonds and disburse the money “through loans and, mostly, through grants, direct payments for investment and equity,” the European Parliament said. The bill was passed with 505 votes in favour, 119 against and 69 abstentions.

Cash, investors’ confidence and supportive governments are the key factors for the rapid growth of green energy projects. Banks have given renewables projects preferential financing terms, such as low interest rates and long payback periods.

“Power demand growth has been phenomenal, and this has given global investors the confidence to put money into projects that provided stable returns while offering low perceived risk,” commented Alex Whitworth, Wood Mackenzie’s head of Power & Renewables for Asia Pacific.

Falling generation costs

Operation costs of new solar and wind plants across Asia Pacific have fallen by 54% and 29%, respectively, over the past five years. “This took average costs for new projects below those of gas-fired power by 2018, though in most places renewables are still around 30% higher than coal.

In China, subsidies and preferential dispatch polices have helped new wind and solar projects gain a competitive edge over fossil power plants. However, as the scale of renewable investments increase, many Asian governments are now reducing or cancelling these subsidies, and feed-in tariffs - similar to how green energy markets evolved in Europe.

Sharp and short recession

Gauging the impact of the coronavirus pandemic on energy investment across Asia Pacific, Wood Mackenzie current base case sees a “sharp but relatively short world recession” though there’s clearly risk to the downside.

“In our base case, we now expect APAC power demand to grow by 0.3% this year, resulting in the loss of 380 TWh of demand. But this is followed by strong recovery in 2021 and growth averages 3.6% over the next five years, in line with our pre-pandemic outlook,” Whitworth explained.

Confidence in demand growth

Though most investors have been hesitant to process projects to financial close since mid-February, the lower infection rates across Asia have renewed confidence in Asia Pacific power demand.

Capital markets are expected to soon re-open to the renewables sector, supported by government stimulus and a broader recovery will also push coal and gas prices higher. As a result, Wood Mackenzie sees APAC’s wind and solar build-out recover from 2021. That would mean the crisis results in a modest 26 GW of wind and solar projects being taken out of the pipeline through to 2024, a 5% decline by this time compared to WoodMac’s pre-pandemic outlook.

In case of a prolonged recession, analysts see around 1,000 TWh of demand permanently lost by 2023, equivalent to about two years of growth. In response, governments are likely to prioritise low cost coal, with renewable projects negatively impacted by higher financing costs, increasing the levelised cost of electricity.

“In this scenario, we could see 150 GW of project cancellations or delays across Asia Pacific in the next five years,” Whitworth said, noting, “this is equivalent to pushing back the Asia Pacific renewables construction pipeline by nearly two years.”

The intermittent nature of wind and solar power sources, requires grid operators to make efforts to mitigate the risk of disturbances and ensure a stable power supply. Terna owns and operates 98% of the Italian high-voltage power transmission grid, so it has a vital role for ensuring stable power supply to households and businesses.

Each of GE’s synchronous condenser unit can supply reactive power of up to +250/-125 MVAr and 1750 MWs inertia. The units are designed to quickly regulate the energy parameters of the transmission network, regulate the voltage and improve the energy factor, and increase the overall grid inertia with GE’s new flywheel system. Flywheels provide spinning reserve which is especially important as Italy has seen a strong growth of wind and photovoltaic plants, and a parallel reduction of coal power units.

Topair technology

Under the latest order, GE’s scope of supply includes the design, civil works, supply, installation and commissioning of two electrical two-pole generators “Topair” technology - each equipped with a flywheel, step-up transformers, generator circuit breakers, all the electrical and mechanical auxiliaries and balance of plant for our supply, including the protection and controls systems, monitoring and diagnostic systems, as well as 20 years of planned maintenance.

In addition, GE has been working on installing four 250 MVAr synchronous condensers on behalf of Terna near Selargius and Maida power plants in Sardinia and Calabria. The American OEM has already installed two 160 MVAr synchronous condensers at substations in Sicily that have been running since the end of 2015.

In total, GE’s eight synchronous condenser units with Terna will supply up to 1,820 MVAr of reactive power for Italy’s grid with a value of 10,500 MWs of inertia, helping to stabilize the grid across the south of Italy where more than 20 million people live.