When factoring the in burgeoning bus, truck and van markets, vehicles account for over 900 MW of the 1.1 GW total, according to E4tech’s latest Fuel Cell Industry Review.

The remainder consists of stationary systems – of which US and Korean power generation units make up the bulk – and tens of thousands of Japanese CHP units installed in apartments.

Fuel cells tech   ready for commercialization

“There is a real sense that the industry is on the cusp of something great. Fuel cells are proven from a technical perspective, and blowing past the 1 GW mark is a vindication of that,” said David Hart, director, Fuel Cells & Hydrogen at E4tech.

In 2020, the sector is expected to enter a new stage characterized by rapid commercialization and infrastructure build out. “If the 2010s can be seen as the breakout decade for the battery, the 2020s will see the ascendancy of the fuel cell. Just in time, too: climate change targets are looking more urgent and challenging than ever, and we need a full range of technologies to meet them,” Mr Hart commented.

At the same time, the broader hydrogen sector is starting to expand as recognition grows that some applications, like heat, will be difficult to fully electrify. This supports and complements fuel cell growth.

Strongest demand growth in China and Korea

Asia remains the largest market for fuel cells, accounting for 680 MW, driven strongly by Hyundai NEXO sales into Korea and by Korean stationary power. Fuel cell vehicles deployed in Asia in 2019, including trucks and buses in China, constitute 50% of the total shipped fuel cell capacity worldwide.

The NEXO also accounts for some growth in European capacity, which rose from 41 MW to 69 MW in 2019. However, the biggest market outside of Asia is North America, which saw shipped capacity of 384 MW – down slightly from 425 MW in 2018, but expected to rebound in 2020.

“To succeed, the fuel cell industry will need to see the supply chain mature quickly enough to deliver on expectations, and to allay any remaining safety concerns. But the opportunity is huge, big players are investing very seriously in hydrogen, putting the pieces into place to make it work,” Hart noted.

Once that happens, fuel cells will rank as an established technology, feeding not just into the success of today’s products and systems, but featuring in the designs of tomorrow’s innovators and entrepreneurs.

Despite a small decline from 114.2 billion cubic metres in 2018, Gassco said the year 2019 ranked as one of the best ever for gas deliveries from the Norwegian continental shelf.

“Even in a year with a big rise in European imports of liquefied natural gas (LNG), Norway’s gas deliveries were well above the average for the past decade,” commented Gassco’s CEO, Frode Leversund.

High and stable volumes of Norwegian gas supply ensured stable deliveries to Europe. Gassco noted the availability for delivery of gas to the transport system over the past year was more than 99 percent. “That’s a solid result,” Leversund commented, “and demonstrates good interaction from field to delivery points in Europe.”

By comparison, Gazprom’s exports of Russian pipeline gas to Europe and Turkey reached almost 202 Bcm in 2018, according to the last available official figures.

Going forward, the Norwegian state-owned TSO Gassco is working to find the right integrated infrastructure solutions to enhance gas deliveries from the Norwegian continental shelf. Extensive planned maintenance work has already been carried out in 2019, and is bound to continue.

In addition to natural gas, Gassco noted its deliveries of natural gas liquids (NGL) and condensate from the process plants at Kårstø, Kollsnes and Nyhamna totalled 10.1 million tonnes in 2019.

Compensation payments are currently planned for power plants with a total capacity of 2.5 gigawatts (GW) that will be turned off by the end of 2022. Additional payments of some 700 million Euros will be made to finance the early retirement of about 3,000 coal workers.

After months of talks, Germany’s multi-stakeholder coal exit commission had agreed to phase out the fossil fuel by 2038 at the latest. Early on, RWE had signaled it could shoulder the early shutdowns in western Germany, due to its greater economic alternatives than in the East.

Quarrels about Datteln-4

Uniper, Germany’s largest utility, had propose to shut down or convert to gas all its entire fleet of coal power stations in return for putting online its new hard-coal plant Datteln-4 before summer 2020.

For power stations already built but not yet operation, such as Datteln-4, the German coal exit commission had initially recommended a negotiated solution so they are not taken into operation. However, Eastern German states, that are bound to be hard hit by the coal exit, find this ruling unfair and want the new Datteln power unit not to be put into operation.

Trying to resolve matters, Chancellor Angela Merkel has invited all coal-state government heads to a meeting in the chancellery on 15 January.

Policy makers in Beijing seek to boost domestic production of gas, but the country also needs more LNG and piped gas imports. Gas currently accounts for less than 8 percent of China’s energy mix, compared to a global average of 22 percent.

Forecasts as to how China will cover its rising gas needs vary widely, though most analysts expect China’s import dependency will grow significantly. DNV GL’s Industry Outlook 2019 research showed almost two thirds (61 percent) of senior industry professionals in China say more investment is needed in LNG and pipeline infrastructure.

Striving to secure supplies, without disregarding safety

As Chinese gas demand spirals, the pressure on securing supply is high, while the requirements on the reliability of facilities and equipment are even higher. ”As China is enhancing pipeline interconnections, we need to pay high attention to safety management with zero tolerance for major incidents,” said Mr. Zhou, a manager from a major Chinese pipeline operator.

”There are still have challenges in intrinsic safety management, and integrity management of facilities and equipment,” said Arthur Stoddart, regional manager, China, South Korea and Japan, DNV GL – Oil & Gas.”Gaps need to be closed in the establishment and implementation of our management system, and strong execution and sufficient tools need to be in place to facilitate the implementation, and then manage and maintain the improved infrastructure.”

Fast-tracking LNG regas and pipeline expansions

Some 18 LNG import terminals have been in operation in China over the past year, with a total installed domestic capacity of nearly 60 million tonnes per annum (mtpa). Seven were being expanded and another seven new-build terminals are on the drawing board. The projects could add nearly 19 mtpa capacity by the early-2020s, with more expected by mid-decade.

BP’s latest Energy Outlook anticipates that around half of China’s additional gas needs will be met by new pipeline capacity from Russia and other CIS countries, and the rest from LNG. Over the coming twelve months, the government in Beijing wants to create a state-owned national pipeline company to operate all oil and gas pipeline networks to extend its reach and reliability.

To enhance supply security, China is expanding its strategic gas storage and is building up a fleet of LNG carriers to become less exposed to seasonal price shifts.

Without these two hydro-power megaprojects, the 19 projects currently under construction total just 4.5 GW, compared to 24 projects totalling 5 GW in the IEA’s 2016 report.

Zambia is currently the largest investor in Chinese-added capacity, followed by Nigeria, Angola, Uganda and Côte d’Ivoire. These five countries make up around half of the capacity added or being added by Chinese contractors. In terms of fuel type, 11% of the projects run on natural gas, 9% on coal, and 4% on oil. In the last five years, Chinese contractors completed five coal-fired plants in Nigeria, Rwanda (peat), Zambia, and Botswana for a total of 811 MW.

A greener mix

When the IEA first analyzed China’s involvement in the sub-Saharan Africa power sector in 2016, Chinese companies operating as the main contractor were responsible for almost 30% of capacity additions in the region. Since then, capacity additions by Chinese companies have fallen somewhat, although low-carbon projects represent a larger share.

Of all the newly Chinese-built power plants in the region, 52% are fully-integrated with both a Chinese contractor and a Chinese turbine manufacturer. In total, Chinese equipment manufacturers between 2014 and 2024 are seen supplying more than 9 GW of power generation equipment: approximately 7 GW in hydro, 1 GW in wind and solar PV, and 1 GW in coal and oil.

If Chinese energy infrastructure need to source equipment from overseas, these are mostly gas turbines, a piece of equipment for which Chinese contractors currently rely entirely on foreign manufacturers.

Project finance, combined with EPC

Chinese energy companies in Africa focus mainly on supplying construction services and equipment with engineering, procurement and construction (EPC) being the most common type of project contracting arrangement for construction services. Host country governments issue bids and award projects, and Chinese energy infrastructure companies deliver construction services without having any stake in the project.

Additional electricity capacities fall under public sector spending from a country’s national budget. “This means that project financing remains challenging and tends to shift progressively away from public lending towards more equity financing,” IEA analysts commented.

“However, this remains challenging in the absence of reliable power purchase agreements and adequate, stable local regulation,” analysts said, suggesting “ultimately, the success of a power project depends on the ability of African governments to negotiate, implement and maintain the project.”

Himile Mechanical Science and Technology, based in China’s Shandong Province, was singled out for its “ability to handle blanket orders for gas turbine components,” notably cast steel and castings as well as final machining and fitting of attachments, helping to strengthen MHPS’ competitiveness.

Kajima supported MHPS to make revisions to construction work designs and methods according to value engineering(note) principles.

Sung Il continued its production of prefabricated piping processed at the factory and assembled on site, with “stable quality over many years.”

HP Valves, also known as Hengelo, helped expand scope of MHPS’ business for high pressure valves for several projects including first-time customers, and completed delivery while maintaining quality and deadlines.

Liang Liang Industries received an award for manufacturing a ship desulfurization scrubber (exhaust gas treatment system), conducted quality and delivery date management for the initial unit, and completed shipment on schedule.

Going forward, the MHPS said it will step up its efforts to improve quality, delivery speed, and cost in the areas of thermal power generation and environmental technologies.

As thermal coal is a cheaper fuel than regasified LNG for power generation, Japanese utilities are looking to build new coal power plants and have decided not to renew some LNG import contracts after expiry. Hence, LNG shipments to Japan in 2019 already fell by nearly 12 percent to around 72.8 million tonnes per annum (mmtpa), while cargoes headed for China increased by 37.5 percent to just over 74.1 mmtpa over the same period.

By the end of 2020, Japan is likely to have lost its position as the world’s No.1 LNG importer to China. Analysts noted that Japanese energy companies are currently “well-contracted in LNG” to the early 2020s. However, the average cost of gas for Japanese utilities remains “well above spot price,” Wood Mackenzie finds, stressing “coal is still the cheapest form of electricity generation after nuclear and renewables on a short-run marginal cost basis.”

Public opinion turns against coal

Environmentalist have brand-marked Japan as “an outlier” given that it is one of the very few developed power market that still prioritizes construction of new coal capacity. But the government’s pro-coal policy targets seem to be misaligned with public sentiment and rising concerns about air pollution.

“The tide appears to be turning with increasing restrictions on financing and building coal. As such, we expect this policy target and such a robust share of coal in the generation mix will be increasingly difficult to sustain, which would improve the outlook for LNG,” commented Wood Mackenzie’ senior analyst, Lucy Cullen.

In terms of demand, analysts expect Japan’s LNG imports will remain above 70 mmtpa through much of the 2020s, and may even exceed 60 mmtpa until at least 2040.

So Japan is set to remain the world’s No.2 LNG importer, after China, Ms. Cullen stressed, suggesting: “The Japanese market still provides ample opportunities for LNG sellers, particularly as existing contracts expire.”

Risk of missing renewable targets

Aggressive investments into new wind and solar power capacities is meant to boost Japan’s renewable energy share to 22-24 percent of its 2030, but analyst warned that too little effort is being made to grid-integrate the influx of intermittent green energy supply.

On the nuclear front, Japan restarted five plants last year alone. With next restarts scheduled for the mid-2020 and 2021, this will put downward pressure on LNG import requirements in the early 2020s. “We assume 15 reactors will be back online by 2030, accounting for 12 percent of power generation, much lower than the official target of 20-22 percent,” Cullen said.

“While nuclear restarts generally dampen gas generation, our lower nuclear number implies a more optimistic view of LNG demand compared to the government.”

Qinous has made a name for itself with modular, scalable, prefabricated plug-and-play battery products that combine renewable energy sources, power generators and battery storage technology. The specialist for battery storage and associated control systems, and has already implemented storage solutions around the world.

“As a young, start-up-style company, Qinous brings expertise that is an ideal complement to Rolls-Royce's industrial credentials. Together we will be able to respond quickly and with great professionalism to the demands of the market,” said Andreas Schell, CEO of Rolls-Royce Power Systems. “In future, we will be able to offer not just the technical solution and associated service offerings, but the finance too.”

Response to rapidly growing microgrid market

The closer partnership is seen as a logical and consistent step towards opening up the rapidly growing microgrid market. “Functionality and reliability of tour solutions have been proven. Now, with MTU's experience and global presence, we can meet demand more quickly and more comprehensively,” said Qinous co-founder Steffen Heinrich. He thanked the “seedcorn investors” who made it possible to set Qinous up as a company, and gave continuous support.

Rolls-Royce had already acquired a 19.9% stake in the former start-up back in October 2018. Now, it is boosting its shareholding to over 73 percent by snapping up the stakes of all other current financial investors, including that of investment holdings IBB Berlin. The founding shareholders will owns part of the company and retain their current roles in the business.

The modular components of the Qinous/MTU product range will span from 30 kW/30kWh to several megawatts (MW). This covers the needs of commercial enterprises, municipal utilities, energy suppliers, and even sizeable industrial plants.

The two partner will offer microgrid solutions, based on various power gen and storage systems. According to Cordelia Thielitz, VP of Rolls-Royce's microgrid solutions business, “The key to this is the comprehensive expertise in storage technology, the efficient integration of microgrid components and the development of intelligent control systems,”

Berlin-based Qinous employs around 40 people. Rolls-Royce is engaged in research and development of microgrids and power generators at four locations: Friedrichshafen, Ruhstorf, Augsburg, all situated in Germany as well as at Mankato, Minnesota, U.S.

Across Appalachia, long-term rig decline seems to finally dragging production down, the London-based consultancy Energy Aspects commented.

Strong hedge books

“We believe that Appalachia shut-ins are unlikely unless prices drop well below $1.50/MMbtu, given the basin’s competitive advantages. Even then, many producers in the region have strong hedge books,” analysts said in a research note.

“Still, weak prices throughout H2-19 and into 2020 have caused producers to slash Capex and limit production guidance,” they cautioned.

Production seen to soon rebound

Work at TETCO – mainly repairs after an August 1 explosion near Danville, Kentucky – had caused 0.4 billion cubic feet per day (bcf/d) month-on-month decline from Appalachia to 32.4 bcf/d in December. Though works are nearing completion, analysts cautioned the pipeline’s 30-inch line is still subject to an ongoing corrective action.

Whether regional gas production rebounds as TETCO work eases will indicate the degree to which maintenance was limiting output. January to-date flow data points to another 0.3 bcf/d m/m decline to 32.0 bcf/d. Checks and repair is now limiting flows south to the Gulf Coast by 0.8 bcf/d.

“The effect on flow dynamics is minimal,” analysts noted, “given that gas is more likely to flow north for heating demand during winter..

“If later month receipts trend back towards the 32.5 bcf/d daily readings that were commonplace in early December, it can be assumed maintenance was the culprit for the weak output figures from late 2019,” analyst said. Meanwhile, “if flows stay depressed close to 32 bcf/d, it is likely that November was the high-water mark for Appalachia production for the foreseeable future, given current prices are unlikely to spur investment. If that is the case, Lower 48 gas supply will have lost a key sequential growth engine in 2020.”

Both trends indicate an even lower TTF price for 2020, which in turn suggests lower spot price in Asia. Not to forget, Sims noted, the “ever present is the risk to LNG supplies from Qatar should US-Iran tensions escalate to a point of causing disruption to shipping through the Strait of Hormuz.”

On the demand side, low LNG spot prices across Asia have brought forward a range of new buyers. In South Korea, for example, new power and industrial consumers are also looking to self-procure, joining the likes of POSCO, SK E&S, GS Energy and others who already independently import and bypass KOGAS' stronghold on the market.

In Malaysia, Shell imported a spot LNG cargo into Malaysia, breaking PETRONAS’ monopoly for the first time. Now, Malaysia’s power generation company TNB, TNBF, is understood to be looking for additional cargoes in 2020. Incumbents, like Petronas or Kogas, have a supply portfolio of long-term supply contracts with relatively high prices.

“Being able to self-purchase LNG from the spot market will provide additional margin for these end users,” analysts stressed. After a few spot cargoes under their belts, these new buyers and LNG suppliers might well gain confidence to take on mid-term deals.

Asia’s backlash against coal could provide upside

Clean air policies, adopted by governments in South Korea and Taiwan, have reduced coal-burn in the power sector which is starting to have a positive effect on gas demand.

“If this winter’s curtailments [and restrictions on coal power dispatch] have a positive impact and blackouts are avoided, then seasonal coal curtailments are likely to feature regularly in Northeast Asia; to the benefit of LNG,” said principal analyst Lucy Cullen.

She cautioned, however, that the nature of energy markets in Northeast Asia does not favour significant coal-to-gas switching. Emissions concerns and sustained low natural gas and LNG prices may provide the necessary impetus for wider-scale switching in 2020.

Works will focus on converting the existing five Wärtsilä 46GD dual-fuel combustion engines to five Wärtsilä 50SG gas fueled engines, and additional system upgrades.

Once completed, the improved plant performance will raise its overall competitiveness, especially with regard to winning contracts in Brazil’s future energy auctions. The operator RAESA seeks to extend its existing Power Purchase Agreement (PPA) to sell the entire power output from the Cristiano Rocha plant to the Brazil’s national grid.

The current contract is set to expire in 2025.

No more need for rental power units

“The combination of converting to fully gas-powered operation and having a supporting long-term service agreement will deliver clear economic, performance, and environmental benefits,” said Edésio Nunes, CEO of Multiner. In his view, “this upgrade provides an avenue to transform our business to a more viable future enterprise.”

At present, RAESA rents additional generators to ensure adequate output of the Cristiano Rocha power plant. The cost for rental power and more expensive diesel fuel will be eliminated when the conversion is completed.

Furthermore, the use of natural gas fuel will reduce the plant’s carbon emissions by some 10 percent, representing some 35,000 metric tons of carbon dioxide equivalent per year, which equals the pollution from some 7600 cars.

According to Tom Lindqvist, responsible for service projects at Wärtsilä Energy, the conversion and upgrade will increase the plant’s operational reliability and diminish operating costs, while the service agreement will optimize equipment maintenance and planning, guarantee the capacity, and enable predictability of maintenance costs. “We shall have a dedicated technical consultant on hand at the plant to ensure that the capacity guarantees are met,” he noted.

IEC’s modernization project for the Hadera plant, first announced in 2018, comes in reaction to new legislation passed by the government of Israel, notably the 2011 Clean Air Law.

For GE, today’s order win comes shortly after the contract for the first HA turbine was signed in April 2019. As per the latest order, GE will also provide a steam turbine, generator, heat recovery steam generator and balance of plant equipment—as well as a 15-year services agreement.

First CCGT due operational in 2022

With over 61% net efficiency rate, each of GE’s 9HA.01 gas-fired units will produce 630 MW to replace the output of four of the existing coal-fired units. The first unit of the converted Hadera CCGT plant is due for commissioning in 2022.

Once fully operational, the Orot Rabin CCGT is expected to be largest and the most efficient gas-fired power unit in Israel. With an installed capacity of nearly 1.3 GW the CCGT will account for more than 8% of Israel’s total installed power generation capacity.

“Gas will play a significant role in Israel’s energy future due to its sustainability, generation flexibility, low capital costs, natural resource efficiency, and rapid deployment capabilities,” said Michael Rechsteiner, CEO of GE’s Gas Power business in Europe. The 9HA turbines are using natural gas as the primary fuel and fuel oil as secondary fuel.

The fleet of GE’s HA gas turbines recently reached the milestone of 500,000 operating hours, having secured 101 orders from 40+ customers across 19 countries. It is available for both 50 and 60 hertz markets.

Throughout most of the United States, in contrast, monthly average prices remained lower than $75/MWh.

In the Electric Reliability Council of Texas (ERCOT) market zone, day-ahead around-the-clock wholesale electricity prices averaged $38/MWh in 2019, up 13% year-on-year. However, on August 12, 2019, electricity demand in ERCOT hit a record high of 74,666 MW, propelling up wholesale prices on August 13 and 15 to reach their $9,000/MWh cap for several hours.

The Texan grid operator has one of the lowest reserve margins of any electricity market region in the U.S., meaning it has a very small buffer of extra capacity to serve peakload demand.

Electricity prices fall elsewhere amid cheap domestic gas supply

At other key hubs – PJM, ISO-NE and ISO-NY – wholesale electricity prices were generally 15% to 30% lower on average than in 2018. Analysts noted much of this decline was the result of lower natural gas prices.

Natural gas spot prices in 2019 at Henry Hub in Louisiana averaged $2.57 per million British thermal units (MMBtu) last year, about 60 cents per MMBtu lower year-on-year and the lowest annual average price since 2016. According to U.S. government analysis , lower gas prices in 2019 supported higher consumption – particularly in the electric generation sector – and higher exports. Continued growth in domestic gas production also supported lower prices throughout the year.

In the northwestern United States, constraints on a transnational gas pipeline system resulted in higher wholesale electricity prices in the region in February, which also had implications for California’s power market. In New England, timely deliveries of LNG helped reduce price volatility on both gas and power markets in the first quarter of the year.

In the Pacific Northwest, however, unseasonably cold weather at the end of winter coupled with regional supply constraints and decreased storage inventories led to significant price spikes at the Northwest Sumas hub in March.

Most new pipelines placed in service in 2019 were located in the South Central and Northeast regions. These pipelines provide additional takeaway capacity out of the Permian and Appalachian supply basins and will serve growing demand for LNG exports, pipeline exports to Mexico, and U.S. gas-fired power generation.

Carmakers are under pressure to electrify their car fleets to comply with EU climate and air quality targets. Moreover, the German government's climate action programme stipulates that up to ten million e-cars are put on the road in the country by 2030.

However, just over 83,000 purely electric cars and 340,000 hybrid cars were registered in Germany in January 2019, and about 63,000 additional new purely electric cars were registered throughout that year. Sales is accelerating, as around 97,000 electric cars were sold in Germany, up to and including November, an annual increase of 49 percent.

E-mobility still “very expensive”

Deutsche Bank warned that the German e-vehicle market has been “largely driven by regulation” and “less by market forces”. Without subsidies, e-cars are “still a niche”, analysts said, noting the technology is “a very expensive way of avoiding carbon emissions.”

New electric car registrations only reached a 2.6 percent market share in the European Union this year, but 30-50 percent market share would be needed by 2030 to achieve Germany’s targeted CO2 limits for new car fleets, Deutsche Bank Research finds.

Car makers traditionally have a big lobby in Germany, and the industry recently announced ambitious plans to raise the share of e-cars in their product portfolio, in competition with rival electric car makers in Asia and the United States.

In November, Tesla announced to Gigafactory-4 – its first European factory for battery cells and e-vehicles – in Germany, just south east of Berlin. There, Tesla plans to build batteries, power-trains and vehicles, starting with the much-anticipated Model Y – an electric SUV. Market observers hope this will bring an “enormous boost” for the country's lagging shift to electric mobility.

Moreover, the European Investment Bank (EIB) does not need a capital increase as European climate targets can be reached "with the EIB's existing resources," the German finance ministry commented. Under the Commission’s proposal, the EIB was meant to grant a public sector loan, backed by the EU budget, to mobilise between €25 and €30 billion of investments.

Where will the funds come from?

On January 14, Ursula von der Leyen, the new President of the European Commission unveiled its financial plan to shift Europe towards carbon-neutrality by 2050.

Of the staggering €1 trillion funding for the EU Green deal, some €503 billion will come from the EU budget, plus some €25 billion from the EU emission trading system (ETS) funds. InvestEU, an umbrella organization of European investment banks and national banks are hoped to help mobilize private sector monies of at least €279 billion.

To ease the burden in Europe’s traditional coal regions, a ‘Just Transition Mechanism’ has been set up to help mobilise at least €100 billion over the period 2021-2027 in the most affected regions by alleviating the socio-economic impact of the transition. This fund will receive €7.5 billion of „fresh EU funds,“ the Commission pledged, with another €30 and €50 billion set to come from the European Regional Development Fund and the European Social Fund Plus.

How much of this is new money?

The European Green Deal Investment Plan builds on the Commission's proposal for the future long-term budget 2021-2027. Running for 7 years, it will mobilise 25% of the EU budget for climate financing and invest in environmental objectives through several EU programmes.

Extrapolated to 10 years, assuming the climate target will be at least maintained post -2027, the long-term budget is expected to deliver €503 billion. The next long-term budget 2021-2027 is currently under negotiation. The numbers are extrapolated to ten years, without prejudice to the final agreement on the next long-term budget and the one after 2027.

The Plan also builds on the contributions from national budgets to EU projects, on public and private investments mobilised by InvestEU and the ETS funds

EU push compels Germany to act

In Germany, green investment is rising quickly in volume, but sustainable finance experts warn that the government needs to find a clear position on how it plans to integrate finance in its environmental policies in order to shape developments rather than just following them.

Though sustainable investment still only account for about 3 percent of the country’s overall investment, the volume of assets managed in retail funds under the so-called ESG (environmental, social, governance) criteria in Germany has doubled over the past five years from €15 billion to over €30 billion. More coherent action, and pan-European coordination would be needed in the future, to help enact aspirations under the EU Green Deal

Looking at 2020 and beyond, constraints costs in the Balancing Mechanism continue to rise over time in line with growth in renewable deployment (see graph). According to Cornwall Insight, “this is unsurprising given the growth in renewable deployment and the predominance of onshore wind being deployed in Scotland.”

Managing grid constraints

Today, grid bottlenecks are handled by matching bids (to reduce output) and offers (to increase output). Considering the dominance of wind power supply in Scotland, the current grid constraints occasionally forces National Grid ask some wind farms to turn down against some compensation.

In the long run, it would be prudent and more sustainable, to fully utilize Britain’s wind power potential by building additional power transmission line. According to Cornwall Insight, network reinforcement is costly but vital, especially in the Cheviot Boundary area between northern England and Scotland.

National Grid’s new constraint pathfinder’s first project is looking for at least 200MW with a 2 hour duration to manage the flows between Scotland and England, which currently ranges between £100-200mn a year from Balancing Mechanism actions alone.

Contrasting two ways of cost-sharing

GB policy for transmission connections still remains as ‘Connect and Manage’, in which generators who wish to connect to the system have a fixed date for receiving Transmission Entry Capacity. Hereby, the cost for grid expansion and reinforcement are shared by all network users.

In contrast, under the previous ‘Invest and Connect’ approach, the grid connection cost had to be paid by the parties contributing to the problem. This more straight-forward approached has allowed the UK to meet the 20 percent by 2020 renewables target, and analysts say it would help to reach the Net-Zero target.

A positive example is the Western High Voltage Direct Current (HVDC) link between Western Scotland (Hunterston) and North Wales (Flintshire Bridge), at a total of 2.2GW – the so-called ‘Western Boostrap’. The project underwent significant pre-planning and environmental and marine studies necessary to obtain necessary licences, with construction starting in 2013 and commissioning completed in 2018.

“Despite some reliability issues, it is a good example of managing connections while limiting the costs of constraints,” analysts concluded.

As per the agreement, the gas turbine will be connected to the GE´s Monitoring & Diagnostics Center for 24/7 predictive maintenance support. A turbine upgrade with GE’s Advanced Gas Path technology is also part of the contract, which would improve unit’s availability, heat rate, and output.

AGP technology and advanced analytics

“The reliability of a turbine impacts the performance of the entire plant” said Gigi Shlomo CEO of MRC Alon Tavor Power Ltd. After examining both operating and capital expenditures, the plant operator has chosen GE’s total plant solution and advanced analytics to improve 9FA gas turbine’s reliability, as well as to lower its operation and maintenance costs.

As the original equipment manufacturer (OEM) of Alon Tavor’s power island since 2004, when the plant was commissioned, GE has been responsible for the reliable operations of the plant’s power generation equipment. “We are honored that MRC awarded our expertise and proven execution capabilities with this new agreement,” said Michael Rechsteiner, Vice President and CEO of GE’s Gas Power business in Europe.

GE Power Israel is responsible for the maintenance of the power Plants of all of Israel’s largest power producers, Dorad, Dalia Power Energies, OPC Hadera, the IEC (Eshkol and Tzafit sites), Nesher and Delek Ashkelon, who jointly represent 60% of the country’s overall power production capacity.

Earlier this week, GE had received an order for a second 9HA.01 heavy-duty gas turbine from Israel Electric Corporation (IEC). The turbine will be used at IEC’s Orot Rabin plant, located in Hadera, Israel, as part of the conversion of the existing power station from coal to gas generation.

Huge investment needs in investments in electrification and autonomous driving, cooling global demand, plus the effects of trade disputes and Brexit: the challenges facing BMW, Daimler and VW are so numerous that 2020 has already been dubbed a "fateful year" for the German car groups.

Tougher EU pollution limits

Worse still, the EU's pollution limits are posing an even greater uncertainty for the sector. The average new car registered in the EU must not emit more than 95 grams of CO2 per kilometer, which corresponds to a fuel consumption of around 4.1 liters of petrol or 3.6 liters of diesel per 100 kilometers.

Electric cars could become a panacea for this problem. Projections for Europe indicate that automakers would need to sell up to 2.2 million electric vehicle (EV) units in 2021 alone to meet their fleet CO2 targets, said the business consultancy McKinsey.

Surge in e-car sales on the cards

According to McKinsey projections, "that would be a steep ramp-up of EV sales in fewer than two years and equivalent to global EV sales in 2018.” Analysts cautioned, however, this is “a big task not only for the automotive industry but also for the associated industries."

The carmakers also attempt to use the demand for SUVs to push electric mobility by offering electrified SUVs. Audi started selling the e-Tron in 2019 and Mercedes launched its EQC – both weighing around 2.5 tonnes when they are empty. BMW will sell an electric X3, also an SUV, in 2020.

VW to launch 1^st fully electric model

Among the German carmakers, VW has made the most outstanding commitment to electric mobility. The world's largest carmaker pledged last year to transform itself from ‘dieselgate pariah’ into ‘e-mobility pioneer’, and has committed dozens of billions of Euros to the task.

In 2020, VW will launch the ID.3, its first fully electric model based on a new vehicle platform that forms the basis for its huge electric ambitions. Experts believe that VW's full entry into electric mobility could indeed turn out to be a game changer.

The coal exit is meant to ensure that Germany, Europe’s largest economy, will meet its 2030 target for cutting greenhouse-gas emissions. Investment in offshore wind, solar power and new long-distance power transmission lines are also on the cards.

“Germany, one of the strongest and most successful industrial nations in the world, is taking huge steps towards leaving the fossil fuel era,” said Finance Minister Olaf Scholz.

Boosting RES and gas-fuelled CHP plants

The agreed phase-out roadmap entails a boost for renewable energy sources (RES) to reach a 65 percent share in power consumption by 2030 in order to compensate for the closure of coal power plants. It will also seek to expand combined heat and power (CHP) systems and install "two gas plant capacities" to cushion "the vanishing of large quantities of controllable energy."

Analysts said that the decision marks a major turnaround for Chancellor Angela Merkel’s Conservative-Social Democrat coalition. It previously shelved a key emissions target shortly before re-taking office in 2017, only change course amid growing public concerns about climate change, and a surge in polls by the Green Party.

“These were tough negotiations,” said environment minister Svenja Schulze. “But you can see the result - we are the first country that has a binding agreement to exit coal and nuclear power - and that’s an important signal internationally.”

Timeframe of coal exit – two options

In a first step, Germany's total installed lignite-fired power generation capacity will be reduced to 15 gigawatts (GW) by the end of 2022, with eight plants operated by RWE in western Germany going offline by that year. The total installed lignite generation capacity stood at about 21 GW in 2019.

In a second phase, starting after a two-year hiatus following the nuclear exit, capacity will be cut to 8.8 GW between 2025 and 2029. A total of eleven units are to be taken offline, three of which are transferred into security standby. Five of these eleven units are operated by RWE in the west and six by LEAG, a subsidiary of Czech investor EPH, in eastern Germany. 

During the final phase starting in the 2030s, the remaining eleven lignite units in the country are scheduled for decommissioning between 2034 and 2038, the year agreed by the coal exit commission as the very last for the fossil fuel in the country. But the agreement also says there will be an assessment in 2026 and 2029 to see whether the last phase of decommissioning in the 2030s can be brought forward by three years. In this case, the coal exit would be completed in 2035 instead of 2038.

LNG imports to soon add to Russian pipeline gas

Situated in central Europe, Germany has been a long-standing offtaker of pipeline gas, mostly from the Russian energy giant Gazprom, but also from Norway's Gassco and previously from the Netherland.

However, it will soon alos have LNG import capability, allowing the country to diversify its gas import sources and taking advantage from cheap LNG cargoes on oversupplied global markets. Two new LNG regas and import facilities are two are planned, one on the Elbe River near Hamburg and another at the North Sea port of Wilhelmshaven.

If its latest Short-Term Energy Outlook forecast holds, energy-related CO2 emissions will have declined in 7 of the 10 years from 2012 to 2021. With the anticipated declines, the 2021 level of fewer than 5 billion metric tons would be the first time emissions have been at that level since 1991.

Efficient combined-cycle gas turbine (CCGT) power units will keep replacing aging and more polluting coal-fired power stations, but the EIA sees the total share of fossil generation decline amid a strong rise in renewable power sources. Coal and natural gas electric generation combined, which had a 63 percent share of generation in 2018, fell to 62 percent in 2019, according to EIA figures, and is forecast to fall to 59 percent in 2020 and 58 percent in 2021.

Massive impact of fuel switching

Fuel switching in the power generation sector has a large impact on energy related emissions. In 2020, coal-related CO2 are seen fall 10.8 percent after plunging after declining by 12.7% in 2019 because of low natural gas prices. Coal-fired generation alone has fallen from 28 percent in 2018 to 24 percent in 2019 and will fall further to 21 percent in 2020 and 2021. The gas-fired generation share rises from 37 percent in 2019 to 38 percent in 2020, but it declines to 37 percent in 2021.

Natural gas -related emissions -- notably in the upstream sector and from gas-fired heating appliances -- increased 4.2 percent last year and is seen rising 1.4 percent in 2020, before falling 1.7 percent in 2021 due to warmer winter weather and less heating demand. The recent declines come after an increase in 2018 when weather-related factors pushed up emissions from the oil & gas upstream and power generation by 2.9 percent, the U.S. Energy Information Administration (EIA) noted.

Petroleum-related CO2 emissions are seen to remain flat in 2020 and decline slightly in 2021. More than two-thirds of U.S. petroleum consumption is for transportation, not least becomes miles traveled (VMT) keeps growing nearly 1% annually during the forecast period.