U.S. West Texas Intermediate crude futures, meanwhile, plunged 3.8 percent to a three-and-a-half-month low of $52.15 per barrel.

"Investors react quickly to any sign of negativity and this is no exception as China announces that the issue has become an emergency. This could keep oil prices fragile until the coronavirus shows signs of slowing down," said Mihir Kapadia, CEO at Sun Global Investments.

The deadly disease caused by the coronavirus so far killed 81 people in China with almost 3,000 confirmed ill, while at least 44 cases have been reported abroad in countries as far as Singapore, France and the U.S.

The Economist Intelligence Unit said the longer-term impact of the coronavirus will depend on how quickly it is contained and the confidence of the public in the authorities' ability to take effective measures. “The experience of previous disease outbreaks, including SARS in 2002-03, suggests that consumer spending could be negatively affected in the next two-three months, but that this is likely to be compensated for later in the year,” commented EIU global economist, Cailin Birch. In the wake of the SARS outbreak, the Chinese economy slowed from 11 percent to 9 percent and recovered slowly.

Shares at London's FTSE 100 share index today shed more than 2 percent, with luxury clothes maker Burberry loosing 5.5 percent in share value. Other loss-making shares were British Airways owner IAG and HSBC Holding.

LTIIP II projects will include replacing older power transmission poles, underground and overhead lines and fuses; installing new substation equipment, network vaults and manhole covers; and reconfiguring circuits.

Approximately $123 million of the work will be carried out this year across FirstEnergy's Pennsylvania service areas, with the remainder spent over the next four years.

Expected 2020-2024 LTIIP II investments for each operating company are: Metropolitan Edison (Met-Ed) - $153 million, Pennsylvania Electric Company (Penelec) – approximately $200 million, Pennsylvania Power (Penn Power) - $72 million, and West Penn Power – approximately $147 million.

Costs associated with these service reliability investments will be recovered through Distribution System Improvement Charges (DSIC) on monthly electric bills. The bill impact in 2020 for a residential customer using 1,000 kilowatt hours (kWh) per month will be $0.64 both for Met-Ed and Penelec customers, $1.34 for Penn Power clients and $0.44 for West Penn Power customers.

Uzbekistan, which borders large oil and gas producers Kazakhstan and Turkmenistan, has substantial hydrocarbon reserves but is not a massive developer yet. Future upstream developments could help source domestic natural gas for power generation, which would lower electricity costs and help facility growth of energy-intensive industries.

The Talimarjan Power Complex, situated some 440km southwest of Tashkent, was built at a cost of $819 million and commissioned in 2004 as an 800 MW gas-fired unit. In 2018, the combined-cycle plant was expanded by two additional 450 MW gas turbines which pushed total capacity to 1,700 MW.

Now, the Mubadala accord with JSC is looking to further expand of the CCGT. Commenting on the agreement, Mubadala’s utilities director, Mohammed Alhuraimel Alshamsi, said: “The Talimarjan Power Complex comprises of 1.7GW of existing gas-fired conventional power, with a plan to further expand the complex to accommodate the growing power demand of the nation.”

Mubadala, CEO Khaled Al-Qubais hailed the deal as one of the first privatizations in Uzbekistan’s conventional power generation sector utilizing the Independent Power Producer (IPP) model. “We hope this is the first of many partnerships with the Republic,” he said.

Costs of batteries have fallen by over 80 percent since 2010, largely thanks to technology improvements, which render energy storage increasingly attractive for utilities to complement wind and solar PV installations. Around 70 Gigawatt-hours (GWh) of battery cells were used last year for electric cars worldwide, while 8 GWh of stationary batteries were added to provide flexibility in the power sector.

Cheap batteries could curtail coal power

“If the costs of battery storage systems were to fall below one-third of today’s level, investment decisions in new power capacity would change considerably, especially in India,” IEA analysts pointed out. In this Cheap Battery Case, power generation capacity from coal could plateau in the 2030s without compromising system reliability or the affordability of electricity. In India alone, solar PV capacity could reach 800 GW by 2040.

“This would ultimately result in India’s power-related CO2 emissions starting to decline just after 2030 and would also reduce outdoor air pollution,” analyst said, noting the positive effects on peoples’ health and life expectancy.

For the “Cheap Battery Case” to happen, battery system costs would need to decline much more quickly than the recent pace of cost reductions. This would be possible if improved battery chemistries enter the market, further lowering the floor costs of batteries. Also, economies of scale in manufacturing and learning-by-doing would be essential to further drive down costs.

Hybrid power, the preferred flexibility option

Looking ahead, the IEA estimates over the next two decades growth in batteries will out outstrip that of any other flexibility option available to electricity systems. In India, investment in solar PV in 2018 was greater than in all fossil fuel sources of electricity generation combined.

Hybrid power systems, combining batteries with solar PV, “appears to be one of the most cost-effective ways of helping provide affordable electricity to isolated communities,” analysts noted. Hereby, batteries increase the value and competitiveness of solar PV by storing the electricity produced during sunny periods and feeding it back to the grid at another time.

Researchers at VTT focus on energy storage as a means to overcome bottlenecks in renewable power systems.

Research by the team at VTT has studied gas powerstorage at three distinct scales - KW, MW and Terrawatt (TW). The first stage covers smaller house-hold devices and storage units at this scale are already commercially available. The MW scale projects are expected to start appearing within the next year paving the way to TW storage systems designed to meet the needs of national utilities.

”We aim at showing how storage technologies can balance the electricity grid, and how they mobilise the transport sector. We have a concept ready for the Terrawatt-scale unit,” said Pasi Vainikka, principal scientists at VTT. ”In modelling we would have a platform that can be used in designing an energy system with mobility and electricity grids merged and with large storage infrastructure in place.”

Looking further into the future the team are modelling systems that are entirely renewable, where gas used to store energy is created artificially from excess solar power. This would greatly reduce the environmental impact of gas power generation as there are no extraction or transportation costs.

Natural gas favoured over hydrogen in short term

The driver behind all of this research has been to understand the economics of widespread renewable penetration. As a result the benefits of hydrocarbon based energy storage are more apparent. While there is a range of promising technology focused on hydrogen power generation the costs quickly spiral when TW-scale storage systems are considered.

“We concentrate on hydrocarbons. Why? Because if we really want to do something about climate change by, say, 2030 one would need TerraWatt-hours to move very soon and while hydrogen is nice there are currently no capabilities to store 1 TWh hydrogen if it falls in your lap tomorrow,” Vainikka said, adding that in our existing hydrocarbon infrastructure “it is possible.”

VTT predicts that the technology under development today will largely be complementary to the integration of electricity grids, particularly, in the EU. This is expected to have major strategic impact to energy security, feasibility of solar and wind, as well as energy storage access.

The state of California has recently mandated operators to provide 1.3 GW of energy storage by mid-2020 to strengthen the grid. Converting excess power to gas has a number of advantages, not least the wide availability of existing gas pipelines and infrastructure.

Gas turbines, used of oil and gas upstream, are in high demand as the power needs in the offshore platforms and for remote exploration. Gas turbines used for mechanical drive is will witness highest growth during, according to reportlinker.

By turbine size, the ‘1-20 MW’ turbine will likely remain the largest segment due to its wider application area but the turbine size ’20 MW and above’ will see the highest growth. High efficiency as compared to smaller turbines is driving growth of this segment, analysts noted.

High growth, high spend in Permian and Bakken Shale

North America is likely to witness the highest growth through 2024 due to growing investment in unconventional oil and gas facilities. The U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020.

The Permian region, spanning across western Texas and eastern New Mexico, remains the most prolific crude oil production growth region in the United States. Favorable geology combined with technological improvements have, according to EIA analysts, contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential.

Permian crude oil production is seen average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian region will produce an average of 5.6 million b/d. The Bakken region in North Dakota, meanwhile, is singled out as second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year.

Analyst's U.S. crude oil production forecast is based on the West Texas Intermediate (WTI) price forecast in the January 2020 STEO, which rises from an average of $57 per barrel (b) in 2019 to an average of $59/b in 2020 and $62/b in 2021.

Liquid ammonia is easy to transport and a substantial supply chain already exists. “We cannot manage the energy transition with electrification alone. Molecules will play a huge part (…) and we can produce those molecules in an increasingly green way.”

Storing surplus renewable energy as hydrogen or ammonia is more lucrative than curtailing the capacity of offshore wind and solar at times of peak production. Green hydrogen is deemed to become the “backbone of future, largely decarbonized power generation,” a Siemens white paper finds. This is because chemically stored electrical energy is, to date, “the only way to overcome renewable sources or times where there is little or no wind or sunshine.”

Switching from coal to NH3

Japan already retrofits existing coal plants to run with ammonia, a hydrogen liquid, NH3. “You can use carbon capture and storage to produce ammonia, or even use renewable sources to create hydrogen and ammonia,” explained says WEC Secretary General, Christoph Frei.

“It’s important that we go for solutions that are the easiest to implement,” he stressed. Hence, it’s vital to couple the renewable energy sector with the gas infrastructure through Power-to-X.

Half of the world’s capital is invested in energy and related infrastructure. “So rather than kill the molecules, we better see them become green as well,” Mr. Frei said, pointing at electrolysis as a process to generate green hydrogen from excess wind and solar power.

Counting capacity factors and costs

Production costs for renewable energy have fallen drastically as technology advances. Levelized costs of electricity (LCoE) for onshore wind power will soon fall below $20/MWh in the U.S. and Mexico, and similar low prices can be achieved for solar power in northern Australia and the Saharan Africa and Saudi Arabia.

With cheap renewable energy and up to 6,000 full-load hours of wind or solar PV installations for some locations, green hydrogen generated from electrolysis can already compete with grey hydrogen from steam methane reforming (see graph).

Considering today’s prices for hydrogen at fuelling stations, e.g. in Switzerland, green hydrogen would make a positive business case, a Siemens white paper finds.

"Transmission grid operators are committed to also using the existing gas infrastructure for hydrogen. We are working at full speed on concrete technical and network planning solutions to ensure that the integration can be successful," FNB Gas head Ralph Bahke told the German business daily Handelsblatt.

More than 90 percent of the hydrogen grid planned by the operators is based on the existing network used for transporting natural gas. The hydrogen grid would also allow for the import of hydrogen via ships or pipelines.

Natural gas will continue to play a key role in electricity generation, heating, and industry for many years to come in Germany. But because the country aims to be climate-neutral by 2050, most experts believe it will be gradually substituted by hydrogen, which could eventually become carbon-neutral if made with renewable power using electrolysis.

The German government plans to present its highly anticipated plans for a "hydrogen economy" in the coming weeks.

Steel and chemical industries are also betting heavily on the use of green hydrogen in their long-term decarbonisation plans. Because the making of green hydrogen is extremely energy-intensive, Germany will likely have to import large quantities from countries better suited for renewables generation in the future.

Production will still continue to grow as rig efficiency and well-level productivity rise, offsetting the decline in the number of rigs until drilling activity accelerates in 2021. That year, production is forecast to 13.7 million b/d.

In the Lower 48 states, crude oil and associated gas production has a relatively short investment cycle. Output alterations typically follow changes prices and rig counts with about a four- to six-month lag.

The West Texas Intermediate (WTI) crude oil price forecast in the January 2020 Short-Term Energy Outlook (STEO) rises from an average of $57 per barrel in 2019 to an average of $59/b in 2020 and $62/b in 2021.

Permian and Bakken Shale to lead growth

North America is likely to witness the highest growth through 2024 due to growing investment in unconventional oil and gas facilities. The U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020.

The Permian region, spanning across western Texas and eastern New Mexico, remains the most prolific crude oil production growth region in the United States. Favorable geology, combined with technological improvements, has contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential.

Permian crude oil production is seen average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian region will produce an average of 5.6 million b/d. The Bakken region in North Dakota, meanwhile, is singled out as second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year.

Despite a rise in equipment deliveries and service volumes, Wärtsilä’s operating result was “well below the previous year,” Mr. Eskola noted. For the January to December period, the operating result fell to 457 million Euros, or 8.8. percent of net sales which remained stable at 5,170 million Euros.

Cost overruns due to inaccuracies

Performance in Q2 was weakened by cost overruns in a handful of complex marine and energy projects. These were caused by “inaccurate assumptions in cost estimates, insufficient risk identification, and supplier related challenges,” the Wärtsilä CEO admitted.

Order intake picked up picked up in the fourth quarter, but was not sufficient to raise the order level to that of the previous year.

Demand for new, gas and liquid fuelled power generation capacity declined significantly during the year, as macroeconomic uncertainty and the ongoing energy transition delayed investment decisions. While equipment orders were “well below” that of the previous year, energy services orders “developed well,” thanks to a record high order intake for service agreements.

Bracing for challenges ahead

Looking ahead, Wärsilä expects challenging times to continue during the upcoming year. “For this reason, we remain cautious on the demand outlook,” Mr. Eskola stressed.

“Our focus will be on improving operational efficiency and on optimising our portfolio, with the aim of mitigating the near-term headwinds related to pricing and mix to the extent possible,“ he cautioned. “Delivery of the projects affected by cost overruns will also weigh on our performance.”

Earnings per share fell to 0.17 Euros compared to 0.25 Euros a year ago, below the profit of 0.28 euros expected by analysts in a Refinitiv poll.

Although coal's share of China's energy budget is supposed to drop to 52 percent by 2030 in favour of renewables, nuclear power, and natural gas, the amount of coal burned — not only for electricity generation, but also for the production of raw materials for industry —is expected to continue increasing, according to Siemens projections.

Gasifying powdered coal at high temperature

As a leader in efficient, low-emission technologies, Siemens helps to develop and commercialise coal gasification. It is an established technology based on a simple principle: powdered coal – in other words, almost pure carbon – is gasified at a high temperature together with oxygen. The result is a synthesis gas of hydrogen and carbon monoxide. Using water, the carbon monoxide is converted into carbon dioxide and hydrogen.

Integrated gasification combined-cycle (IGCC) plants use this process to supply high-purity hydrogen that can be mixed with natural gas in a gas turbine to produce electricity. "Here, CO2 has already been separated out, and rather than being released into the atmosphere, it could be injected into an oil field to increase its yield, for example," a Siemens engineer said, explaining:

"Electricity generation would then be almost entirely CO2-free – a goal that will be achieved by an IGCC plant under development in the USA: the Texas Clean Energy Project." That plant is expected to produce electricity and fertiliser with gas turbines supplied by Siemens, while the CO2 is injected into an oil field.

IGCC suited for generating electricity & producing chemicals

Power generation is one way to use the IGCC project, but it can also be used to produce chemicals for industrial purposes.

"It is the ideal way to use different carbon-containing fuels like coal, refinery waste, and even organic waste to produce many different materials — "basically, anything that contains carbon," said Frank Hannemann, head of Technology and Innovation at Siemens Fuel Gasification Technology GmbH in Freiberg, Germany.

"Plastics, methane (natural gas), methanol, diesel, fertilizer – there are almost no technical or chemical limits to what can be produced from coal," he suggested.

5x500 MW coal gasifier built in Ninxia

In China, most coal reserves are located in remote regions like the northern Chinese steppe where there are very few customers for electricity. Together with coal-mining company Shenhua Ninxia Coal Group, Siemens has built a coal gasification plant near the Mongolian border. The plant has an output of 5 times 500 megawatts.

For the five fuel gasifiers at the plant, Siemens is using an advanced design with a pneumatic coal conveyance system and full quench design which require less high-pressure steam to convert the carbon monoxide it generates into hydrogen, he explained, stressing "all of these features result in greater efficiency and lower CO2 emissions."

The team of Dehui Wang, Technical Manager at Siemens Corporate Technology in Beijing, supports Mr Hannemann R&G group. Using an experimental plant to study the chemical reactions that occur when hot synthesis gas is cooled, Ms Wang's team has contributed to a new type of shift process that uses water to convert carbon monoxide into carbon dioxide and hydrogen.

Developing advanced gasification processes in China

Based on Clariant's catalyst, a two-step CO-shift process is being used, with an inhibiting catalyst in the first step. The catalyst slows down the reaction, causing only a small portion of the gas to be converted in the first step. The complete reaction takes place in a second step using a state-of-the-art catalyst.

"What gives this solution an edge over other approaches is that, because the process is slowed down, it requires less steam for cooling the hot gas (which has a temperature of up to 1,400 degrees Celsius), and that makes it more efficient overall," Ms Wang pointed out.

Together with Siemens' Fuel Gasification Business Unit, she is now looking for a customer in China to demonstrate this new technology.

"The facility sets new standards for efficiency," she said but cautioned "it isn't quite as environmentally friendly as it could be." The CO2 is removed, but it is not stored underground. Shenhua Ninxia Group considers this to be too uneconomical and still releases its carbon dioxide into the air.

“The expansion of natural gas and LNG can be expected to contribute to cleaning and diversifying energy supply and reducing Asia’s dependence on energy imports from the Middle East,” said Ken Koyama, IEEJ chief economist and managing director.

Japan is set to remain the world’s No.2 LNG importer, after China. So, the Japanese market still provides ample opportunities for LNG sellers, particularly as existing contracts expire. Japan’s LNG imports are expected to remain above 70 mmtpa through much of the 2020s, and may even exceed 60 mmtpa until at least 2040.

Price is, however, still a big issue. Koyama stated that pipeline gas and LNG were not necessarily the perfect energy source and the biggest challenge remained how to make them more price competitive, more affordable, more attractive and easier to be selected as preferred energy. 

Energy security that has become a major matter of concern because of Asia’s growing dependence on energy imports. “Substantial energy demand growth makes it important for Asia to tackle environmental problems. A particularly important problem involves Asia’s structurally high dependence on fossil fuels including coal,” he stated.

Dirty king coal

Across Asia, thermal coal accounts for around 48 percent of the primary energy consumption, far higher than the global average at 27 percent. “Coal has become a main energy source in Asia, including China and India, as large energy consumers because coal has been locally abundant and price competitive in Asia,” the IEEJ report reads.

Massive coal consumption has boosted carbon emissions and air pollution, which directly caused serious air pollution as an urgent, grave environmental challenge.

China, India and Southeast Asia are expected to boost energy demand and will face a rise in their dependence on energy imports, particularly oil purchases from the Middle East,” it explained.

“The Middle East for its part must give priority to the Asian market as its dependence on Asia increases,” said Mr. Koyama’s report said, concluding; “In this sense, Asia and the Middle East will grow more interdependent.”

Diagnosing operations of Indonesia's power plants through artificial intelligence (AI) and big data analysis is meant to enhance efficiency. To that end, MHPS and the ITB seek to establish a joint research and development base in Indonesia.

“Through this joint research, not only will we develop new technologies for clean energy, but also we will improve the performance of existing power plants in Indonesia through big data analysis and Artificial Intelligence (AI),” said MHPS President and CEO Ken Kawai.

ITB, one of Indonesia's leading national universities, as a total of 12 faculties and schools in fields including industrial technology, mining and petroleum engineering, mathematics, as well as art and design. Situated in Bandung, the capital city of West Java province, it has a student body of roughly 22,000.

MHPS has provided thermal power systems and generating equipment to Indonesia for more than 50 years. Looking ahead, the Japanese company seeks to help enhance Indonesia’s energy efficiency and available energy supply. Through the new initiative, the company will also promote the conversion to low-carbon energy sources.

On Java, MHPS some sixteen month ago commissioned the 300 MW unit-2 of the Tanjung Priok combined-cycle power plant ahead of schedule. Unit 1 of the Jawa-2 project initially went into operation as a simple gas turbine system this June with output nearing 300 MW, and Unit 2 doubled that capacity to 600 MW. In Indonesia, MHPS claims to hold the top market share for large gas turbines, with a total power gen equipment supplied reaching 12 GW.

Focus on CCGT/ICGT conversions to hydrogen co-firing

In 2020, MHPS pledged to focus on decarbonization by promoting fuel conversions to biomass, hydrogen and ammonia. CEO Kawai anticipates “further growth” for combined-cycle gas turbine orders to help convert CCGT and ICGT units to hydrogen co-firing.

In the area of steam power, MHPS will strive to improve the performance of existing boilers, push for fuel conversion including biomass and ammonia co-firing. By promoting plant upgrades, notably the replacement of CCGTs and IGCC (integrated coal gasification combined cycle) systems with hydrogen-co-firing, the Japanese turbine manufacturer wants to help utilities reduce carbon emissions to meet more stringent environmental regulations.

Aiming for 100% hydrogen-fuelled power

MHPS has already successfully tested a large-scale turbine that runs on a 30% hydrogen fuel mix, combined with natural gas. That turbine reduces CO2 emissions by 10%, compared to a standard natural gas-fired plant. As a pilot project, MHPS is now working to convert a combined-cycle gas turbine at Vattenfall’s 440 MW Magnum power plant in the Netherlands to run solely on hydrogen by 2025.

Optimizing solid oxide fuel cells (SOFC) for distributed power systems is another technology focus, whereby MEGAMIE, one of MHPS’s hybrid generating systems, combines SOFC and micro gas turbines. The technology has been in commercial operation at the Marunouchi building of Mitsubishi Estate since March 2019, supplying electric power and heat.

After 2045, renewables will generate more electricity than gas-fired power plants, according to the government’s Annual Energy Outlook (AEO2020). Overall the United States is seen adds 117 gigawatts (GW) of new wind and solar capacity between 2020 and 2023, as renewables grow faster than overall electricity demand.

Meanwhile, gas-fired generation retains its market share while coal and nuclear generation continue to decline.

“We see renewables as the fastest-growing source of electricity generation through 2050 as cost declines make them economically competitive beyond the expiration of existing federal and state policy supports,” noted U.S. Energy Information Administration (EIA) head Linda Capuano.

Coal power units – retrofit or retire

Although coal-fired and nuclear generation decline through the mid-2020’s as a result of retirements, generation from these sources stabilizes over the longer term as the more economically viable plants remain in service. Going forward, coal-fired plants must either invest in heat rate improvement technologies by 2025 or retire to comply with the Affordable Clean Energy (ACE) rule.

At projected Reference case prices, natural gas-fired generation is the marginal fuel source to fulfill incremental demand and increases in the later projection years, averaging 0.8% growth per year through 2050.

Electricity demand growth is seen average at 1 percent which is dampened through energy efficiency measures and higher self-generation through rooftop photovoltaic. The transportation sector still accounts for only a very small percentage of economy-wide demand because electric vehicles are still a minute, though growing market. According to EIA analysis, miles driven by e-vehicles would need to increase “substantially,” for e-cars and e-trucks to raise electricity demand by §more than a small fraction.”

Production of natural gas grows at a faster rate than consumption in most cases after 2020, leading to an increase in exports. Continued development of tight oil and shale gas resources in the East and Southwest regions, U.S. crude oil production is seen to set annual records through the mid-2020s while natural gas production will keep growth through 2050.

However, dry gas production is seen grow just 1.9 percent from through 2025, which is considerably slower than the 5.1 percent growth rate in the five years running up to 2020.

Shut-in of US LNG production on the cards

Rampant US gas supply has been outpacing demand growth for the past year, slashing prices in Europe and Asia. Some US exporters are considering shutting in production as record low gas prices at the Dutch TTF hub challenge the profitability of liquefying and shipping gas to Europe.

Prices at the Dutch TTF gas trading have averaged $4.5/ MMBtu in 2019 but would have to drop below an average of $3.8/ MMBtu through 2020 to balance the market. “Our forecast touches back down to the low US$3/million Btu range during the summer. The risks to price remain heavily weighted to the downside,” said Wood Mackenzie’s director, European Gas, Murray Douglas.

Yet, shut-ins of US gas production is still unlikely at this point - given the political clout surrounding American gas exports as well as the importance and competitiveness of Henry Hub-indexed supply for global markets. American LNG supply is gearing up to make up 46% of Atlantic Basin trade by 2022.

Over the summer, the British and European LNG marketplace is expected to become “increasingly congested. Hence, some infrastructure constraints will likely surface and place further downward pressure on hub prices. This will become particularly acute in the UK during summer where regas utilisation will be capped at 75%, assuming Norwegian pipeline deliveries follow historical trends.

Market observers doubt that Chinese LNG importers will exercise ‘force majeure’ at this point in time. “So far, the virus’ impact on the real economy is not moving the market yet,” LNG Unlimited Data analyst, Alex Wilk said, pointing instead to oversupply and the climb-down from a high-demand period in December. “What we see regarding price is traders cutting their risk exposure,” he noted, “rather than a slump in real demand.”

S&P Global Platts cautioned it might take time for to justify this virus outbreak as force majeure. “While it might affect a buyer’s ability to fulfill its contractual obligations, most of the long-term contracts have an annual volume commitment that can be postponed to later in the year,” analysts said, suggesting “it might be early for Chinese companies to justify and obtain reliefs from performance.”

Energy demand "greatly affected" by coronavirus outbreak

Chinese LNG offtakers are apprehensive amid uncertainly of how quickly the virus can be contained. “Demand for LNG will be greatly affected,” one end-user told Platts. “There is a decline in residential gas demand, gas power generation and traffic. If the epidemic lasts until May, I think the LNG growth rate will be a single digit.”

If and when Chinese LNG importers will resort to using ‘force majeure’ certificates, they would be obliged to provide proof of delivery delays or cancellations, sales contracts or agreements, as well as customs declarations. Traders indicated Chinese gas buyers might try to delay February cargo deliveries due to a downbeat demand outlook as impacted as millions of Chinese citizens are quarantined which heavily impacts the domestic economy.

Economic fears, sparked by the fast-spreading coronavirus, now outweigh the positive news of the phase-1 trade deal between the United States and China, whereby Beijing committed to purchase an additional $52.4 billion of energy products from the United States, including oil, coal and LNG.

Drax stressed it did not accept agreements for its two coal unit at Drax Power Station or the small Combined Cycle Gas Turbine (CCGT) at Blackburn Mill and will now assess options for these assets, alongside discussions with National Grid, Ofgem and the UK Government.

A new-build CCGT at Damhead Creek and four new-build Open Cycle Gas Turbine projects participated in the auction but exited above the clearing price and did not accept agreements.

The 3,906 MW Drax Power Station at Selby, North Yorkshire, has largely been converted from coal to natural gas and wood pellets as the government sees to exit coal by 2025 at the latest. Drax’ remaining coal-fired power units have capacity contracts through to the end of September 2022.

Will Gardiner, CEO of Drax Group, conceded earlier the likelihood of the last coal-fired units at Selby running “past 2023 is extremely low”.

Coal not to pitch into T4-auction

Looking ahead, Drax now prepares for the T-4 auction, due to be held in March, which covers the delivery period from October 2023. However, Drax noted it does not expect to sign a capacity agreement for its coal-fired power assets in the T-4 auction. So, early retirement of these assets is on the cards.

Bowing to growing regulatory pressure, several other UK utilities have announced the closure of some of their left-over coal power assets, including SSE’s Fiddlers Ferry unit in Cheshire which is meant to close by March 31.

Fuel costs are another key obstacle for coal power in Britain. Falling capital costs for offshore wind and solar PV, as well as the 2013 introduction of a carbon price support levy has made it increasingly uneconomic to run coal-fired power units. Natural gas-fired units are also burdened by the carbon price, although to a lesser degree.

The UK capacity market is designed to remunerate energy companies for making power generation capacity available at short notice at times of peak demand.

EDF Energy confirmed it secured a one-year agreements, lasting from October 2022 to September 2023, for 12 nuclear power units with a total of 5.9 GW of capacity as well as three gas-fired blocks at its West Burton power plant and two battery storage units.

However, the utility failed to secure capacity contracts for its nuclear units at Hinkley Point B nuclear power unit. "Although Hinkley Point B entered into the auction and we are confident it will operate to its scheduled closure date of 2023, it exited above the clearing price and therefore did not get an agreement," EDF Energy said in a statement.

Scotland’s SSE won capacity contracts for nearly 2.8 GW of gas-fired, hydroelectric and pumped storage capacity. But it failed to get contracts for three of its gas-fired power stations. "While our Medway, Keadby 1 and Keadby 2 stations have not been awarded capacity contracts in this auction, this will not impact our existing operations and we will have further opportunities to secure contracts in future auctions," commented SSE’s energy director, Martin Pibworth.

Drax secured capacity contracts for 2,562 MW at the latest T3 auction for existing gas, pumped storage and hydro assets. These contracts, running from October 2022 to September 2023, are priced at £6.44 per kilowatt and worth some £15 million.

Looking ahead, Drax now prepares for the T-4 auction, due to be held in March, which covers the delivery period from October 2023. However, Drax noted it does not expect to sign a capacity agreement for its coal-fired power assets in the T-4 auction. So, early retirement of these assets is on the cards.

In early 2020, Eagle LNG monetized a source of previously stranded gas in the Marcellus field and delivered it as LNG to a New England electric utility where the gas is used for power generation.

Under the latest contract, Edge LNG’s second deal in 2020, it is acting as a service provider at stranded gas wells in Tioga County in Pennsylvania. The name of the owner of the gas wells was not disclosed.

“The Marcellus is an important region for us, there is lots of potential here with a large number of stranded wells,” said Mark Casaday, CEO of Edge LNG. “So much gas goes unharnessed, purely because lack of access to a pipeline has meant there is no economic way to take it to market. We provide operators with an opportunity to profit from wells that would otherwise not be used and we make it into valuable fuel,” the CEO added, calling it a win-win solution.

To tap stranded wells, Edge LNG uses Cryobox liquefaction units, created by Galileo Global Technologies, which can be delivered to any site accessible by road. ““After set-up and safety checks, production can begin within hours, with minimal investment required of the site owner and without the need of pipeline infrastructure,” Edge LNG explained.

The LNG produced from these stranded wells is being purchased by Edge and delivered to nearby customers by truck. A supply deal is also in place with City of Norwich, Connecticut, where the LNG will be regasifed and used in local homes and businesses.

With the U.S. election looming large in November, analysts say it is unlikely that President Trump will facilitate real breakthroughs on trade with China. Russia’s Gazprom might turn out to be the ‘laughing third’ as it strives to ramp up deliveries to China through the new 38 Bcm/y Power of Siberia pipeline.

Beijing strives to diversify China’s gas sources, but the cost of any new supply option matters. Considering the huge expenses of transporting Russian pipeline gas over thousands of miles towards Beijing and Shanghai, analyst deem it “unlikely” that CNPC will want to quickly ramp up gas supply from Siberia at the expense of imported LNG.

Eventually some 8 Bcm/y of Russian gas will be exported to China’s CNPC through the new interconnector, but the competitiveness of PoS gas imports in China is entirely dependent on where it is sold.

Costs hinge on point of sale

Considering the cost of PoS gas into the Yangtze River Delta versus recent LNG contracts, Wood Mackenzie says this is “not a major competitive threat.” Particularly because the Yangtze River Delta is a region that already has six regas terminals, with a further three greenfield projects under construction and two more proposed.

Things look different further north. “In the Northeast, tariffs from the Russian border will only be around $1/MMBtu to reach a city such as Shenyang, making ‘Power of Siberia’ gas attractive against LNG,” Mr. Thompson said. “But to take gas further south to Shanghai will increase tariffs to around $3/MMBtu.”

“LNG doesn’t have this problem. And the world is awash with dirt cheap LNG right now,” he added, suggesting “this will continue over the next couple of years as more projects come onstream.” Moreover, China is rapidly expanding regas capacity and pushing third-party access policies to encourage more participants.

While legacy LNG contracts are the marginal source of supply into China, recent LNG contracting trends are seeing term deals signed around 11% of oil, Wood Mackenzie understands. At this level of oil indexation, new LNG projects would not really have fear Russian pipeline gas into China.

Uncertainty on PoS gas price, future tariffs

Wood Mackenzie’s team of China gas analysts hence argue that the ‘Power of Siberia’ pipeline will take 7 to 9 years to reach full capacity. Analysts in the West, however, have only limited understanding of exactly how the Power of Siberia gas contract is priced and what future pipeline tariffs will be following the establishment of China’s new national pipeline company in early December.

“China’s recent proposals to exclude city-gate prices from national regulations, mean Russian gas prices will be deregulated, potentially encouraging PetroChina to raise wholesale prices (which would also benefit LNG),” Mr. Thompson said. “But what we do know for sure is that even with Russian pipeline gas now in China, LNG is increasingly competitive into China and should continue to play a key role in supplying cleaner energy into this most critical of markets.”