Europe can no longer absorb excess gas supply as economies across the EU juddered to a halt as strict corona containment measures remain in place. An increasingly saturated European gas market has sunk TTF prices today under $2.30/mmbtu.

“Japan will potentially declare a state of emergency as early as today in Tokyo and six other regions. India’s nationwide lockdown is choking energy consumption and raising fears of a humanitarian crisis,” said Wood Mackenzie Asia Pacific Vice Chair, Gavin Thompson.

Shut-ins of uneconomic production, notably at the U.S. Gulf Coast, is hence seen as the last mechanism to gradually rebalance the market. The WoodMac data supports the argument that this should be happening more, but to date, US LNG liquefaction utilisation has been robust despite the economics of much US supply not being supported by European or Asian gas prices.

Bleeding cash

“Any US LNG delivered into Europe this summer in this cost band is bleeding cash,” Thompson said, suggesting this situation cannot go on for much longer.

Even the most efficient liquefaction plant in the US cannot support a negative spread between feedgas costs – highly correlated to Henry Hub – and FOB LNG prices (currently around US$1.60/mmbtu). Prices are now effectively being set by a netback from TTF; however, the discounts from on-the-water US LNG to accessing TTF have increased as utilisation of European terminals has grown.

Imports into Northwest Europe in Q1 were close to 50% higher than the same period in 2019,“ said, stressing: “Any cargoes sold at this price level are effectively distressed.“

The big question is if Henry Hub falls further and pushes US liquefaction back into positive territory. In Thompson’s view that “doubtful,” as current prices are already below sustainable levels and US producers are cutting investment as both oil and gas prices slump. “The likely loss of some associated US gas supply could hurt US LNG producers further,” he argued, “although the impact will only likely be felt by 2021 due to the delayed nature of drilling reductions.”

The influential carmaker lobby group VDA also wants the European Union drop a planned tightening of emission limits on cars. Analysts at the Landesbank Baden-Wurttemberg (LBBW) called relief for carmakers “absolutely necessary,” given that they expect 12 to 15 percent fewer cars being sold worldwide this year, while manufacturers may have to pay 15 billion Euros in fines to the EU for failing to comply with CO2 limits.

EEG levy might rise

Declining wholesale power prices, caused by falling electricity demand, could incur major losses for operators of thermal and renewable power plants. For the latter, this could lead to an increase of the renewables surcharge on end-customers’ electricity bill.

The surcharge (EEG Umlage) might have to rise by seven percent in 2021 to make up for expected losses of about 1.7 billion Euros in surcharge earnings for operators this year, according to estimates by Germany's Chamber of Industry and Commerce (DIHK). The levy currently stands at 6.75 cents per kilowatt hour (kWh).

Any rise in the renewables surcharge should, however, not be passed on to consumers who are already struggling to weather the current loss in revenue as several companies reduced working-hours and pay. Hence, DIHK argues that higher power prices could be cushioned by grants from the state budget.

Plentiful sunshine across Germany has lifted temperatures to 26 degrees this week, providing good conditions for solar PV generation. Combined with wind power from the northern part of the country, electricity from renewables available on the market is now prone to outstrip supply.

“The hours are now increasing in which a high feed-in of renewable energies, especially from wind energy, meets low demand for electricity and leads to negative spot prices,” said enervis analyst Tim Steinert. The consultancy expects the number of hours with negative prices to increase by 80 to 150%.

System lacks power storage

Large-scale power storage is currently not available in the German grid, so the amount of electricity fed into the system and the amount used have to be kept equal to maintain a stable frequency on the grid. When supply outstrips demand, power producer have to pay their wholesale customers to buy the excess electricity, resulting in negative power prices.

Already in March, the German wholesale power market logged about 130 hours of negative prices, mostly during periods of high wind production; that was up from 90 hours in March 2019. Some renewable power producers are not compensated for negative price periods that last more than six hours, so the increase could lead to significant revenue losses.

Spain and California worst affected

Persistently high in-feed of renewable energy supply, which is inherently intermittent, poses challenges for power grid operators especially at times of low demand due to industry lockdowns. In fact, coronavirus containment measures have slashed electricity demand in most countries by around 15%, according to the International Energy Agency (IEA)

In Spain and California, where grid operators have to balance a substantially higher share of variable renewables, the lockdown “fast forwarded these power systems 10 years into the future,” IEA executive director Fatih Birol commented.

“The abrupt slowdown in industrial and business activity across much of Europe has reduced electricity demand, but it is also depriving power systems of a key source of flexibility,” Birol explained. “Under normal circumstances, large-scale electricity consumers such as factories can adjust their usage to help balance the system,” he added, “but that option is hardly open today.”

Technical advancements allow renewables to also provide some degree of flexibility. Wind power can be gradually ramped down when demand drops late at night. Some solar power can be shut off at noon when there is more than needed. The IEA indicated that “in time, electricity generation from renewables may no longer simply follow the weather but will have to be managed in an intelligent way in order to reduce costs and improve electricity security.”

The Poland-wide rollout follows the successful trial of a 450 MHz proof of concept (PoC) network in operation since April 2019. The smart grid supports PGE’s wide-area operations of energy distribution system operators (DSOs) across Poland.

The 450 MHz band has excellent propagation properties, generous power levels, according to Nokia. It is the band of choice for the support of machine-to-machine communications in the energy sector, including smart meters and wireless SCADA connections e.g. with wind turbines. In the future, the network may also manage distributed energy sources, such as decentralized gas generator sets and energy storage.

Poland is keen to digitalize its energy grid in order to integrate more renewables and distributed energy sources, which require ubiquitous, reliable and safe communications, explained Andrzej Piotrowski, Vice-President of PGE Systems.

“The Nokia PoC has demonstrated that it will meet our needs in terms of coverage, service quality, resilience and long-term availability,” he said. Moreover, private wireless networks in the 450 MHz range are applicable for various industries, including energy and telecommunication.

Nokia has over 6,000 employees in country working in our R&D centers, developing 4.9G and 5G technologies. Hence, the Finish manufacturer is well place to support for the digitalization of the Polish electrical grid.

“Our proof of concept, 5G-ready private network has ably demonstrated the superiority of cellular systems for mission-critical and machine-to-machine communications in these energy-related applications,” said Chris Johnson, Vice-President of Nokia’s Enterprise business.

The focus of the work is to define what role hydrogen can play in the future evolution of Uniper’s coal power plants, Siemens stated. Coal-to-gas conversion and subsequent hydrogen co-firing would help substantially reduce emissions at ageing lignite and hard coal-fired plant, allowing extending the life time of these assets.

Net-zero emission by 2035

Complying with the German government’s coal exit plan, Uniper agreed to close or convert its coal-fired power plants in Germany and ultimately all of Europe by 2025 at the latest. Uniper’s coal-exit plan is instrumental for the utility to reach its goal of reducing CO2 emissions in the European generation segment from 22 million tons today to net-zero emissions by 2035.

Today, Uniper already produces around 24 terawatt hours of carbon-free electricity with its hydroelectric and nuclear power plants in Germany and Sweden. Under its new strategy it intends to gradually increase the share of ‘green hydrogen’ in its conventional gas business, in both power generation and energy trading.

Coal-to-hydrogen conversions

“Brownfield transformation” projects, as carried out by Siemens, help decarbonize coal-fired power plants and curb emissions from gas-fired plants, often by adding energy storage solution on site and allowing for hydrogen co-firing.

By building infrastructures for Power-to-X, Siemens is contributing to cross-sector decarbonization. The German manufacturer offers all core technologies for a long-term CO2-free energy supply – from power and heat generation by renewable energies or gas-fired power plants, to power transmission and distribution, to efficient electrolysis for hydrogen production.

Power-to-gas technology makes ‘green hydrogen’ possible has been pioneered by Uniper in its Falkenhagen plant, built in 2013, followed by another one in Hamburg in 2015. Uniper added a methanisation plant to the Falkenhagen plant in 2018 and is now forward cross-sector industrial projects together with refineries and the automotive industry.

“After the coal phase-out and the switch to a secure gas-based energy supply, the use of climate-friendly gas will be a major step towards successful energy system transformation. We are ready to invest, accelerate the decarbonization of our portfolio (…), and act openly in terms of technology by working with partners like Siemens,” said Uniper CEO Andreas Schierenbeck.

“We are only at the beginning,” Siemens board member Jochen Eickholt cautioned. Brownfield transformation and the design of the green hydrogen value chain can show that a CO2-free energy supply is possible and makes sense under real conditions and using existing plants. “Our future lies in hydrogen. This is what we are committed to as a company,” Eickholt underlined.

However, shutdowns in Asia are not over, as the Philippines, Malaysia, India and Thailand just announced more lockdown measures that will impact on domestic energy demand as well as global technology supply chains.

In the US, ports are likely to remain open and site construction could continue but impacts from smaller bill-of-materials equipment and project permitting delays. The time-lag in the coronavirus pandemic and Asia’s early recovery ultimately could give e-car makers in Japan, Korea and China a competitive edge over rival manufacturers elsewhere.

Already today, the Asia Pacific region has the largest share of battery electric vehicle (EV) sales worldwide and sees the highest growth in terms of EV sales, topping 979,000 units in 2019.

In a survey among Southeast Asian consumers, respondents stated that the most motivating and important factors to buy an electric vehicles include better safety standards and the availability of (fast) charging points. In China, the number of publicly accessible fast chargers for electric vehicles now tops 111,000 units while in South Korea, the number of charging stations will reach about 90 thousand by the end of 2020.

Use of e-cars helps reduce air pollution, which is especially relevant in megacities of China and India, where the animal level of particulate matter tops 145 micrograms per cubic meter in Delhi and 75 microgram per cbm in Beijing.

The first cargo will arrive at Tianjin by 29 April, our LNG Unlimited shipping tracker shows. Delivery of the four cargoes would mark the first successful sale and shipment of LNG from the United States to Chine in more than a year.

Economics of U.S. LNG imports to China have only become attractive again after Beijing conceded to remove the 25% tariff in February. In the face of the covonavirus crisis, the Chinese government announced it would enable buyers to apply for tariff exemptions on 696 types of goods, including LNG. Chinese buyers seeking exemptions from the additional tariffs were advised to submit their application from 2 March, with any exemption granted reportedly valid for one year.

Suppliers fiercely compete on cost

“Still, even with tariff exemptions in place, we believe U.S. LNG would still be more expensive than gas currently available at around $3/mmBtu on the Asian spot market,” commented LNG Unlimited data analyst, Alex Wilk. It is questionable, however, if Chinese buyers can take advantage from cheap spot prices since much of their supply is locked into long-term contracts, particularly with Australian suppliers.

Latest price data published by China’s customs authority indicates the country’s landed LNG price averaged $8.85/MMBtu in March. In Wilk’s view, “U.S. LNG thus still stands a chance of being profitable if costs are managed carefully and LNG remains tariff exempt in China.”

At the same time, Gazprom is supplying cheap pipeline gas to northern China through its recently opened ‘Power of Siberia’ pipeline. The Russian gas giant agreed to supply 4.6 billion cubic meters (Bcm) through the new interconnector in 2020 and ramp the volume up to 16 Bcm by 2022.

Beijing lowers industrial gas prices

As China strives to rekindle its economy, after strict lockdowns in January and February, the government in Beijing lowered gas prices for industrial users. Transport and logistics constraints are also being lifted quickly.

However, these policies are deemed “insufficient to stir a lost-demand recovery and new coal-to-gas switching.” Despite a gradual resumption in economic activity, Wood Mackenzie estimates a full-year gas demand reduction of between 6 Bcm and 14 Bcm in 2020, translating to a 4% to 6% growth in gas demand this year.

Combined-cycle gas turbine (CCGT) power plants tend to be dispatched for peakload power generation but their economics are currently undermined by depressed electricity demand and high availability of renewable energy supply.

With many industries shut, energy use in Germany is forecast to fall 6% while wind and solar power output remains high. Higher wind speeds during week 14, combined with low power prices have resulted in some negative price hours – in Germany and France for the second weekend in a row and also Great Britain.

U.S. heads for recession

As North America is now the epicenter of the pandemic, Wood Mackenzie anticipates a recession through the rest of the year and a particularly strong decline in economic activity and energy demand in the second quarter. Texas is expected to see summer peak 4.6GW below pre-crisis levels, with significant price erosion in the scarcity driven summer months.

Project finance is drying up and new power auction in some Latin American markets have been postponed. ”Already contracted projects, both renewables and gas, are likely to face financing challenges as currencies decline,” analysts noted. “Switching away from oil to gas in Central America and the Caribbean is likely to slow in response to the oil price declines.”

India’s power demand slumps

Looking at Asia, India and Malaysia are experiencing large falls in power demand as a part of lockdowns, while Japan and Singapore are instituting more restrictions but not full lockdown that is disrupting construction and trade in the region even as China continues to make progress.

“Global recession is quickly becoming the base case assumption,” analysts warned. Much will depend on the scope and scale of quarantines, as well as the design of recovery policies. Though exit strategies are debated in Europe, a ‘return to normal’ is still a long way off.

Since OPEC and Russia’s failure to agree on a production restraint in early March, the implications of lockdowns to contain the coronavirus have sparked a crisis in the oil market as prices fell and supply ramped up. Prices of natural gas, widely linked to oil prices with a three to nine month time lag, are starting to feel the impact as well.

The size of the demand destruction took upstream companies by surprise, squeezing revenues and putting several wildcatters in the United States at the brink of collapse. In fact, Whiting Petroleum has become the first U.S. upstream company to file for bankruptcy.

Efforts to reverse the price collapse in March

US President Donald Trump was alarmed enough to call for OPEC+ to reduce output. Since then Brent prices have increased from a low of $19 per barrel on 27 March to the low $30s per barrel as of today. This proves, according to Wood Mackenzie, that the OPEC+’s agreed production cut would be very supportive of price over the second quarter.

“A 10 million barrel per day (b/d) reduction may seem small compared with some very high demand loss estimates,” said WoodMac’s vice president Macro Oils, Ann-Louise Hittle. But if the curbs are implemented, “it would slow the build-up in storage and avoid the surplus of supply over the second quarter, when the Covid-19 shutdowns are the extensive and demand lowest. “Even a 5 million b/d reduction would see oil prices in the low $30s,” she noted. “It would ease pressure on storage and stem the steep price collapse we saw in March.”

Other analysts disagreed, saying analysts the lack of an oil price jump in early Asian crude markets indicated the oil output cuts were not enough in the current crisis.

Sharpest demand drops to occur in April

With the pandemic spreading in Europe and North America, containment lockdowns are assumed to remain in place throughout April. Assuming lockdowns get lifted slowly in the following several months, analysts expect world oil demand to fall over 8 million b/d year-on-year for Q2-2020.

“April will see the sharpest drop,” Ms. Hittle noted, forecasting a year-on-year decline of over 15 million b/d as coronavirus containment measures are at their steepest. Notwithstanding, supply from non-OPEC states kept rising this quarter as some U.S. producers take time to shut in rigs and limit output. By July, US Lower 48 oil output it is forecast to be declining at a rate of over 200,000 b/d month-to-month.

“This means Q2-2020 is the most challenging period for producers and the oil market [given that] demand is collapsing and supply is rising,” she warned. But there is a silver lining, as China is slowly ending lockdowns and demand seen picking up.

Starting from the second half of 2020 demand is likely to stabilize, with Asian buyers gradually soaking up the extreme oversupply seen in the first half of this year. In Ms Hittle’s view, “demand will still be down, year-on-year, but the decline will not be as steep as in the second quarter and supply will start to weaken.

Markets hoped to reverse next year

As for 2021, Wood Mackenzie is forecasting total global supply, including OPEC, non-OPEC, and natural gas liquids, to show no growth for year. Demand, while weak, is projected to rise in 2021 – a sharp reversal from 2020 when demand falls and supply rises.

Production drilling is in full swing at the Kovyktinskoye field in the Irkutsk Region. Seven drilling rigs are currently in operation, and their number is going to be raised to 18 next year, Gazprom announced, indicating there will be plenty of supply to ramp up ‘Power of Siberia’ gradually to 38 Bcm per year, as planned, by 2025.

To boost gas exports to China, Gazprom is striving to complete the second compressor station on the ‘Power of Siberia’ pipeline this autumn. Construction of the pipeline section between Kovyktinskoye and Chayandinskoye will also start in the third quarter of this year.

Amur GPP almost two-thirds complete

Progress on the Amur Gas Processing Plant (GPP) construction project is at 58 percent complete. With a design processing capacity of 42 Bcm/year, the Amur plant will be essential to ramp up throughput of the China interconnector.

Installation of the core equipment of the first and second production trains is nearly finished, Gazprom noted, and said equipment is being prepared for start-up and commissioning. Meanwhile, gas separation equipment is being installed on train three and four.

To power the Amur GPP, Gazprom is building a new 160 MW combined-cycle power station called Svobodny TPP which is scheduled to start up in late 2020.

New focus on Northern Gas Corridor

The Russian arctic, notably the Yamal Peninsula is another key focus of Gazprom’s upstream efforts. This strategic oil- and gas bearing region has explored gas reserves of 16.7 trillion cubic meters, where Gazprom seeks to achieve an annual output of 310–360 billion cubic meters of gas. To this end, 52 new gas wells will be brought onstream at the Bovanenkovskoye field as well as a connecting pipeline, stretching to the Kharasaveyskoye field. 

Eager to expand the northern gas transmission corridor, Gazprom is setting up compressor stations and workshops at the Bovanenkovo– Ukhta 2 and Ukhta– Torzhok 2 gas pipelines. Supply from the northern gas corridor can be transported westbound and partially serve as a feedstock for the Nord Stream 2 pipeline.

The start of commercial operation of the Sylhet CCGT increases Bangladesh’s overall electricity output by 640 million kWh per annum, helping to meet the rising power demand in the country’s industrial eastern region. Sylhet’s hinterland is home to the country’s largest gas fields, allowing the power plant operator to rely on domestically produced fuel.

Works to retrofit the gas turbine generator technology had been carried out under an Engineering, Procurement and Construction (EPC) contract, awarded by the plant operator PDB. Shanghai Electric noted it had been chosen to carry out the plant conversion after having “built solid experience through overall five projects in Bangladesh so far since 2002.”

Leveraging GVPI technology

As part of the upgrade, the power plant has been equipped 100 MW global vacuum pressure impregnation (GVPI) air-cooled generator which helped increase the plant’s capacity by 90 MW. It also improved the efficiency of the original plant's simple, open-cycle application from 33% to 55%, Shanghai Electric noted.

“We are always looking ahead to anticipate the client’s needs and improve the availability, reliability and efficiency through a customised solution designed for different regional markets,” said project chief engineer Wang Yi.

In the eight years prior to the upgrade, the plant has provided 8.19 billion kWh of electricity to Bangladesh’s national grid and this figure is estimated to increase by 640 million kWh on an annual basis.

Sylhet was Shanghai Electric’s fourth EPC project in Bangladesh, initiated under the "One Belt One Road" Initiative, following the Barapukuria thermal power plant. During the construction period, the Chinese developer hired 500 local workers.

Whiting Petroleum became the first U.S. upstream company to file for bankruptcy on April 1. Others are not far off, notable Chesapeake Energy and Denbury Resources which also hired debt advisors.

Smaller U.S. oil and gas producers, also known as wildcatters, have been heavily reliant on banks for liquidity over the past twelve month, as debt and equity finance options dried up. Lender have been conservative in valuing hydrocarbon reserves used as collateral, but the recent slump in oil prices have left them worried that some producers are close to bankruptcy.

Alta Mesa Resources and Sanchez Energy are two out of a bunch of energy companies at risk. Should the former go bust, banks are understood to get less than two-thirds of their loans, while a bankruptcy of Sanchez Energy could leave them empty-handed. Hence, some banks are hinting they will foreclose on an energy company and its properties if they do not repay their loan.

Banks could manage fracking firms for one year

By retaining such distressed companies temporarily in separate holdings, banks can avoid having to sell the assets for cheap. Instead, lenders could manage these indebted energy companies until oil prices recover enough so that the assets could be sold at a higher value.

However, banks would have to get a regulatory permission to realize their plans because of limitations on their involvement with physical commodities, sources told Reuters. By holding the assets for only one year, banks are hoping to comply with current Federal Reserve rules.

These day, the banks are understood to set up holding companies to bundle limited liability companies (LLCs) containing the distressed and seized assets. These LLCs would be held proportionally by the banks and financiers that handed out the original secured loan.

The latest order win form Baotou Steel Group is the third expansion of the company’s onsite power plant. Shipments of related equipment to China are planned to begin in 2021.

Making effective use of a by-product

Gas emitted from the coke oven and blast furnace gas (BFG) is a by-product of steelmaking, which can be used at near zero fuel cost for power generation while reducing emissions. However, BFG has a lower calorie rating than natural gas, so advanced technology is needed to ensure stable combustion of the gas turbine.

To this end, MHPS developed special combustors already back in the 1980s and now offers proprietary BFG-fired combined-cycle power generation technology. Various pilot projects have been put in place for steelworks in Japan and around the world, which give MHPS a 60% market share for these turbines.

BFG-fired combined-cycle generating units are made of a gas turbine, heat recovery boiler, steam turbine, power generator, gas compressor, and auxiliary equipment. MHPS said it will manufacture the M701S (DA) X series gas turbines at its Takasago Works in Hyogo Prefecture, and use generators made by Mitsubishi Electric Corp.

Baotou Steel Group, established in 1954, produces iron, steel, rolled steel products, and rare earths. MHPS has already supplied the steelmaker with BFG-fired combined-cycle power generating units for expansion projects in 2005 and in 2012. Two 150 MW class units were delivered and installed at each CCGT project.

The Chinese steelmaker said placed the latest order with MHPS based on the “strength of its record of technological accomplishments, performance and high reliability.”

The current pandemic and related containment measures greatly change the pattern of electricity usage, which is observed hourly by the U.S. Energy Information Administration’s (EIA) Hourly Electric Grid Monitor.

Several regional transmission organizations (RTOs) and independent system operators (ISOs) have reported less electricity demand and a delay in the morning increase (ramp) in the past few weeks as schools, workplaces, and businesses have closed to slow the spread of coronaries.

The the New York ISO (NYISO) reported that “from 6 to 10 a.m., a time when energy use typically ramps up as New Yorkers arrive at work, we are seeing a delay in the timing of the ramp and a reduction in usage of 6 to 9% relative to typical load patterns. That means energy load is increasing later in the day than normally expected and remaining at a lower level.”

Data from Seattle City Light (SCL), near where the first confirmed case of COVID-19 in the country occurred, and Portland General Electric (PGE) show a similar delay and flattening of the typical morning ramp in recent weeks.

In normal times, the electricity demand in the U.S. s highest in the summer, which has a distinct single-peak load shape, and winter demand typically has separate morning and evening peaks. Spring and fall demand can be particularly volatile when temperatures swing significantly from week to week.

The lockdown in India was put in place firmly and forcibly. On 24 March, with only a few hours’ notice, the Prime Minister announced the country’s $3 trillion economy was effectively closing its doors for three weeks.

These drastic measures had an immediate effect on India’s energy market. At its worst, national power demand collapsed by almost a third year-on-year in late March, with thermal coal consumption dropping by a similar level. Oil and gas demand have fallen by around 20% since lockdown began.

Port operators put in place ‘force majeure’ to shield themselves against having to offtake long-term LNG cargoes at a time of plunging demand, although energy is deemed an “essential service” by the government. As per the Essential Service Maintenance Act, refineries, power plants and fertiliser production as well as domestic coal, oil, gas and electricity supply remain operational.

‘Graded relaxation’

Though PM Modi extended the lockdown for at least another 19 days until May 3, he put in place so-called ‘graded relaxations.’ Starting from April 20, key industries will reopen and allow workers to return. Upstream operations, mines and refineries have continued operating with reduced labour and are hoping that an uptick in the economy will help them towards increasing production.

The demand outlook for energy deteriorates despite modest relaxation of the lockdown, Wood Mackenzie cautioned. Previous expectation of a decline in electricity demand of 30% up to mid-April now continues into May before improving progressively after this.

“The reduction in power demand will impact most sources of generation,” analysts said, though it is worth noting that the Ministry of New Renewable Energy has put all renewables plants on ‘must-run’ status (unless affecting grid stability) during the lockdown.

Demand deteriorates in Q2

Things will likely get worse before they get better in terms of energy use. Oil demand continues to be hit by an extended lockdown, analysts noted, and will remain in the doldrums through much of the second quarter. Crude cargoes bought by Indian refiners for processing during April have limited option to be re-sold in such an oversupplied crude market, so these volumes are likely to be diverted into India’s strategic petroleum reserves.

LNG and pipeline gas demand has been severely affected, primarily across India’s transport and industrial sectors. “As a notoriously price-sensitive market, low oil prices are also a competitive threat to gas. High inventories are resulting in refiners further reducing margins for oil products to compete with gas, leading to downside risk on the LNG demand outlook,” analysts commented

With the extended lockdown, thermal coal demand will reduce by 25-30% through April year-on-year and by a further 9% in the second quarter, reducing consumption to 187 million tons in Q2 against the original forecast of 225 Mt. Wood Mack forecasts thermal coal imports now face a downside risk of an additional 5 Mt in the second quarter to 30 Mt.

The three SGT-700Bs will be installed and maintained under a Long-Term Program (LTP) with Ascend, whereby Siemens will perform all scheduled outages. The eight-year LTP also calls for Siemens to upgrade, at the time of the first inspection, the B-series generators to C-series models (35 MW rating) to operate in a cogeneration application.

Phil McDivitt, President and CEO of Ascend called the project “transformational for our company,” given that the new gensets will help meet their future power generation needs while also lowering their emissions.

Commissioning in Q4-2021

The gas turbines will be manufactured in Siemens Gas and Power’s Finspång, Sweden plant in time for project commissioning, which is expected in the fourth quarter of next year.

With 6,500 rotations per minute (rpm), the SGT-700 is designed as a two-stage uncooled free-power gas turbine. It can run at 50 to 105% of its nominal shaft speed, enabling high output and efficiency under a range of operating conditions. Its high exhaust heat and ability to handle sudden load changes, makes the SGT-700 “ideally suited” for simple cycle, combined cycle, cogeneration, and other heating applications, the manufacturer noted.

The turbine’s high exhaust heat will allow Ascend meet their future process steam needs at lower fuel costs than with the previously installed solution. “They expressed that much of the reason they selected Siemens Gas and Power is the confidence they have in us and our product,” said Gabriel Popescu, Vice President of Siemens Energy Oil & Gas Services, North America.

“We have supplied other power generation equipment to Ascend in the past, and we have the manufacturing and logistics expertise to support their future power needs within a very short delivery window.”

Total ordered capacity for J-series gas turbines currently exceeds 25 GW globally, the Japanese manufacturer said. One hundred units have been technically selected in Brazil, Canada, Japan, Mexico, Peru, South Korea, Taiwan, Thailand, and the United States.

MHPS chief executive pointed out the J-series “ran all those [one million] hours with 99.5% reliability. Our extreme reliability is not by good luck,” he underlined. “It is because we test the durability and reliability of every new technological advancement for 8,000 hours before shipping it to our customers.

The first J-series gas turbine was installed at T-Point, MHPS own own combined cycle power plant in Takasago, Japan. The developer now built T-Point e, where the air-cooled 60 Hz JAC, has just synced to the grid and achieved full load.

Aiming for 100% hydrogen capability

The turbine can run on a 30:70 hydrogen and natural gas mix, with full hydrogen capability under development. This makes J-series turbines ideal for retrofits of ageing coal-fired turbines, like at the 1.9 GW Intermountain Power Plant in Utah, U.S.

The plant operator last month ordered two JAC gas turbines that will partly run on hydrogen. The initial 30% hydrogen co-firing will reduce carbon emissions by more than 75%, compared to the same size coal-fired power plant, and the 100% hydrogen system will eliminate emissions entirely.

Compared to the same size coal-fired power plants, one million J-series operating hours has resulted in CO2 emissions reduction of 270 million tons. According to MHPS calculations, this is equivalent to CO2 emissions from 1,346,918 railcars of coal burned.

In Utah, MHPS is developing grid-scale renewable hydrogen production and storage in the city of Delta. MHPS Americas chief executive, Paul Browning, announced: “Going forward, every gas turbine we sell globally will have renewable hydrogen fuel capability. This allows our customers to purchase a natural gas power plant today, and convert it over time into a renewable energy storage facility.”

April’20 clean spark spreads in France (for 49.13% efficiency power plants) were last seen at €-5.30/MWh, while the comparable spread in Germany fell to €-3.19/MWh.

Demand-side shock

On energy markets, the corona crisis is mainly felt on the demand side. As lockdown measures are extended in France and only cautiously loosened in Germany, energy traders expect that power demand will remain subdued and gas peaking plants will barely be dispatched.

The French front-month power price shed 9% on Tuesday following the lockdown extensions, while containment measures in Germany are gradually lifted. The French May-2020 power contract was last seen trading at €15.15/MWh. Total electricity demand in France already plunged by nearly 20% since March 17, when the lockdown was first imposed, and is now likely to fall further.

Sharp fall in gas and EUA price

Spark spreads throughout Europe are impacted by a 33% plunge in the benchmark carbon price and record low prices for natural gas at the European gas benchmark hub, the Dutch TTF. The carbon benchmark Dec-20 EUA contract on March 18 shed 16.44% in value, while the TTF front-month lost nearly 31% over the course of March.

Despite the sharp drop in CO2 prices, the combined-cycle gas power plants are further ahead in the merit order in Germany than rival coal-fired plants, modeling by Energy Brainpool shows. The main reason for this is the likewise sharp fall in gas prices and only a very moderate decline in hard coal prices.

Thermal power plants have higher marginal costs than nuclear or renewables. These days, in fact, wind and solar power cover a rising share of electricity demand which has fallen to record lows due lockdowns to contain the pandemic.

For 2021, Energy Brainpool is assuming a reduction in the average European baseload electricity price of €10.20/MWh, relative to a reference scenario in Q4-2019. “Should there be a recession-related slump in electricity demand, a further loss of an additional €3.60/MWh is conceivable for the year,” analysts concluded.

It will be a partial replacement for the aging 165-MW jet fuel-fired power plant, which is currently on a Reliability Must-Run contract with the California Independent System Operator (CAISO), meaning the Oakland plant is critical for local of power supply.

The battery extension project has been approved by the East Bay Community Energy (EBCE), which agreed to receive the larger resource adequacy capacity from the enlarged battery. Meanwhile, Pacific Gas and Electric (PG&E) approved a new Local Area Reliability Service Agreement, signaling out the project as helpful to ensure grid reliability.

Battery energy storage will play an increasingly key role in the reliability of the electric system, Vista CEO Curt Morgan said, calling the Oakland project “a shining example.” It will provide clean energy to the residents of Oakland, whilehelping the city meet its sustainability goals,” he pointed out.

Looking ahead, Vistra said it will eventually retire the existing units at Oakland Power Plant and develop additional energy storage projects on the site.

Headquartered in Irving, Texas, Vistra is a utility-scale battery developer: its 10-MW/42-MWh Upton 2 Battery Storage Facility came online in December 2018. In California, its 300-MW/1,200-MWh Moss Landing battery project is currently under construction, slated to be complete later this year. When the Moss Landing energy storage system comes online, it will be the largest battery of its kind worldwide.

For the hydrogen conversion, Intermountain Power Agency (IPA) ordered two 1-on-1 M501 JAC power trains, equipped with air-cooled dry low NOx combustion system with hydrogen-rich fuel capability.

Following first fire, the turbines will initially run on a 30:70 mix of hydrogen and natural gas which will cut emission by more than 70 percent compared with the retiring coal-fired unit. In the run-up to 2045, the hydrogen co-firing capability will then be systematically increased to 100%, enabling carbon-free power generation at a utility-scale plant.

Situated in Delta, re-fuelled plant will provide green energy to Los Angeles and municipalities in other parts of California and Utah. It is owned by the IPA and operated by the Los Angeles Department of Water and Power (LADWP).

L.A. mandates green energy conversions

Green hydrogen co-firing is supported by Los Angeles’ 2019 sustainable city plan that envisages to transform the metropolis to 100% renewable power. The state law requires that all retails electricity sales and all electricity procured by state agencies should be zero-carbon by the end of 2045.

Due Los Angeles’ mandated fossil fuel exit, LADWP knows that it will no longer be able to sell electricity from the coal fired Intermountain Power Project (IPP) in Utah.  “IPA knew that the customers for those coal units were going to go away in 2025,” the utility’s spokesman John Ward commented. That year, the plant’s existing Power Purchase Agreement (PPA) expires with LADWP, the plant’s biggest customer. Converting the plant to hydrogen was a precondition for renewing the PPA.

As America’s largest municipal utility, LADWP currently generates 18% of its electricity from coal which is higher than the 3.3 percent in California’s state-wide energy mix. The utility provides electricity to an estimated 1.5 million customers in Los Angeles, and another 5,000 in the Owens Valley.

Making use of excess renewable energy

California has heavily invested in wind and solar power, creating great challenges for power grid operator who cannot handle the excess production of inherently intermittent renewable energy. At times, carbon-free renewable energy units have to be shut down because the grid cannot handle it.

Energy storage, or using that excess renewable energy to produce hydrogen, would greatly alleviate the strain on grid operators. Batteries can currently store electricity for four hours, and even if the technology can be enhanced to eight hours, the required storage footprint would be massive.

Hydrogen, in contrast, can be stored in large quantities in the natural gas network for long periods, and be used for power generation as needed.