This summer, however, the Covid-19 pandemic is seen drive a global contraction in LNG deliveries compared to the previous year. Wood Mackenzie’s Robert Sims said: “This will be the first seasonal contraction in eight years.”

US LNG terminals ‘underutilized’

The pricing dynamics this year are expected to be similar in summer and winter season, with US LNG acting as the price-setter for the cross-basin spread. Prices differentials between the U.S. bellwether Henry Hub and the Japan-Korea-Market (JKM) will determine how much hub-indexed US LNG will be shipped to Asia, in competition with largely oil-indexed supply from Qatar and Australia.

“In general, a return to stronger growth is not expected until mid-2021,” Sims pointed out.

The fact that more than 20 US LNG cargoes had been ‘cancelled’ by contract and tolling off-takers for June loadings is “significant for the market,” he said, suggesting; “This could lead to feedgas going as low as 5 British cubic feet per day.”

“We expect under-utilisation of US terminals to continue for several summer months as margins remain negative for many companies [and] some degree of under-utilisation will now also happen through summer 2021.

Low prices lead to a downward revision in LNG supply which is currently seen across all basins and regions. Only if there will be a “robust rebound in LNG demand from Japan, Korea or India,” then a price correction could begin earlier than previously anticipated, Sims said, which would help “reduce the risk of further US supply reductions next year.”

Chinese industry returns to growth

Fresh out of winter heating season, China is shifting focus to industrial demand recovery. Although none of the force majeure notices were formally confirmed on LNG contracts, China reduced pipeline import growth in Q1-2020 to just 1% year-on-year.

Imports from China’s largest supplier, Turkmenistan, plunged by 2%. Coupled with a low spot price environment, the temporary waiver of US LNG import tariffs and industrial recovery, China managed to increase LNG imports in the first three months of 2020.

Moving into summer, China is now faced with the daunting task of economic recovery. While the 'Blue Sky Defence' policy will continue, Wood Mackenzie says it is unclear whether the government will set specific targets for coal-to-gas switching in 2020.

“Any moderation could reduce gas demand during the heating season. Near-term gas-power demand is risked to the downside as power demand recovery faces macro uncertainty and more coal-fired power plants are being approved,” Sims explained.

As a result, China’s second quarter 2020 LNG consumption is expected to rise 12% to 15 million tons year-on-year.

Indian buyers take advantage of low spot prices

India, meanwhile, has seen LNG consumption jump 19% year-on-year as utility buyers are keen to snap up cargoes at the current low spot gas prices.

However, Wood Mackenzie says this trend is about to reverse as three months of lockdown materially reduces LNG consumption. India’s demand for imported LNG hence is expected to decline 24% to 4 Mt in the second quarter 2020 compared to the same period last year.

In Europe, the impact of lockdowns on total gas demand will be proportionally less because industry over here uses less gas, while gas-burn in the power sector and from residential offtakers were seen “largely unaffected.”

The deregulation of the Japanese power and gas market has caused a shift in the energy landscape and conjured up fierce competition between incumbent energy provider and market entrants. Independent power producers like JFE Steel are rushing to modernize their existing power plants to optimize operations and reduce fuel costs.

“The industry competition is intense, with a lower barrier to entry for new power generation players,” said Satoshi Ogino, manager in the Energy Technology Section of JFE’s East Japan Works. He singled out GE as “best partner to work with to expand the business opportunity for JFE.”

Follow-up order

For GE, the latest order win for a HE upgrade of a Chiba gas turbine comes on the heels of an similar upgrade at the Chiba power plant. Two years ago, the American manufacturer carried out a MXL2 gas turbine upgrade at a GT26 (former Alstom) turbine installed at Chiba, effectively increasing its output by up to 60 MW.

This year, the operator JFE Steel opted for GE’s latest GT26 HE technology to further improve the plant’s efficiency, increase output and improve part-load efficiency. The HE-upgrade will increase the plant’s output by 10 MW, while raising efficiency by more than 1% to similar levels as a F-class combined cycle gas turbine.

The technology behind the GT26 HE upgrade, first introduced in 2019, is partly derived from GE’s flagship HA gas turbine as well as breakthroughs on major component of the GT26 frame—turbine, compressor and combustor. Combined, these enhancements “take turbine performance to a new level,” GE claims, decrease fuel costs while increasing full-load output and reliability.

"Due to the coronavirus-induced crash on electricity markets, the operation of installations is hardly economically viable even at the most ideal locations," green energy provider Naturstrom says.

The company wants operators of wind farms to continue receive "a fraction" of the support payments they were entitled to so far, on average 3.2 cent per kilowatt-hour (kWh). It claims such payments would be feasible at a total cost of about 15 million Euros.

Calls for ‘safety net’

Lower Saxony, Germany's biggest wind power state, is hence calling for a “safety net” in the form of continued payments for wind turbines. These payments should be granted for turbines reaching the end of their 20-year support period to prevent these installations from halting operations which could significantly reduce Germany’s overall green energy capacity.

In an open letter to the Bundesrat, Germany’s federal legislative body, the government of Lower Saxony proposes a fixed remuneration for wind turbines of about 4.4 eurocents per kilowatt hour (kWh) for a maximum of seven years.

"Continued operation of fully functional old wind turbines is much cheaper than replacing them with power plants of any technology before their time," Naturstrom board member Oliver Hummel commented.

Power customers, who pay the surcharge with their power bill, would not face higher costs as long as power prices for onshore wind remain above the fixed remuneration.

Once fully operational, the waste-to-hydrogen plant will produce 3.8 million kilograms of green hydrogen per year - making it the largest plant of its kind worldwide. An average hydrogen-fuelled car an run 500 miles on 5 kilogram of the fuel, and SGH2 Energy specified the hydrogen fuel would come at an average price of $15 per kilogram, making it competitive with gasoline.

Plasma-enhanced thermal catalytic conversion

To extract hydrogen from plastic waste, SGH2 developed a unique gasification process that uses a plasma-enhanced thermal catalytic conversion process, optimized with oxygen-enriched gas. In the catalyst-bed chamber, plasma torches generate temperature of 3500º to 4000º C so that the waste feedstock disintegrates into its molecular compounds, without combustion ash or toxic fly ash.

As the gases exit the catalyst-bed chamber, the molecules separate into a hydrogen-rich biosyngas free of tar, soot and heavy metals. The syngas then goes through a pressure swing absorber system resulting in hydrogen at 99.9999% purity and a small amount of biogenic carbon dioxide.

Cost-competitive production costs

SGH2 claims the production costs of its Solena electrolyzing process will be 5 to 7 times cheaper than green hydrogen and are projected to be US$2 per kg of green hydrogen. Brown hydrogen produced from cheap coal in India also costs US$2 per kilogram. Blue hydrogen — produced from natural gas paired with carbon capture and storage — costs between US$5 to 7 per kg in the US, and $7 to 11 in Europe and Australia.

According to the International Energy Agency, today nearly 99% of the 70 million tons of hydrogen produced each year is gray hydrogen (70%) made from natural gas and brown hydrogen (30%) made from coal gasification.

Green hydrogen produced through electrolysis using renewable power costs US$10 to 15 per kg, depending on availability. However, these transitional electrolysis plants are “expensive,” SGH” claims, given that they often have limited capacity and take a long time to build, if related to new wind farms.

In contrast, SGH2’s stacked modular design is built for rapid scale and linear distributed expansion, at lower capital costs, and on a fraction of the land required for large scale solar and wind farms. Engineering and construction is handled in cooperation with Fluor Group.

Hydrogen cars meant to replace gasoline guzzlers

To commercialize the green hydrogen, SGH2 Energy is currently in talks with all major owners of hydrogen refueling stations in California. The aim is to provide hydrogen to all of the state’s 42 refueling stations and increase that number to 100, and eventually to 1,000 stations.

“The beauty is here, that Lancaster will be using this for transportation but it could also be sued to generate electricity,” said Robert Do CEO of SGH2. Hydrogen can be stored in the natural gas grid or in underground taverns and then used as a zero-emission fuel for multiple purposes.

The major of Lancaster Rex Parris strives to position the city as “the alternative energy capital of the world.” He hailed green hydrogen as a “game-changing technology, saying it “solves the city’s plastic and waste problem by turning them into pollution-free hydrogen.”

Analysts at the U.S. Energy Information Administration said the subdued demand for natural gas will continue through August and keep spot gas prices around $2.00/MMBtu.

Come September, however, demand is expected to recover. “Despite EIA’s forecast of record end-of-October storage levels, we expects that rising demand heading into winter, combined with reduced production, will cause upward price pressures,” the agency said in its latest short-term energy outlook.

Total US consumption of natural gas is expected to average 81.9 billion cubic feet per day in 2020, down 3.6 percent from 2019.

“The decline primarily reflects less consumption in the industrial-sector, which the EIA forecasts will average 21.0 Bcf/d in 2020, down 8.7 percent from 2019 as a result of reduced manufacturing activity,” the report noted.

Dry gas production hits fresh record

US dry natural gas production set an annual record in 2019, averaging 92.2 Bcf per day and the EIA forecasts production will average 89.7 Bcf/d in 2020, with monthly production falling from 96.2 Bcf/d in November 2019 to 83.6 Bcf/d in March 2021, before increasing slightly.

“Natural gas production declines the most in the Appalachian and Permian regions,” the report reads. In the Appalachian region, low natural gas prices are discouraging producers from engaging in natural gas-directed drilling, and in the Permian region, low crude oil prices reduce associated natural gas output from oil-directed wells.

In 2021, analysts see production of dry natural gas in the US average 85.4 Bcf per day. The EIA then expects production to begin rising in the second quarter of 2021 in response to higher prices.

Coal-to-gas switch continues

In the power market, the report forecasts that the share of US utility-scale electricity generation from natural gas-fired power plants will increase from 37% in 2019 to 41% in 2020.

“In 2021, the forecast natural gas share declines to 36% in response to higher natural gas prices,” it said. “Coal’s forecast share of electricity generation falls from 24% in 2019 to 17%  in 2020 and then increases to 20% in 2021.”

Crete’s electricity supply currently relies mainly on ageing fossil power plants that are due for retirement by the end of 2022, so the new power cable is needed to ensure the island’s supply security.

Under the turnkey contract, Siemens will design, supply and install two converter systems at a direct-current voltage of ± 500 kilovolts, as well as gas-insulated switchgear (GIS) substation on Crete. The two converters – one near Athens and the other near Damasta in north Crete – will be linked by a 330-kilometer-long direct-current (DC) power cable.

Transmitting green energy to Crete

Both stations will use HVDC Plus voltage-sourced converters in a modular multi-level arrangement (VSC-MMC) in order to convert alternating current (AC) to direct current and DC back to AC on the other side of the link. This allows Aridne to transmit energy from wind and solar PV, generated on the Greek mainland, to Crete which could help reduce emission by 500,000 tons in its first full year of operation.

“The system combines the advantages of HVDC transmission with benefits like AC voltage control, black-start capability, minimized power transmission losses, grid stabilization and high availability,” said Beatrix Natter, CEO of the Transmission Division at Siemens Energy.

The Greek construction company Terna will handle the installation of the HV distribution systems, carry out all civil works and equipment installations for the HVDC project.

Green hydrogen is an emission-free fuel source, produced by splitting water into oxygen and hydrogen via electrolysis by using wind and solar energy. The electrolysis process is highly energy-intensive, though, hence Germany would have to significantly enlarge its installed renewable energy capacity if it wants to produce the country’s entire hydrogen with green energy.

Industry hence urged the government to take into account all available low-emission forms of making hydrogen, including those using natural gas and CCS.

Converting steel industry to run on hydrogen

Significant investment will be needed to convert Germany’s energy-intensive industries, notably the steel industry, to be powered by hydrogen.

Coinciding with the new strategy, German steelmaker thyssenkrupp said it had expanded its production capacities for water electrolysis to make green hydrogen to the Gigawatt -scale.

“Many countries around the world are currently planning to enter the hydrogen economy. Water electrolysis is increasingly emerging as a key technology for building a sustainable, flexible energy system and carbon-free industry. This opens up new markets for us,” said Sami Pelkonen, CEO of thyssenkrupp’s chemical & process technologies business unit.

Whether to use hydrogen to power cars and heating systems is still controversial. Environmentalists called for limiting its use in the transport sector to vehicles that cannot be powered directly by electricity, such as many ships and planes. They argue hydrogen should not be used for heating as there are more efficient alternatives, e.g. district heating from combined heat and power plants.

Malaysia’s state energy company Petronas had said in a statement it would deliver the cargo directly to Myanmar, giving rise to rumours the tanker would be headed from Bintulu LNG in Malaysia’s eastern state of Sarawak to the port of Yangon. Instead, it did berth directly at the new jetty and regasification unit, built just meters from the gas-fired Thanlyin power plant (see map).

The maiden cargo is the first of a series of LNG deliveries from Petronas to CNTIC and VPower Group under a sale and purchase agreement, signed in early 2020 to ensure a stable fuel supply for three new gas power projects in Myanmar.

A second cargo, loaded the tanker Golar Kelvin, left Bintulu LNG on Thursday last week, according to ship tracking data. However, it is unclear when it will arrive at Thanlyin given that the tanker with the maiden cargo had been waiting in the Gulf of Martaban off Myanmar’s coast for almost a month before entering Thilawa port, the site of Thanlyin LNG.

Delayed cargo delivery slows down power project

CNTIC and VPower Group are fast-tracking construction of the 350 MW power plant in bid to avoid the recurrence of blackouts this summer. According to the government tender notice, developers were given seven month to complete the project but commissioning is now running two month late – possibly due to the delayed delivery of fuel.

The tender initially envisaged to source gas for the Thanlyin power plant via a floating storage and regas unit (FSRU), with electricity meant to be generated on floating power barges at Thilawa port.

Later, that plan was changed to an onshore, engine-based power unit with an associated floating storage unit (FSU). The Thanlyin consortium consequently resorted to importing LNG via small LNG carriers with a shallow draught that can transport the cargo directly to the jetty and offload it onto the FSU.

Emergency power projects meant to mitigate risk of blackouts

Swift start-up of the Thanlyin LNG-to-Power is vital to avoid a repeat of power shortages, and potential blackouts. During the past summer, the Yangon area of the country was subjected to power cuts of up to six hours a day and World Bank warned the country’s electricity demand is growing three times as fast as available capacity.

With general election coming up in November, the government wants to avoid a repeat of the dire situation of blackouts this year; hence it launched tenders for three emergency power units. Once up and running, these Wärtsilä engine-driven gas power plants can operate baseload or in load-following mode to provide balancing power for Myanmar’s rising share of wind and solar power.

The Chinese Premier Li Kequiang said recently Beijing wants a nationwide 5% cut in power prices, instated during the lockdowns, to remain in place for the rest of the year. This national policy is meant to help revive the economy by giving energy-intensive industry access to electricity at a reduced cost.

Guandong’s regional government, in contrast, is considering levying higher rates predominantly on electricity from burning gas -- given that local utilities had rushed to buy cheap LNG cargoes after prices in Asia fell towards $2 per MMBtu. Critics dismiss the proposed rate cut as counterproductive to China’s nationwide clean energy aspirations. 

Surge in shipments to CNOOC’s Dapeng LNG terminal

When energy demand and LNG prices began falling across Asia due to shutdowns to contain the coronavirus pandemic, utilities in Guandong were quick to snap up cheap cargoes. Shipments to CNOOC’s Dapeng LNG import terminal (pictured) recorded a record number of tanker arrivals of 775,000 tons in May.

However, the cut in power tariffs threatens to undermine this growth. Even with lower prices for imported LNG, utilities could no longer reap a profit from operating some gas-fired power plants. Several less-efficient plants would be at risk of being mothballed and lying idle temporarily, or even be permanently shut down.

The proposed new tariff rates would be 0.029-0.08 yuan (0.4-1.1 $cents) per kilowatt-hour lower than the current level of 0.533-0.665 yuan per kWh, according to local reports referencing a consultation paper from the Guangdong Development and Reform Commission.

New tariff could alter Guandong’s energy mix

If enacted, the lower power tariffs that utilities would be able to charge from their customers would mean that ageing and less-efficient gas power plant would no longer be able to operate at a province.

In the long run, the tariff cut could shift Guandong’s energy mix towards more coal generation. Contrary to the rest of China, coal currently accounts for less than half (48%) of Guandong’s energy mix while gas-fired power makes up about 18%.

Operating technology (OT) assets, especially in the power sector, are particularly vulnerable to cyber attacks particularly because most of the critical infrastructure in the energy was engineered before the time of digitalized control system.

This lack of centralized monitoring and control often leaves portions, or entire power plant fleets, without the ability to be patched or cost-effectively updated with new security defenses.

SparkCognition’ ‘DeepArmor Industrial’ security system, fortified by Siemens, has been designed to prevent industrial zero-day attacks and persistent threats. It prevents never-before-seen attacks in disconnected and isolated environments.

The system gives a backstop solution for iindustrial systems that operate on legacy platforms (e.g., Windows 2000) that are unpatched or under-patched. Built-in application, USB and script control capability allow implementing the security tool with a whitelistig approach to system security.

Designed to protect autonomously on isolated OT networks, DeepArmor Industrial does not require frequent updates or connection to a management console.

Utilities ‘vulnerable to cyberattacks’; Ponemon study finds

Global energy utilities are facing a growing risk of cyberattacks with potentially severe financial damage. A survey by Siemens and the Ponemon Institute found that 54% of utility respondents fear an attack on critical infrastructure. The study surveyed 1,726 utility professionals responsible for securing or overseeing cyber risk in OT environments at electric utilities with gas, solar, wind assets, and water utilities worldwide.

“The utility industry has woken up to the industrial cyber threat and is taking important steps to shore up defenses,” said Leo Simonovich, Siemens global head of Industrial Cyber & Digital Security.

Fearing financial and infrastructure damage, 64% of respondents said sophisticated attacks are a top challenge and more than half anticipate an attack in the near future. 56% of respondents reported at least one shutdown or operational data loss per year, and 25% were impacted by mega-attacks often from nation-state actors.

Vulnerabilities, that malicious actors seek to exploit, are rising as rely on digitalization to optimize power plant operations and balance the grid with intermittent renewable energy and distributed power sources. Business models that connect OT Power generation and transmission to Information Technology (IT) systems, tends to be more at risk.

Everett LNG, in operation since 1971, is used primarily to balance peak demand during the winter season, when gas consumption for heating is prioritized. The terminal feeds regasified LNG into two interstate gas pipelines and the Mystic Generating Station, deemed ‘system-relevant’ for regional energy supply security.

But the Attorney General Maura Healey argues Massachusetts needs make large cuts in its use of fossil fuels to meet the state’s goal of net-zero greenhouse-gas emissions by 2050.

“If the state’s Department of Public Utilities opens the investigation, Massachusetts would become the third state to launch a formal process to phase out natural gas,” Healey said in a statement. California and New York are already looking at how to best transition away from using gas for heating and use electrified systems, powered by renewables, instead.

Exelon mulls closing uneconomical gas power units

Gas-fired power generation is not always economical in New England. In fact, Exelon two years ago approached the U.S. Federal Energy Regulatory Commission (FERC) suggesting it would only keep its two large Mystic gas power blocks and the adjacent Everett LNG import facility operational between 2022 and 2024, if it gets permission to collect $1 per month from all electricity customers in New England.

Estimating the future costs of operation, Excelon said at the time its annual fixed revenue requirement for the two plants totals nearly $219 million in 2022-2023 and nearly $187 million in 2023-2024.

Mystic is “system relevant”, says ISO New England

Trying to put pressure on the regulator, Exelon had floated plans to retire Mystic’s two gas power units at the end of May 2022 rather than continue to lose money. However, the regional power grid operator insisted it needed the 1,700 MW capacity of the two gas power blocks to keep the system in balance.

Pipeline constraints limit the amount of natural gas that can be transported to New England, hence ISO New England urged the regulator that Exelon needs to keep the Mystic plants running because it can rely on imported LNG.

The Australian start-up Austrom says it has acquired enough land in Callide to build a large solar-battery power hub. The site, though unnamed, is said to boost excellent solar conditions and have access to the regional power transmission grid.

The 3.6 GW solar PV park will power the production of green hydrogen through electrolysis, which is expected to result in over 200,000 tonnes of hydrogen per year.

“The technology for generating hydrogen more efficiently is evolving rapidly as is the demand for commercially produced quantities of green-powered hydrogen production,” said Austrom Hydrogen Director Tonny Jorgensen. “Along with contributing significantly to Australia’s export market and economy, this project will provide thousands of jobs, boosting regional economies and help foreign industry partners achieve their green hydrogen targets.”

Gladstone turns into hydrogen hub

The Port of Gladstone, one of Australia’s traditional centers for the coal and gas industry, is on the verge of transforming into the nation’s green hydrogen hotspot.

To that end, the Queensland Government has set up a $15 million Hydrogen Industry Development Fund. It helped fund Australia’s first $4.2 million gas injection facility that will inject green hydrogen into the local gas grid.

AGN, part of the Australian Gas Infrastructure Group (AGIG), has also been granted more than $1.7 million through the fund to build a blending facility to deliver 10% renewable hydrogen into the gas network.

Gladstone is also the chosen home to the Hydrogen Utility’s (H2U) latest project, a proposed $1.61 billion industrial complex for large-scale production of green hydrogen and ammonia. Dubbed ‘H2-Hub Gladstone’, the project is being developed in stages and comprises an up to 3 GW electrolysis plant with up to 5,000 tonnes per day ammonia production capacity.

Green hydrogen reaches cost parity in Australia

Though green hydrogen is still more costly to produce than conventional sources, Wood Mackenzie expects it could reach parity by 2030 in Australia, Germany and Japan based on $30 per MWh for renewables. While technology is advancing, analysts see “considerable uncertainty” around hydrogen investment in Asia-Pacific.

“In our accelerated transition scenario case for Asia Pacific, we forecast the share of zero-carbon energy reaching 35% by 2040 with green hydrogen capturing up to 3% in the mix,” said Prakash Sharma, head of Markets and Transitions in Asia Pacific. “In the mobility sector, the share of electric vehicles increases up to 65% of new sales by 2040 in the scenario case compared to an average 25% in the base case.”

Globally, some $365 million has been invested in hydrogen sector, according to Wood Mackenzie estimates, with over $3.5 of billion worth of projects due for commissioning by 2025.

Initial gas gathering operations are underway at the EXON wells and expected to continue through 2022.

Under the contract, Edge will both produce the LNG at the Marcellus wells and purchase it from EXCO Resources. This LNG will then be sold and delivered to customers in the northeast region via its truck-based virtual pipeline, where it will be used to provide natural gas to homes and businesses. Edge hopes to generate surplus LNG beyond this agreement for sale to its own customer base.

Mobile Cryobox liquefaction technology

To gather the stranded gas, Edge LNG deploys its mobile, truck-delivered liquefied natural gas (LNG) equipment to the Marcellus site. At the heart of the operation are three trailor-mounted Cryobox liquefaction units that can be delivered to any site accessible by road.

The unique liquefaction process, created by Galileo Global Technologies, is used exclusively by Edge LNG in North America. After set-up and safety checks, production can begin within hours.

Trucking LNG remedies infrastructure constraints

In the Marcellus Basis, Edge LNG is already gathering and monetizing stranded gas on behalf of various other upstream companies, whereby the natural gas is delivered by truck to electric utilities, mostly in New England, to fuel some of their decentralized power stations.

Trucked LNG helps overcome the bottleneck in New England gas infrastructure, where pipeline constraints keep limiting the amount of natural gas that can be transported to utilities and local businesses. To avert energy shortage at times of peak demand during the winter, regional utilities regularly had to import LNG by having cargoes shipped to the Everett regas terminal, situated at Boston harbour.

With lockdowns lifted in most European major economies, electricity demand and wholesale power prices are slowly approaching pre-corona levels. A notable exception is gas prices, which have fallen to unprecedented low levels due to the mild winter and full gasholders.

“This development has created a perfect storm for coal plants,” Mirko Schlossarczyk from the consultancy enervis commented.  "The combination of reduced electricity demand, extremely low gas prices and recovering CO2 prices remains a toxic mix."

As a consequence, coal-fired power plants lose out to gas-fired plants on the market, he explained, concluding: "In the end, the corona crisis only accelerated the long-term decline of coal."

Need for better incentives

In Germany, strong renewable power production coinciding with low demand underlined the need for more flexibility in April and most of May. In the absence of sufficient levels of energy storage, power prices turned negative, because it was not possible or profitable for thermal plants to turn off, and because a lot of renewables that are in the system currently have no incentive to turn down even when power prices turn negative.

To avoid such scenarios in the future, it is vital to increase both the flexibility of dispatchable power plants, and give renewables incentive to curtail production when power prices turn negative.

Grid stability and power supply security was not threatened, as grid operators have been quick to learn how to cope with high volumes of renewable energy in the system. Basically, German TSOs they tend to handle it through re-dispatch and feed-in management, i.e. telling renewables in the north to turn down and thermal plants in the south to turn up.

Calling for further grid expansions, Hanns Koenig from consultancy Aurora Energy Research pointed said: “TSOs likely would have had a harder job at managing the system if demand had not been reduced due to Covid-2019, because re-dispatch is normally highest in high renewables, high load situations.”

By 2030, Aurora expects only moderate increases in power demand but looking further ahead Mr Koenig sees stronger demand growth, “simply because the cheapest way of decarbonising a lot of industry sectors will be to electrify.”

Depending on the situation, as many as 67,000 customers who might have lost power when areas outside Humboldt County face extreme weather conditions, can remain energized, due to PG&E’s changing of the plant’s set-up. Areas that can be re-energised that way by the Humboldt Bay Generating Station include over 20 cities and towns such as Eureka, Arcata, McKinleyville and Fortuna as well as some tribal communities.

Operating since 2010, the 163 MW Humboldt Bay Generating Station (HGBS) power plant uses 10 reciprocating Wärtsilä engines that run on natural gas, with diesel fuel as a backup. The technical re-configuration, also known as ‘islanding’, allows PG&E to use large parts of the installed capacity at HGBS specifically for certain areas to prevent blackouts in the event of unforeseen downtime of another power plant or an important power transmission line.

Tests completed, fine-tuning ongoing

Works to upgrade and commission the HGBS were carried out by a team of 70 specialists at PG&E over a six month period. Tests of the system’s capabilities were successfully completed on May 9, the operator said, stressing it will “continue to fine-tune the system and make additional transmission upgrades to improve functionality in the coming months.”

 “Our residents and businesses endured hardships during safety shutoffs even when there wasn’t a wildfire threat in Humboldt County. PG&E leadership answered our calls to make sure they did everything they can to reduce impacts next time,” said Rex Bohn, First District Supervisor for Humboldt County.

Andy Vesey, PG&E Utility CEO and President explained that “as soon as the last PSPS event of 2019 ended, we set a goal to complete direct local powering capabilities before this next wildfire season. The team worked on air permitting, design changes, and testing activities to reach this goal,” he said, noting “safety was at the forefront of everyone’s minds, especially during the pandemic.”

The HBGS employs 17 full-time workers in Humboldt County and contributes more than $4 million a year in property taxes and local sales taxes.

In contrast, residential electricity sales is forecast to grow by 3% this summer because more people are working from home and following social distancing practices.

Weather factors normally large determine electricity demand over the summer but this year other factors have a greater impact on demand: Although state and local governments are relaxing stay-at-home orders, social distancing guidelines will likely result in Americans spending more time at home than usual this summer. In addition, many people that had worked in offices are now working from home, shifting electricity demand from the commercial sector to the residential sector.

All eyes on employment

Macroeconomic indicators, especially on employment, are key drivers for the EIA’s energy demand projections. EIA’s short-term economic assumptions are based on the macroeconomic model from IHS Markit. This model projects non-farm employment will fall by 13% in 2020 and that the electricity-weighted industrial production index will contract by 12% in 2020.

Ample supply of cheap domestic natural gas, combined with depressed demand, will accelerate coal-to-gas switch in the electric power sector. Analysts expect the contribution of coal will fall, with coal-fired plants seen generate 178 billion kilowatthours (kWh) between June and August 2020, down from 272 billion kWh last summer.

The EIA expects coal’s share in the US power generation mix will fall from 24% of the electricity generated during summer 2019 to 17% this summer, when the contribution of coal power will be lower than nuclear generation at 207 billion kWh.

Gas-fired power plants, meanwhile are seen generate 467 billion kWh this summer, slightly higher than the 460 billion kWh last year. Forecast natural gas prices remain low this summer, making it relatively more economical than coal for power generation.

The share of natural gas in the US power mix is consequently seen rise from 41% last summer to 44% in summer 2020. Renewables also increase market share. Strong wind and solar additions in the Midwest and Texas is likely to drive up the share of wind power to 7% this summer and utility-scale solar to 3%, the EIA says in its summer 2020 electricity industry outlook.

Germany is the first country in Europe to have implemented generating set certification with detail guidelines for grid code compliance, though other countries are in the process of drafting similar requirements. Grid connection rules in Germany are specified in low, medium, high, and extra high voltage levels. Any power plant connection to the network should comply with these rules.

Niklas Doktar, Director, Solution Design, Wärtsilä Energy Business said the grid code compliance certificate brings the Finish company one step closer to a wide-spread adoption of Wärtsliä engines in Germany to balance rising volumes of intermittent energy supply from renewables.

“Certification of the Wärtsilä 31SG places it in a leading market position for 2-stage turbocharged engines,” he underlined, adding all other gas-fuelled Wärtsilä genset are under certification.

World-class efficiency of 31SG gensets

The Wärtsilä 31 gas engine gas engine generating is typically installed in medium sized de-centralized power plants having multi-engine configurations to provide a plant net load of from 20 to 200 MW.

According to the manufacturer, it offers “the highest available open-cycle efficiency” as well as “unparalleled dynamic capabilities.”

Designed for flexible power supply it allows to backstop high volumes of energy from renewable sources. It creates a balancing link between power generation and consumption, thus providing effective system level resilience.

The engines engine can reach full output in 2 minutes from the start command, allowing for the flexibility needed to balance high levels of unpredictable renewables in the power system. According to Wärtsilä, they can be used for load-following or baseload operations.

The modular design of the genset allow for easy conversions between pure gas, multi-fuel and pure liquid fuel variants. It can also be adapted to run on renewable fuels.

Strong gas production is outpacing consumption with the surplus being put in storage or exported. Currently, the Lower 48 states’ cumulative net injections of natural gas exceed the five-year average by 16%, data by the U.S. Energy Information Administration (EIA) shows.

Net injections into working gas storage reached a record 102 Bcf for the week ending May 29, and cumulative injections were as high as 709 Bcf by that date.

Pace might slow over the summer

The pace of storage injections might slow over the summer if gas production falls significantly after major upstream companies have slashed their capital spending and shut in some wells. Market observers will close watch the rig counts, the number of new well completions, and the availability of fracturing crews to estimate whether the drop in domestic supply will be enough to stabilize prices, considering the substantial drop in industrial gas demand due to the coronavirus crisis.

Summer temperatures in the main storage regions will also influence how much gas will be used by peaking power plants to meet the need for air conditioning. This amount, in turn, affects the amount of natural gas available for summer injections.

EIA data shows that this year, working gas stocks entered the refill season at a relatively high level following a warm 2019/20 winter heating season. Yet, total net injections for the Lower 48 states reported so far in 2020 are the third largest ever reported, going back to 1994, when working natural gas stocks exceeded 1,500 Bcf entering the refill season.

Despite the corona crisis, the Egyptian government maintains its target of 6-7% economic growth in the current fiscal year 2019/20. The International Monetary Fund (IMF), meanwhile, forecasts Egypt will reach a 5.9% growth in GDP.

Though fiscal reforms and reduction in subsidies have won Egypt the confidence of credit rating agencies and foreign investors, the immediate effect has been a fall in living standards. Between 2015 and 2018 the proportion of Egyptians living below the poverty line increased sharply. This means that not only are the benefits of reform not being felt, the reforms are actually causing pain and public unrest.

Avoiding blackout to appease the public

The political imperative to avoid blackouts and to ensure the consistent availability of electric power at peak times has been a defining feature of the Sisi presidency, analysts noted. The collapse of the Mubarak regime and the brief rise and fall of the Brotherhood's Mohamed Morsi took place against a backdrop of a severe energy crisis. The long-term mismanagement of the gas production and export industry meant that by 2012 Egypt not only had to cease gas exports, it also had insufficient production to supply domestic industry and power generation.

“Morsi's failure to respond to these economic challenges was an important factor behind his downfall. It is certainly the case that after taking control in July 2013, the military swiftly resolved the most debilitating aspects of the power supply crisis,” ResearchandMarkets commented.

Three Siemens-build mega plants add 14.4 GW

To avert future power shortages, President Sisi struck an 8 billion Euro deal with Siemens to build the three mega power plants – Beni Suef, New Capital and Burullus (4.8 GW each) – together with its consortium partners, Orascom Construction and Elsewedy Electric. The three CCGTs, along with some smaller wind and solar PV installations, helped raise Egypt’s installed power generation capacity to over 47 GW, and boosted the available reserve to 25.7% of installed capacity.

“It was President Al-Sisi’s decision to trust Siemens with this enormous national power project. Joe Kaeser and Al-Sisi shook hand on this deal,” Peter Ullrich, overall project director CCPP Megaproject Egypt told Gas to Power Journal. Precondition for an order of this size, in his view, was a political interest at European level to stabilize Egypt as a country.

To realize the mega power projects, state-owned EEHC had to finance nearly 85% of the cost of 6 billion Euros ($6.7 billion) through a loan provided by Deutsche Bank, HSBC and KfW-IPEX.

Blackstone affiliate Zarou as well as Edra Power Holdings of Malaysia in May 2019 both expressed interest to purchase three Siemens-build CCGTs from the Egyptian state-run owner and operator EEHC. A sale would ease Egypt’s burden of treasury-guaranteed debt that equalled 20.4% of GDP in the 2019/20 state budget. About a quarter of that debt is being owed by electricity companies.

The order to develop the CCGT was placed in early 2015 by Mexico’s Federal Electricity Commission (CFE) in a bid to meet the growing need for electricity in the region.

The Chihuahua region has been identified as a “deficient node” in Mexico’s national electric system, considering local energy demand growth over the next decade. The Norte III combined cycle plant will help fill the supply gap.

Alejandro Maluf, CEO Techint North America said “we chose GE to collaborate with us on the Norte III plant because of its reliable technology and total plant-service solutions.” Techint believes the 907 MW plant will dent he expected growth in the Chihuahua region, as identified in the Mexican government’s 15-year infrastructure development program the PRODESEN 2017-2030.

Eric Gray, Vice President for Americas region, GE Gas Power pointed out the project was performed with the “highest standards of quality and safety” in collaboration with FieldCore, the field services execution team owned by GE. He stressed the commissioned plant will provide “productive and reliable results for our customers, including Techint.”

As part of the 25-year operations agreement, GE will provide a full spectrum of digital solutions to predict and reduce unplanned downtime and improve plant productivity. GE’s software will directly support to the GE O&M team to achieve guaranteed capacity outcome.

In Mexico, GE has its third largest 7F gas turbine installed base in the world as well as the 16,000-square-meter Morelia Service Center, in Michoacán, that provides maintenance, testing and repair solutions for the wider Latin American region.

This month, GE’s 7F gas turbine technology turns 30, with the first 7F having started commercial operation in 1990. The turbine’s installed base of 950+ units (including 96 in Latin America) generate 150 GW in combined power output. The 7F fleet provides customers with 60.4% efficiency at low fuel costs and 97% availability thanks to improved maintenance practices and field removal compressor airfoils. In terms of green fuels, the 7F can be configured to operate hydrogen up to ~60% volume.