Throughout 2020, Henry Hub spot prices are seen averaging $2.11/MMBtu and increasing further in 2021, reaching an annual average of $2.51/MMBtu.

The rebound comes after spot prices eased off as low as $1.91/MMBtu amid excess supply an unusually mild winter. “Warmer-than-normal temperatures in February reduced demand for space heating and put downward pressure on prices,” EIA analysts said.

On the supply side, the plunge in global oil prices impacts the profitability of U.S. fracking activities and will gradually lead to lower production of both shale oil and gas.

Though the EIA still expects gas production in 2020 will rise 3% to an average 95.3 Bcf/d, the rate of output increase slows substantially. Anticipating a downward trend, the EIA expects monthly production to generally decline through 2020, falling from an estimated 96.5 Bcf/d in February to 92.3 Bcf/d in December.

“The falling production mostly occurs in the Appalachian and Permian regions. In the Appalachian region, low gas prices are discouraging producers from engaging in gas-directed drilling, and in the Permian region, low oil prices reduce associated gas output from oil-directed wells,” analysts commented.

In 2021, EIA forecasts dry natural gas production will rise from December 2020 levels in response to higher prices. Forecast dry natural gas production for 2021 averages 92.6 Bcf/d.

US working natural gas in storage ended February at 2.1 trillion cubic feet (Tcf), 9 percent more than the five-year (2015-2019) average. The EIA forecasts that total working inventories will end March at 1.9 Tcf, 12 percent more than the five-year average. During the April through October injection season, inventories are seen rise by almost 2.1 Tcf to reach almost 4.0 Tcf on October 31.

Regulated kilowatt-hours were historically a low risk and low return business but the global boom in low-cost renewables have turn things around. An estimated 420 million people now use standalone off-grid solar and another 47 million people rely on mini-grids, supplied by decentralized gas gensets and renewables, for access to electricity.

Public-private partnerships have sprung up, such as Konexa in Nigeria or TP Renewable Microgrid in India, and smart subsidy programs such as SMART RBF for mini-grids have evolved as follow-ons to integrated energy access planning.

Combining solar, gas and storage to cut costs

Distributed hybrid plants – mainly solar PV, increasingly combined flexible gas gensets or battery storage – now have highly convincing economics compared with diesel-fuelled plants. Nearly 3.5 GW of renewable of hybrid power units are is operational or under development for powering mining applications, nearly half of which will power mines already off the grid or those looking to improve on unreliable grid power.

“The market for off-grid renewables holds a lot more promise beyond lighting unlit households or reducing costs and fuel variability for remote, diesel-dependent industries,” said senior research analyst Benjamin Attia, suggesting the technology shifts the utility business model towards customer-centricity.

Decentralised power solutions, based on hybrid units are well positioned to displace hundreds of GWs of diesel generation, particularly where off-grid units and incomes are large enough to support modular system upgrades.“The last decade saw the birth of a trillion-dollar market opportunity,” he said, “but the 2020s will reveal the true pace of change.”

Integrating off-grid gensets with centralized plants

Though future grid will be increasingly renewable, low-cost, digitally-managed and eventually demand-following, low energy access countries’ urgent need for large utility-scale generation and grid infrastructure upgrades cannot be overstated. “Therefore, the most game-changing growth factor for the off-grid renewables sector will be centralised and integrated electrification planning,” Attia pointed out.

New tools, based on machine learning, are being developed to estimate least-cost electrification scenarios, map existing grid infrastructure, gauge future electricity demand as well as customers’ willingness to pay for upgrades.

When factoring the in burgeoning bus, truck and van markets, vehicles account for over 900 MW of the 1.1 GW total, according to the latest Fuel Cell Industry Review. The remainder consists of stationary systems – of which US and Korean power generation units make up the bulk – and tens of thousands of Japanese CHP units installed in apartments.

Ready for commercialization

“If the 2010s can be seen as the breakout decade for the battery, the 2020s will see the ascendancy of the fuel cell,” said David Hart, director for fuel cells & hydrogen at E4tech.

From a technical perspective fuels are proven, so there’s a great sense that the industry is on the cusp of something great. Anticipating rapid demand growth for fuel cells, E4tech analysts stressed that trend is coming just in time: “Climate change targets are looking more urgent and challenging than ever, and we need a full range of technologies to meet them,” he commented.

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

China, Korea drive demand

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

The NEXO also accounts for some growth in European capacity, which increased from 41 MW to currently over 70 MW. However, the biggest market outside of Asia is North America, which saw shipped capacity of 384 MW – down slightly from 425 MW in 2018, but expected to rebound in 2021.

“To succeed, the fuel cell industry will need to see the supply chain mature quickly enough to deliver on expectations, and to allay any remaining safety concerns. But the opportunity is huge, big players are investing very seriously in hydrogen, putting the pieces into place to make it work,” Hart noted. Once that happens, fuel cells will rank as an established technology, feeding not just into the success of today’s products and systems, but featuring in the designs of tomorrow’s innovators and entrepreneurs.

The price of gas under long-term contracts has been at a premium to hub-priced gas in recent times – but the plummeting oil prices have turned things on its head. “For China, at an oil price of $35/bbl, contracted LNG arrives at a cost lower than domestic wholesale price benchmarks,” said Wood Mackenzie senior manager Miaoru Huang.

“While there is strong incentive for NOCs to retain the benefits to compensate for years of import losses, the import cost reduction will be partially passed through to downstream and will allow the government to push through its policy of lowering gas prices to end users,” she explained, adding; “This will help coronavirus-affected businesses to resume operations but stimulating new coal-to-gas switching will require further policy support even under a low oil price environment.”

Gas squeezed out in India

But in other markets, gas demand will come under pressure from oil as a competing fuel. Notably in India, analysts suggest “a lower oil price could slow the shift from oil to gas in the industrial sector,” as both long and spot LNG prices will compete with fuels like heating oil, LPG and naphtha.

European gas demand and flows will face little impact from even a sustained oil price collapse. Oil-indexed Russian pipeline contracts now account for less than 25% of Gazprom’s portfolio and, regardless, the current market share strategy is unlikely to change.

Algerian pipeline contracts into Spain remain fully oil-indexed and have been sitting at take-or-pay levels. “If oil prices remain low, Spanish buyers would take more Algerian piped volumes,” Ms Huang said. This would not become a possibility until October 2020 due to the lag on the contract - “but in 2021 it would reduce the space for LNG into Spain by 2 billion cubic metres, placing even more pressure on the oversupplied LNG market.”

U.S. gas production plunges

The biggest downside risk from the oil price crash to gas supply is associated with gas production – largely from unconventionals in the United States. “However, it’s not an instantaneous effect,” analysts said, “as prices are still generally above variable wellhead operating costs.”

As oil drilling slows, so does associated gas production growth, particularly in the Permian. Wood Mackenzie’s Genscape estimates that by the end of the year, U.S. gas production would be 0.9 billion cubic feet per day (cfd) lower than pre-crash estimates. This could be exacerbated to a fall of 3.1 billion cfd through 2021, with more flexibility in drilling reductions.

LNG projects face delays

Most liquefaction projects in the U.S. are supplied from non-associated gas so there’s little direct impact. ““The greater risk to supply is pre-FID investments,” said WoodMac research director Giles Farrer.

Record LNG supply investments last year and plunging LNG spot prices this year were already testing the appetite of LNG project developers to sanction new LNG projects in 2020. But the drop in oil price will make these decisions more complicated.

“Lower oil prices will have several consequences for the sector. These include restricted capital investment budgets, reduced appetite for financing LNG projects with exposure to oil prices. US LNG projects selling on a Henry Hub-plus basis will also be perceived as less competitive than oil-indexed LNG,” he explained. “As a result, there will be fewer LNG projects taking FID in 2020 and 2021. Projects in Mozambique, Mauritania/Senegal and Australasia will come under pressure. This is likely to translate into lower global supply between 2024 and 2027.

In contrast, Qatar - with low fiscal breakevens and an ambition to grow LNG market share long term - is expected to continue to push forwards with its North Field expansion plans.

Spanning over 131km, the Pioneer Pipeline runs from Drayton Valley in central Alberta to west of Edmonton. The pipeline purchase is underpinned by 15-year firm delivery contracts for 328 million cubic feet per day (mmcf/d) and an eight-year firm receipt contract for 47 mmcf/d.

“This acquisition presents a unique opportunity to connect Western Canadian Sedimentary Basin (WCSB) supply to Alberta power generation demand, which supports coal-to-gas conversion and lowers carbon emissions,” said Tracy Robinson, Executive Vice President at TC Energy and President of Canadian Natural Gas Pipelines.

NGTL System currently spans 25,000km in length and receives, gathers and transports gas produced in the Western Canadian Sedimentary Basin to customers in Alberta and into northeast British Columbia.

Expanding the system, TC Energy is also building the US$5-billion Coastal GasLink pipeline to bring feed-gas from the Montney shale basin in northeast BC to the proposed LNG Canada’s proposed liquefaction and export plant proposed at Kitimat on the Pacific Coast.

“Utilizing the existing Pioneer Pipeline maximizes the use of existing infrastructure and provides the most efficient solution to deliver gas to this growing demand,” added Robinson.

The proposed purchase is still subject to the execution of definitive sale agreements, which are expected to occur in Q2-2020. The deal also requires approval of the Canadian Energy Regulator.

Construction of the Killingly Energy Center is slated to start this year and the unit will be funded and developed by NTE Energy. Mitsubishi Hitachi Power Systems Americas (MHPS) will supply the power train, equipped with an M501JAC gas turbine and a TC2F steam turbine in multi-shaft configuration.

“This will be the fourth project for the team of NTE, MHPS and Gemma and we are thrilled to have the opportunity to design and build another state-of-the-art energy project and to have it located in our home state of Connecticut,” said Gemma Power Systems co-president Charles Collins.

Once complete, the Killingly Energy Center will be capable of powering approximately 500,000 homes and represent an investment of over $500 million, providing significant tax revenue and energy security of the local community.

FID of Brook County power project imminent

The second EPC services contract, awarded by ESC Brooke County Power, is for the construction of a 920 MW gas power plant in Brooke County, West Virginia.

Works are also due to start this year, once developers have reached financial close for the project. Once operational, the plant will be capable of powering the equivalent of 700,000 homes.

 “ESC Brooke County PowerI, LLC will create jobs, source fuel regionally, and use state-of-the-art generation technology for maximum efficiency and minimum emissions,” commented ESC president Drew Dorn.

Situated in Shuiba, in Kuwait’s Al-Ahmadi region, the mostly gas-fuelled plant currently has a capacity to produce some 270,000 cubic metres of water and 800 MW of electricity.

Strikingly, MEW’s tender document for the power plant did not include production availability data for 2018-19. It is known that production availability was between 74% and 80% between 2015 and 2017, which is way below industry benchmarks.

Many of Kuwait’s largest largest power plants are more than 20 years old and are reaching the end of their lifespan. Turbines at Doha East, Doha West, Shuaiba and Al-Zour South steam plants have been derated and are operating below capacity. Hence, the emirate’s available generation capacity is estimated to be around 7 percent below nameplate capacity of 14,700 MW.

Call for tenders

Eager to find buyers that will upgrade the North Shuaiba CCGT, the ministry recently invited bidders for advisory and valuation contracts. The government hopes to fetch some $12.6 billion through the privatization, but that may well be unrealistic.

One well-established consultancy refrained to bid for the contract amid concerns over the asset’s actual state and the amount of costly retrofits required before the plant would be ready for regular dispatch.

Mitsui and Italy’s Fisia Italimpianti had been the EPC contractors to build the North Shuaiba power plant in 2010-12 on a lump-sum turnkey basis. Subcontractors and equipment suppliers for the project were Hyundai Engineering & Construction and Doosan Heavy Industries, GE and Siemens.

The 778 MW plant is currently run by a joint venture of Malaysia’s TNB Remaco and Kuwait’s Kharafi National under an operation and maintenance (O&M) contract, which expires in mid-2020.

Aramco on Sunday posted a fall in net income to $88.2 billion for the full-year 2019, down from $111.1 billion in the previous year. The decrease was primarily due to lower crude oil prices and production volumes, Aramco said, coupled with declining refining and chemical margins.

Slashing Capex due to sluggish demand

The Saudi state oil company plans to slash capital expenditure for 2020 to between $25 billion and $30 billion in light of the coronavirus-induced demand destruction and recent commodity price volatility. In contrast, Capex in was $32.8 billion, already lower than the $35.1 billion Capex in the previous year.

“Capital expenditure for 2021 and beyond is currently under review,” the Aramo CEO said, indicating there might be drastic cuts. He stressed, however, the company’s low upstream costs and low sustaining capital give it a competitive edge over rival producers.

“Our unique scale, low costs, and resilience came together to deliver both growth and world-leading returns,” Nasser stressed, adding these strength combined with disciplined and flexible approach to capital allocation are meant to help sustainably grow free cash flow.

Tapping huge Jafurah field from early 2024

On the upstream side, Aramco in February received regulatory approval to develop the Jafurah unconventional gas field in the Eastern Province. It is the largest unconventional gas field in the Kingdom to date, with an estimated 200 trillion cubic feet of resources.

Start of production of the first of three development phase is slated for early 2024.

A boost in domestic gas production is set to help the Saudi kingdom to realize its goal of using more cleaner-burning gas as fuel in power stations and as feedstock for the production of petrochemicals. Refining and petchems are high-priority industries for the government in its strategy to diversify the economy.

The new fast-start gas power unit will be built adjacent to the Berezovskaya combined heat and power plant, both operated by Brestenergo. Once operational, the new peaking plant will help further strengthen the reliability and stability of the Belarusian power grid.

The latest order follows a contract in 2019 for the delivery of 11 SGT-800 gas turbines for three peak load and backup power plants in Lukomlskaya, Novopolotskaya, and Minsk.

Similar to these three units, the new flexible power plant in Beloozersk is designed for 700 operating hours and 350 cold starts per year.

“Our most important requirement for the new power plant project was to select and purchase a highly maneuverable reliable peak and backup power plant to provide reliability of electricity supply to consumers,” said Sergey N. Shebeko, General Director of Brestenergo. “In the competitions for the right to supply equipment for this project Siemens technology, with the SGT-800 gas turbines, has won.”

Siemens’ complete scope of supply includes the five SGT-800 gas turbines with AC generators and the PCS 7 control system. It also comprises the gas receiving station, along with high- medium-, and low-voltage equipment.

Olaf Kreyenberg, Siemens’ head of Power Generation Europe and CIS, underlined “third order in a period of three months underscores the enormous trust that Belarus places in our technology and our capabilities.”

In an analysts’ call, RWE stressed it “bears the main burden of the lignite phase-out, which will stretch it to its limits.” The Essen-based utility explained it will implement the required capacity reduction by 2023, mandated by the German coal exit, “nearly entirely on its own.”

The first 300 MW lignite power unit at the massive 3,641 MW Niederaussem site will be taken offline this year, and RWE agreed to close its Inden and Hambach opencast mines much earlier than originally planned. For complying with the coal exit timeline and shutting down power plants ahead of the end of their lifetime, RWE will get some 2.6 billion in compensation from the German taxpayer.

Sizeable project pipeline

Going forward, RWE is keen to get rid of its dirty coal image and has hence lined up a substantial share of green energy investment, after doubling adjusted net income to €1.2 billion last year due to “exceptional trading performance and a strong gas business.”

"A total of 2.7 GW in renewables capacity is currently under construction. Furthermore, the group has a sizeable project pipeline of over 20 GW, which will add to RWE’s current 9 GW of wind and solar power assets.

Starting in fiscal 2020, RWE's financial reporting will reflect the company's new strategic focus. The company’s core business will be made up of four segments: Offshore Wind, Onshore Wind/Solar, Hydro/Biomass/Gas, and Supply & Trading – supplemented by the fifth segment: Coal/Nuclear.

New capacities will be predominantly added in the Onshore Wind/ Solar segment, RWE announced, adding this is expected to achieve adjusted EBITDA of between €500 million and €600 million.

In terms of gas generation, RWE has benefitted from payments from the British capacity market for 2019 and a retroactive payment for 2018. As for its Hydro/Biomass and Coal segment, RWE anticipates that earnings will range between €550 million and €650 million in the year underway. Higher electricity margins are hoped to increase earnings even in the beleaguered Coal/Nuclear segment for which RWE targets an adjusted EBITDA of just over €500 million.

The novel approach of combining large lithium ion-batteries and an UPS system ensures stable onsite electricity supply for manufacturers and data centers, while reducing energy costs. The systems will first be rolled out at customer sites in Ontario and may later spread throughout North America.

Star America, the lead investor, manages capital from U.S. pensions, insurance firms, asset managers and construction firms. As a developer and manager of greenfield infrastructure assets, Star America said it had been “impressed by Demand Power’s management and their commitment to delivering innovative energy solutions.”

Christophe Petit, President of Star America said the deployment of Demand Power’s energy storage solutions will “lower energy costs, improve grid resiliency, and reduce energy consumption from the highest emission sources during peak use periods.”

Software to supplement storage

Several rival developers are rushing to develop and launch new solutions for software and storage for real time behind-the-meter energy management. Demand Energy, not to be confused with Demand Power, had a similar business plan and offering before being bought by Enel in 2017.

Greensmith, another software and energy storage integrator, was acquired by Wärtsilä in the same year. The behind-the-meter energy storage startup Stem is reportedly up for sale, attracting significant buyers’ interest.

At least 10 new plans for building gigafactories were revealed over the past six month. Tesla’s Elon Musk, the most aggressive green energy investor, announced plans for “probably four” new gigafactories: one near the German capital Berlin, a second is already in the works in Shanghai, China, and some others ones are in planning in Sweden, Hungary and Poland.

Some smaller-scale investors have teamed up on the East Coast. a consortium including Boston Energy and Innovation (BEI), Charge CCCV, C&D Assembly, Primet Precision Materials and Magnis Resources confirmed it will build a 15 GWh a year plant on IBM’s former Huron Campus manufacturing site in New York.

In Thailand, Energy Absolute aims to invest $2.9 million in a battery manufacturing site with a production capacity of 1 GWh per year, and potential to be expanded to 50 GWh by 2020.

Germany’s carmaker Daimler has dedicated $500 to its subsidiary Accumotive to expand its lithium-ion battery production from currently 80,000 units up to around 320,000.

In Australia, Energy Renaissance is advancing plans for a battery factory in Darwin, with production capacity of 1 GWh of batteries a year.

Growing investment appetite amid falling costs

Cost for battery production is falling rapidly as manufacturers bring large gigafactories on-line, although the price for raw material is going up. Lithium now makes up more than 10 percent of the cost of making a battery cell, and pricing for lithium has doubled from $5,000 per ton to $10,000 per ton.

By 2030, Bloomberg New Energy Finance anticipates battery pack prices to drop to $73 per kilowatt-hour, down from a volume-weighted average of $273/kWh in 2016.“This is an average, though,” said Logan Goldie-Scot, head of BNEF's storage practice. “We're already seeing pack prices below $200 per kilowatt-hour.”

“Institutional investors are waking up and ready to invest in storage,” commented Randolph Mann, President of esVolta.

The California-based energy storage project developer recently secured a $140 million loan from CIT, Siemens Financial Services, CoBank, ACB and Key Banc to fund construction and operations of the “esFaraday” potfolio. These eight energy storage units, with 480 MWh combined capacity, will deliver reliable back-up power and ancillary services to the Californian grid, backed up by long-term contracts with electric utilities and load serving entities.

The two joint venture partners have already developed one gas-to-power in another northeast Brazilian state of Sergipe where a floating storage and regasification unit, the “Golar Nanook,” operates about 8.5 kilometres off the coast. That FSRU supplies fuel for a combined-cycle gas-fired power plant, owned by Centrais Elétricas de Sergipe.

At Port of Suape, the project includes infrastructure for the supply of liquefied natural gas to generate electricity, in addition to meeting the demands of industries, commerce, LNG-fuelling stations and household. To this end, Golar will work together with the local gas distributor Copergás to bring LNG to regions of Pernambuco state that are not connected yet served by the traditional pipeline network.

Pernambuco state is situated near the eastern tip of the South American coastline’s bulge into the Atlantic Ocean. The remote northeastern Brazilian state has a population of around 9.6 million people and the project is aimed at benefiting the local economy.

Trucking LNG via ISO-containers

“Natural gas will be delivered by road using LNG ISO-containers,” said Golar. “Suape is already Brazil's largest hub for liquid bulk and gases and, now, it will be one of the main LNG distribution hubs in the Northeast, with full integration of sea and land transportation modes.”

Onsite, Golar intends to use a permanently docked FRSU to fill truck mounted LNG ISO-containers. These vehicles can then distribute LNG to cities within a radius of up to 1,000 kilometres, the company explained. Initial trucked volumes are estimated at 800 cubic metres of LNG per day, equivalent to approximately 480,000 cubic metres of natural gas per day.

Bermuda-based Golar also said it aims to distribute LNG from Suape to other states in Brazil whereby small-scale LNG carriers will be supplied by trans-shipment and used to transport LNG to other ports in the region.”

Most of the Capex for the Suape LNG-to-power project will be funded by Golar’s operating cash-flow. FID on the project still hinges on regulatory approval, developers said, as well as the conclusion of some commercial arrangements.

Benchmark energy products have seen trading high volumes outside of U.S. market hours, demonstrating deep liquidity and flexibility around the clock, Chicago-based CME noted. Brent crude oil prices plunged from $64 per barrel on average in 2019, with the ICE Brent frontmonth May last seen trading as lwo as $29.75/b

Government analysts in Washington, meanwhile, expect prices will average $37/b during the second quarter and recover slightly to $43/b during the second half of the year. Declining global inventories will thereafter gradually put upward pressure on price, lifting Brent prices to an average of $55/b in 2021.

Covid-19 contingency plans curb demand

As economies throughout the global grind to a near-halt as government impose increasingly drastic measures to contain the Covid-19 outbreak, consumption of crude oil and natural gas plunges with the surplus stored in inventories.

Global liquid fuels inventories are seen grow by an average of 1.0 million barrels per day (b/d) in 2020 after falling by about 0.1 million b/d in 2019. According to the U.S. Government’s March Short-Term Energy Outlook (STEO) inventory builds will be largest in the first half of 2020, rising at a rate of 1.7 million b/d.

After the March 6 meeting, the leading OPEC member Saudi Arabia announced to flood the market with cheap oil and natural gas after Russia refused to support measures to limit production. A global crash in prices of crude oil and natural gas was the consequence.

Stockpiling surplus fuels

Analysts now expect OPEC production will far exceed demand, largely due to the significant decline in global liquids demand which contributes to inventory builds. “Given that OPEC surplus capacity is more than 2.0 million b/d, member countries could produce far more than EIA’s currently forecasts, which would lead to larger inventory builds and put downward pressure on prices,” analysts cautioned.

On the other hand, higher-than-expected crude oil production outages could reduce supply and put upward pressure on prices. Such outages are likely to occur in Libya, Iran, Kuwait and Nigeria.

Gas prices plunge

Lower crude oil prices impact oil-indexed natural gas prices with a time-lag, which will also lead to lower long-term LNG supply contracts to the benefit of Asian utility buyers.

The Platts Japan-Korea Marker price for Asian spot LNG was last seen at $3.115 per MMBtu for April cargoes.

In Europe, meanwhile, the UK National Balancing Point (NBP) gas price that guides LNG prices for the Atlantic Basin was last at $3.10 per MMBtu, up from $2.85 per MMBtu and the main natural gas price on Continental Europe, the Dutch Title Transfer Facility (TTF), was also at $3.10 per MMBtu.

The US Gulf Coast LNG prices at the Intercontinental Exchange remain subdued due to the supply glut and sluggish demand. The front-month April 2020 price notched up to $2.401 per MMBtu from $2.390 per MMBtu. The May LNG future was last seen at $2.451 per MMBtu, up from a previous $2.449 per MMBtu.

Once all commissioned through the summer, the three new units will reach a combined output of 1,950 MW. The new CCGT plants will be driven by 1,650℃ class forced air-cooled M701JAC gas turbines.

The turnkey project is carried out jointly by MHPS and Mitsubishi Electric, which will supply three generators and control systems. Works are conducted under a full turnkey EPC (engineering, procurement, and construction) contract.

As for the scope of supply, MHPS specified the three gas turbines and related equipment will come from its Takasago Works, the three steam turbines are sourced from Hitachi Work, and the heat recovery steam generators and exhaust gas denitrizer systems from its Kure Works.

The JAC gas turbines used for this project are equipped with a forced air-cooled combustor system. Air emitted from the combustor casing is cooled in an external cooler, and the pressure boosted in a forced air-cooled compressor, after which the air is used to cool the combustor, and returned to the casing.

“This process optimizes the cooling structure,” MHPS underlined, adding the system also includes turbine blade cooling through an extra thick film thermal insulation coating, and high pressure compressors. According to the manufacturer, “this allows for shorter start-up times compared to steam cooling methods, and improves operational efficiency.”

In China – first hit by the coronavirus outbreak – industrial production and transport volumes have decreased sharply since the beginning of the year, followed by a sharp drop in greenhouse gas emissions. In Germany and indeed most of Europe, similar effects are expected to set in soon, after most governments enacted emergency measures that range from school closures and travel curbs to curfews.

Though these contingency measures will have a one-off effect on emissions, they do not bring about structural changes. Dirk Messner, head of the German environment agency, warned “the corona effect could even obscure the need for change."

Fuel-switch helps reach climate goals

Comparatively cheap gas and rising prices for carbon credits in the European Emission Trading Scheme (EU-ETS) are prompting utilities to dispatch gas-fired plants rather than more polluting coal-fired units.

With respect to the government's initial target of reaching a 40 percent, or 500 million tonnes of CO2 equivalents reduction by 2020, environment minister Swenja Schulze said Germany could come much closer to it than initially expected.

Add to this the “corona effect”, means reaching or even exceeding the 40 percent target would be possible "in principle." Michael Strogies, head of emissions reporting at the environment ministry expects Germany could come much closer to the target than predicted; "But I wouldn't say we exceed 40 percent just yet."

Tackling transport sector emission

All eyes are now on the transport sector which still lags far behind. The success in tackling energy-related emission was largely the result of result of political decisions, such as the expansion of renewable power sources in recent years or the gradual closure of coal plants since 2016.

Things will not be that easy for transport, where 2019 emissions ended up being 1 million tonnes higher than in 1990. Engine efficiency gains are routinely outweighed by sales of heavier and more vehicles and more kilometres travelled by car, and that the share of transport in total emissions is growing constantly.

Policy makers are aiming for a “turnaround in traffic” by freeing up more funding for sustainable transport alternatives to cars, particularly in inner cities.

Deployment of these medium-sized turbines is spurred by the need to repower existing infrastructure, or set up new integrated gasification combined cycle (IGCC) and combined cycle power with over 60% efficiency.

As combustion systems adopt a multi-fuel approach, combining natural gas, propane and distillate oil. Aalysts expect these technical variations across combustion systems will enhance the product applicability and further increase demand.

Growing environmental awareness and a subsequent trend to sustainable energy also spurs demand for hybrid power solutions, combining flexible gas turbines, renewables and energy storage.

Upstream sector drives demand

Rising upstream spending, notably in unconventional oil and gas resources, are expected to drive the related gas turbine market to an estimated $1.2 billion, growing at 3.5 percent annually through 2024. Major suppliers in this sector are GE, Siemens, Mitsubishi Heavy Industries, Solar Turbines, and Kawasaki Heavy Industries.

Gas turbines for mechanical drive is will witness highest growth from use in the offshore platforms and for remote exploration. By turbine size, the ‘1-20 MW’ turbine will remain most widely used but the turbine size ’20 MW and above’ will see the highest growth, as the industry prefers high efficiency over a small turbine footprint.

Quarantines and industry lockdowns in China have caused substantial supply chain disruptions, causing shortages of imported equipment for Korea’s energy-intensive industries, according to a Fitch Solutions report.

Manufacturing accounts for a large share of Korea’s power consumption, hence the Purchasing Managers’ Index (PMI) contracted in January and analyst anticipate the sector will continue to struggle well into the summer months.

Coal looses out to LNG

Sluggish electricity demand will likely led to a decline in coal-fired power plant dispatch, which may work in favor of gas-fired generation, based on imported and regasified LNG.

Prior to the corona pandemic, the Government in Seoul already announced a temporary suspension of 15 coal plants by the end of February, and to idle up to 28 coal plants by March. The remaining coal plants will have a cap on operational capacity of 80%, and six ageing coal plants will be retired by 2021.

The coal caps are part of a new energy policy roadmap, released in 2019, that includes bans on new-build coal power unit and a conversion of several existing ones to run on regasified LNG.

Looking ahead, Fitch sees a significant slowdown in electricity demand growth as South Korea’s GDP is projected to grow just 1.7% in 2020. Weak private consumption due to corona contingency measures will impact retail and services sectors.

In Italy, natural gas is the predominant fuel for power generation and the marginal fuel, hence a price setter for wholesale power markets. Supply swings from variable renewables generation during the relatively productive spring period tend to greatly determine gas demand for flexible peaking plants.

Traders are flabbergasted about the plunge in demand. Uncertainty about the duration of the lockdown in Italy and its economic impact reduces the appetite among traders to take risk which reduces market liquidity. Baseload contracts for April and Q2 shed around 7% over the past two days as traders react to a freefall in industrial energy demand.

Lockdowns slash energy demand

France imposed a near-total lockdown and Spain announced its quarantine will last more than 15 days, significantly impacting electricity demand from industries and the commercial sector. REE, Spain’s transmission system operator, disclosed it had set up a third control center to add redundancy to the system during the coronavirus crisis.

Should Germany, Europe’s largest power producer and exporter, also impose quarantine on its citizens this would exacerbate the bearishness across the continent’s power market. Depth and duration of energy demand destruction are bound to severely impact utilities’ future earnings.

“China remains a market to watch for its ability to rebound from an aggressive response,” Wood Mackenzie suggests. Across Asia, low LNG prices these days challenge and partly outcompete both thermal coal power units and renewables.

Traders rush into derivatives

As economies throughout the global grind to a near-halt as government impose increasingly drastic measures to contain the Covid-19 outbreak, consumption of crude oil and natural gas plunges with the surplus stored in inventories. Traded volumes for energy futures at the derivatives marketplace CME reached a daily record of 6.8 million as traders strive to hedge their positions.

Benchmark energy products have seen trading high volumes outside of U.S. market hours, demonstrating deep liquidity and flexibility around the clock, Chicago-based CME noted. Brent crude oil prices plunged from $64 per barrel on average in 2019, with the ICE Brent frontmonth May was last seen trading as low as $25.37/bbl.

Chandpur Power Generation, part of Doreen Power, had ordered four 18V51/60TS and two 20V45/60 engines for the new plant, which will feed 125 MW into the national grid.

“In Chandpur, the power plant operators have chosen a particularly innovative engine setup. The combination of our 20V45/60 engines and the 18V51/60TS engines with two-stage turbocharging guarantees maximum fuel efficiency and a more compact plant design thanks to a higher power density,” said Waldemar Wiesner, head of region Middle-East Africa, at MAN’s Power Plant Sales.

With 26 MW output per engine, the 20V45/60 is particularly powerful at a fuel utilization rate of over 50 percent. The customer in Chandpur also uses four 18V51/60TS engines, combined with two-stage turbocharging – a premiere for this engine type. The units come both with a low- and a high-pressure compressor, connected in series to improve power density and efficiency.

Adding 278 MW at Bogra and Chittagong

For Confidence Power, MAN has already built and handed over three power plants based on a total of fifteen 18V48/60 units in Bogra and Chittagong. The two plants in Bogra will generate 113 MW each to supply base-load electricity to the city, while the third power plant in Chittagong will feed 56 MW into the grid of the port of Bangladesh's second-largest city.

“As soon as all ongoing projects are finished, MAN will provide a capacity of approximately 2 GW nationwide,” Wiesner said, noting this corresponds to around 10 percent of Bangladesh’s currently installed capacity.