China had imposed additional tariffs on U.S. goods in retaliation to the U.S. Section 301 tariff measures. It had imposed a 10 percent tariff in September 2018 and increased the tariff to 25 percent from June 1, 2019, effectively halting gas trade between the two countries.

By granting exemptions on some retaliatory tariffs, Beijing strives to comply with commitments in latest Phase-1 trade agreement with Washington. The deal stipulates China will take an additional U.S. energy exports worth some $18.5 billion this year and another $33.9 billion in 2021.

Analysts anticipate this commitment will ultimately help rekindle Chinese demand for U.S. commodities, even though the coronavirus outbreak has seriously affected China’s demand for oil and gas.

China imported 1.53 million tonnes of US LNG in 2017, and 1.64 mt in 2018 but imports plunged in 2019 o just 258,955 tonnes in 2019 because of the trade war, while the Chinese purchased 60 mt from other countries. CNOOC, which has long-term offtake contracts, has been forced to swap U.S. cargoes for non-U.S. cargoes to avoid tariffs of 25 percent, sometimes at high premiums, because of uneconomic US-Asia arbitrage.

Coronavirus curbs China’s gas demand by up to 14 Bcm

China’s coronavirus health crisis has slashed the country’s gas demand by 2 billion cubic metres (Bcm) by the end of the first week in February, mostly due to industry closures and quarantined workers. Anticipating a “limited resumption of economic activity,” Wood Mackenzie says full-year 2020 gas consumption could be between 6 Bcm and 14 Bcm lower.

“LNG will bear the brunt of this reduction in domestic gas demand,” analysts commented, estimating the downside impact to Chinese LNG demand as between 2.6 million tonnes (Mt) ‘best case’ with recovery by April, and 6.3 Mt in a more ‘prolonged case’ with a slower return to normal.

Upstream activities in China stall largely as travel restrictions reduce manpower onsite. Baseload pipeline gas deliveries, however, as less affected as they can be handled in close-off. Hence, Wood Mackenzie estimates China’s domestic gas supply will be lower by between 1.6 Bcm and 2.9 Bcm this year.

Faltering Chinese gas demand could not have come at a worse time for the already oversupplied global LNG market. “Disappointing demand growth in Asia Pacific contributed to the halving of LNG prices through 2019,” research director Robert Sims said, “and with further new volumes emerging from U.S. producers, we were already anticipating lower prices through 2020.

In China, the industrial sector has been a focal point in the Government’s decarbonisation efforts given that industry consumes more than half of the country’s electricity supply and accounts for more than 70 percent of carbon emission. Electrifying industrial as well as agricultural is part of China’s latest 5-year plan, notably through replacing privately-owned coal power plant at industrial sites with cleaner alternatives, such as gas gensets or hybrid wind, solar and gas generation.

Energy Aspects sees a “massive growth” in the electrification of China’s industrial process, rising by 42 percent between now and 2040.

Demand grows mainly in Asia

As Europe and North America turns to renewables and energy storage, global gas demand growth will mainly take place in Asia. In China and India, Asia’s two large developing countries, analysts see “enormous scope to replace coal with cleaner gas in both power and industry.”

Asian gas demand is hence expected to rise by 82.8 billion cubic feet per day (bcf/d), equaling 856 bcm per year, by 2040 and grow from 21 percent of the global market to 29 percent.

However, as Asian gas production will only grow to 81 bcf/d, the region will face a shortfall in supply which will mostly be covered by Russian pipeline gas import and LNG from Qatar and North America. Substantial investments in gas import infrastructure will be required, followed by a build-out in gas transmission pipelines, if gas is to play a major role in Asian power generation markets.

The decision-making politburo of Vietnam’s Communist Party said in a planning document, the new energy strategy is “aimed at ensuring national energy security, and sufficiently supplying power for fast and sustainable socio-economic development.”

The construction spree is meant to raise the share of renewable energy sources to nearly 20 percent by 2030, while reducing reliance on emission-intensive thermal fuels. Coal, in particular, currently accounts for 38 percent of Vietnam’s installed power generation capacity.

Investing in LNG import infrastructure

Natural gas is meant to become one of the backbones of Vietnam’s future electricity mix. The Government has pledged to support initiatives to develop new regasification infrastructure to be able to import 8 million cubic metres of LNG per annum by 2030.

Hanoi is also trying to incentivise foreign and domestic private investment to help develop new power plants, and speed the privatisation of state-owned power companies.

U.S. LNG to fuel proposed CCGT in Bac Lieu

Singapore-based Delta Offshore Energy is developing a $4 billion LNG-to-Power project in Vietnam’s southern province of Bac Lieu. “Our investment model will be the predominant investment template going forward. The existing Public-Private Partnership model is obsolete given Vietnam's fiscal reality as debt levels approach the National Assembly's imposed ceiling and is re-enforced by Vietnam's sovereign credit rating threshold,” said Ian Nguyen, Director of Origination and Government Relations for Delta Offshore.

To ensure gas supply, Delta has signed an agreement with Australian-listed LNG Ltd, the developer of the Magnolia LNG venture to deliver 2 million tonnes per annum (mtpa) to Vietnam. The shipments from Louisiana would be on a free-on-board (FOB) basis for a 20-year term, with options to extend.

Once arrived at Bac Lieu, Delta will then regasify the landed LNG for use in its projected 3.2 GW combined-cycle power station. The 3.2 GW power station, designed to consist of four 750 MW gas turbine units and a fifth unit with 200 MW, is scheduled to start operations in 2023.

The German power generation sector, to date, has been shouldering a sizeable share of the Energiewende’s costs and progress. "Other sectors need to follow suit,” IEA Executive Director Fatih Birol said, suggesting “the government must now focus its efforts on achieving stronger emissions reductions in the transport and heating sectors."

The IEA welcomed Germany’s recently adopted Climate Action Programme 2030, which includes a carbon price in the transport and heating sectors. Setting a pathway for sector-specific emissions reductions, the Programme stipulates at 40 percent cut in greenhouse gas emissions by 2020, compared with the base year of 1990, and an 80 percent to 95 percent reduction by 2050.

The corresponding graph to this article shows the development of German CO2-emissions since 1990 and the national targets for the most important sectors up to 2030 on a percentage basis. Achieving these goals poses a challenge that should not be underestimated, Energy Brainpool analysts warned, as the simplest and cheapest emission reduction potentials have already been exploited in many cases.

Grid expansion and energy storage

Notable progress has been made in the power sector, where Germany 2019 achieved the largest decline in energy-related carbon dioxide emissions of any EU country, according to IEA data. To facilitate further renewable build-out, “the government will need to ensure a transmission grid expansion and promote the development of hydrogen technology,” Dr Birol stressed.

Continued strong investment needs to flow into wind generation to meet renewables build-out targets, which means that social acceptance and permitting issues need to be overcome.

In this context, the IEA urge the German government to facilitate the smooth system integration of renewable energy sources, in particular through a build-out of much-needed additional transmission capacity to carry wind resources from the north to the south.

Hydrogen (H2) is a vital compound that goes into the production of fertilizers and chemicals, as well as an essential reactant for many processes. Each year the world consumes 74 million tonnes of hydrogen and demand is expected to increase significantly in the future, as H2 is used to decarbonize the gas grid, industry, power generation, and transportation.

Following on from a successful first phase, the pilot plant will be built at Cranfield University in 2020 and become operational in 2021. The aim is to demonstrate the scale-up of the technology and process, and to offer a unique teaching and research facility for students.

“The Phase one work showed that the technology has great market potential and makes economic sense. Moving the technology forward will minimize greenhouse gas emissions, and we anticipate great benefits for consumers, industry, and the hydrogen sector,” said Mike Rutkowski, GTI Senior Vice President, Research and Technology Development.

New process could be 30% lower cost

GTI, a US-based research and development organization, has developed a technology that inherently captures the greenhouse gas carbon dioxide (CO2) during the hydrogen production process and shifts the chemical reactions to favor the production of more hydrogen. The outputs are high-purity streams of hydrogen and carbon dioxide which can be then stored, sold or transported to where it is needed.

The process for directly producing hydrogen from natural gas that will be used in the project is compact, yet scalable to very large plants. High-purity hydrogen can potentially be produced at up to 30% lower cost than with conventional steam methane reforming methods that require CO2 capture as an additional expensive process step.

Conventional technology is also limited in the portion of CO2 emissions that can be avoided with reasonable economics. Hence, the new process is hoped to be “more economical and efficient than other technologies as the product streams are pressurized.”

“Energy companies have to meet the reliability, cost, and safety needs that their customers demand at the same time they are reducing the impact on the environment. Hydrogen is a great solution for that,” Rutkowski pointed out.

Under the contract, valued some 1.15 trillion won ($ ), Samsung C&T will be responsible for the entire engineering, procurement and construction phase. Key to Samsung’s contract win was its strong track record on building power plants in the Middle East, such as the Al Shuweihat S2 IWPP in Abu Dhabi and the Qurayyah IPP in Saudi Arabia.

Samsung C&T and Marubeni, the two partners on the Fujairah F3 project, have already worked together on the Jawa-1 project in Indonesia. Currently, the South Korean EPC contractor is building a nuclear power plant in the UAE and a desalination plant in Qatar. The company claims the “the Fujairah F3 contract is sure to further solidify Samsung C&T’s position as a global EPC player in the region.”

“Early power” by summer 2022

Abu Dhabi Power Corp (ADPower), the operator of the Fujairah F3 plant, seeks to generate “early power” by summer 2022, and reach full operation by summer 2023. Once fully up and running, the 2,400 MW combined-cycle gas power plant will be capable to power the equivalent of 380,000 households in the UAE.

The F3 unit will be built at EWEC’s Fujairah power and water complex, situated 302 kilometres north of Abu Dhabi. Situated between the existing F1 and F2 water and electricity plants, the F3 IPP will add some 2.4 GW of contracted electricity output. This will boost ADPower’s overall power output at the Fujairah complex to 20.4 GW.

All electricity produced at the F3 IPP unit will be sold to Emirates Water and Electricity Company (EWEC). The new unit will be driven by “one of the most efficient and advanced CCGT technologies available in the region,” EWEC chief executive Othman Al-Ali pointed out. As part of the tender process, EWEC conducted a robust due diligence exercise to select the most attractive technical and commercial bid for this project.

Once operational, the 2.4 GW Fujairah F3 power plant will play a key role in securing the future electricity needs of Abu Dhabi and the northern emirates region. The F2 project, a 2 GW combined-cycle power plant, had been built by Fujaira Asia Power Co and Alstom Switzerland.

Calcasieu Pass LNG, situated Louisiana’s Cameron Parish some 50 miles south of Lake Charles, is expected to produce 10 million tons per annum of LNG once fully commissioned.

Site construction is underway, managed by Kiewit, and the compression trains are due to be shipped in summer and fall 2020. Commercial in-service date of Calcasieu Pass LNG is slated for early 2022.

“The Calcasieu Pass LNG Project involves an innovative modular, mid-scale configuration that enables Venture Global to produce low-cost LNG with a shorter construction schedule. Siemens was able to tailor a custom solution with added flexibility to match the EPC’s project schedule and start-up sequence” said Matthew Russell, executive vice president of LNG for Siemens.

Siemens’ scope of supply covers the engineering, manufacturing and testing of two centrifugal BOG compression packages and one reciprocating BOG compression package. All compressors will be directly driven by electric motors. The order win comes based on the German OEM’s long track record of providing cryogenic boil-off gas compressors for the LNG industry worldwide.

"By then, solar-plus-storage costs would already be competitive against gas peakers in all the National Electricity Market (NEM) states of Australia," said research analyst Rishab Shrestha. "The country's utility-scale solar-plus-storage LCOE will hover at about 23% above average wholesale electricity price."

 Only Thailand is expected to have a utility-scale solar-plus-storage LCOE below the average wholesale electricity price by 2023. While the country does not have a wholesale electricity market, industrial power price taken as a proxy is higher compared to other wholesale markets and hence shows competitive solar-plus-storage economics.

CAPEX subsidies and additional remuneration through renewables certificates are deemed crucial for projects to go-ahead. In general, Wood Mackenzie expect the average solar-plus-storage LCOE in Asia Pacific to decrease 23% from $133/MWh this year to $101/MWh in 2023.

“Storage is still at its infancy in market development. The market will need to fairly compensate the value storage provides in order for storage paired renewables to take off. There is also enough leg room for pure solar to be added to the grid, although the extent varies from region to region,” Shrestha commented

Going forward, business models still need to be refined according to market design and future policy options. Safety and fire hazards also need to be looked at carefully. “Once these challenges are addressed solar-plus-storage will be a great asset for the power grid,” he said.

On the distributed C&I solar-plus-storage front, the storage premium over solar LCOE is between 56% and 204% this year. This cost premium is expected arrow to between 47% and 167% by 2023.

"The reason you have such wide LCOE range is because we have some mature markets where solar cost is extremely competitive while others are not and some in-between. This is due to a mix of labour/ land/ environment/ civil costs, weighted average cost of capital, and procurement methods -- tenders versus feed-in tariffs (FIT). Also, some markets have very well established supply chains with the availability of storage manufacturing," Shrestha explained.

Unsubsidised C&I solar-plus-storage is expected to be competitive in Australia, India and the Philippines by 2023.

Built at a cost of $2.5 billion, the South Texas-Tuxpan pipeline is a crucial outlet for US natural gas as can deliver up to .6 billion cubic feet per day to the southeast of Mexico. The interconnector is jointly owned by IEnova and Canadian pipeline company TC Energy.

Progress is also being made on other Mexican pipeline projects. The Marine Pipeline started operations in September, and a month earlier IEnove resolved matters related with to the Marine and Sonara pipeline with the Mexican energy regulator CFE. However, there are still open issues regarding the Guaymas-El Oro pipeline which the developer is working on with government entities.

Investment in 2019 amounted to $665 million, primarily related to the solar and liquid terminal projects and funding of $49.1 million for Costa Azul LNG and $15.8 million in the South Texas-Tuxpan pipeline which is linked to Enbridge’s Valley Crossing Pipeline in Texas.

Renewable energy is IEnova’s second stronghold in Mexico where it just took financial close on the 150 MW Border Solar project, to be built at a cost of $160 million. Three solar photovoltaic ventures were place in service at Pima, Rumorosa and Tepezala. Once all of IEnova’s renewable projects become operational, they will have over 1,000 megawatts installed capacity contracted long-term in U.S. dollars with high-quality offtakers and with a total investment of around $1.8 billion.

IEnova parent company Sempra has a strategy to achieve around 45 million tonnes per annum of LNG production by the mid-2020s through three plants, the Cameron facility at Hackberry in Louisiana that came on stream in 2019, the Port Arthur plant in Texas and the Costa Azul facility.

FID on the Costa Azul liquefaction project is targeted to be reached later this quarter, IEnova announced. For this venture, the company already signed three Heads of Agreements with Total, Mitsui and Tokyo Gas.

Striving to outcompete rival suppliers, notably U.S. LNG, Gazprom stressed its competitive advantages includes a “vast resource base,” which it claims is “sufficient for providing cheap and reliable gas supplies for many decades to come.”

Most of Gazprom’s sales are handled via a robust network of export routes and strong partnerships with major utility buyers in throughout Europe and the former states of the Soviet Union.

Turning away gradually from its traditional gas sales on long-term, oil-indexed contracts, Gazprom in September 2018 launched its own Electronic Trading Platform (ETP). From this platform, Gazprom has been selling spot volumes to new and existing counterparties, for delivery to ten destinations in central and northwest Europe. 

The weighted average price of transactions on the ESP has been below the average price of Gazprom’s LTC sales to Europe since February 2019 and has been between the average hub prices at TTF-Gaspool (floor) and Austria-Slovakia VTPs (ceiling) since April 2019, according to figures by the Oxford Institute of Energy Studies (OEIS). Analysts hence expect the new trading platform to gain acceptance and liquidity.

Looking ahead, Gazprom said it is looking into hydrogen energy projects, notably technologies to produce hydrogen from natural gas without CO2 emissions.

This winter, unseasonably warm weather and the coronavirus outbreak in China had destroyed a substantial amount of regional demand, which pushed prices to record lows. The spread between the Japan-Korea-Marker (JKM) and the Dutch TTF gas trading hub narrowed substantially, making it more attractive for LNG sellers to ship excess cargoes to northwestern Europe.

At record low prices, natural gas is becoming more competitive as a fuel in the European power generation sector. But things are unlikely to last for long. "While we see weak market conditions today due to record new supply coming in, two successive mild winters and the coronavirus situation, we expect equilibrium to return," said Maarten Wetselaar, integrated gas and new energies director at Shell.

Demand destruction to continue into March

Though the virus pandemic has badly affected China’s gas consumption in February, which will likely continue into March, Shell is convinced that the country’s LNG demand will grow by 4 million tons or even 6 million tonnes this year. Beijing’s clean air policies remain in place, which last year increased gas demand by over 14 percent due to coal-to-gas switching in the power sector as well as other efforts by industry and manufacturers to improve air quality.

After 2025, however, Shell expects a “material reduction” in the growth of global gas supply. Asian markets are seen regain strength and absorb most volumes while Europe will cease to be the market of last resort, the oil major said in its latest LNG Outlook.

As anti-air pollution measures get implemented in many Asian countries, gas demand in the power sector will continue to evolve. In Wetselaar’s view "record supply investments” will be needed to meet people's growing need for “the most flexible and cleanest-burning fossil fuel.”

Natural gas emits between 45 percent and 55 percent fewer greenhouse gas emissions, compared with hard coal or lignite, and less than one-tenth of the air pollutants of coal when used to generate electricity.

The Saudi Prince Abdulaziz bin Salman announced over the weekend that the development of the field over 22 years would provide the government with an annual net income of $8.6 billion and contribute $20 billion to the kingdom’s gross domestic product per year. A week earlier he promised Saudi Arabia would “soon” be able to become a natural gas and a petrochemical exporter.

Production to be fully ramped up by 2036

Al-Jafurah, the kingdom’s largest non-associated gas field, is estimated to contain 200 trillion cubic feet of rich raw gas, or wet gas, which would provide ample feedstock for the Saudi petrochemical industry, domestic power generation and exports. Targeted to start production in 2024, the output of the field is meant to be ramped up to approximately 2.2 billion standard cubic feet per day of sales gas by 2036.

Ultimately, Aramco expects the field to produce some 550 thousand barrels per day of gas, both liquid and condensate. In addition, there will be an output of some 425 million standard cubic feet per day of ethane, equaling about 40 percent of production.

The state-run Aramco has been heavily investing in gas exploration lately. More rigs have been drilled for natural gas than for oil for the first time in seven years, in line with so-called ‘localisation efforts’. Saudi Aramco has set a production target of 23 billion cubic feet a day (bcf/d) of gas by 2030, up from currently around 14 bcf/d, and the energy giant has undertaken key projects to boost output from conventional gas fields.

Aspiring to end oil-fired generation

Striving for a more sustainable power sector, the Saudi Kingdom wants to generate 70 percent of its electricity from gas and 30 percent from renewable energy sources, the Saudi energy minister, Prince Abdul Aziz bin Salman said. Simultaneously, strives to use domestic gas as a feedstock for its larges petrochemicals industry. Any excess gas production will be exported.

Saudi Arabia is one of a handful of countries that burn crude oil directly for power generation. Normally, countries avoid burning expensive oil and turn to gas or coal for power generation. However, Saudi Arabia has no domestic coal production, and most of its natural gas is associated gas, which is produced along with oil from the same wellbore.

By 2030, the Saudis’ electricity demand is seen to more than double, and by then up to 60 percent of the ageing oil-fired capacity is meant to be replaced by gas generation: This ambitious plan requires an investment of up to $18 billion.

In the Reference Case of the EIA’s Annual Energy Outlook 2020 (AEO2020), total U.S. energy consumption increases at an average annual rate of 0.3% between 2019 and 2050, and GDP grows at an annual rate of 1.9%, which indicates a 1.5% average annual decline in energy intensity through 2050

Similarly, in the Low Economic Growth case, energy intensity declines 1.4% annually.

Energy efficiency measures allow industry and household customers to use petroleum, natural gas and electricity more effectively. Strikingly, the domestic energy use associated with each dollar of U.S. economic growth will by 2050 be less than half of what it was in 2005.

Industry’s energy use is seen grow at an annual rate of 0.8 percent through 2050. Energy intensity, measured as energy consumption per dollar of output, is seen fall by 0.4 percent per year as the EIA expects less energy-intensive manufacturing industries to grow faster than others.

In the transportation sector, energy consumption is see fall by an average of 0.2% annually between 2019 and 2050. In the view of the U.S. Government, there is no need for more stringent fuel efficiency regulations for new light-duty vehicles after 2025 nor for new heavy-duty vehicles after 2027.

“Ultimately, vehicle travel demand outpaces fuel economy improvements,” EIA analysts commented, suggesting that on-road transportation sector energy consumption will increase starting in 2041. More energy-efficient technologies are adopted, however, for rail, bus, and air travel.

Commercial energy use is seen grow at a 3 percent rate, while residential energy use will likely stay flat through 2050. Analysts pointed out that “improvements and growth in distributed electricity generation, including on-site solar, partially offset the effects of growth in the U.S. population, households, and commercial floorspace.”

Combustor enhancements can significantly reduce smog-promoting emissions like oxides of nitrogen (NOx) while also helping to balance the intermittent power supply coming from an ever-increasing portfolio of renewable generation. 

PSM committed substantial investments over a 20-year history to develop combustor retrofits for industrial heavy-duty gas turbines. “Technical capability and the business case to successfully develop, deliver and service new advanced combustion technology retrofits is an extremely high barrier to market entry proposition for any OEM, but especially for an aftermarket multi-OEM gas turbine full-scope service provider like PSM.  But we have  overcome these barriers and are proud to be able to deliver positive commercial results for our customers.” said Jeffrey Benoit, Vice President – Strategy & Marketing, PSM – Ansaldo Energia Group. 

“Apart from the capital requirement, a company must have the R&D, analytical and operational expertise plus the ability to identify innovative concepts to deliver necessary performance and reliability requirements.  From here, direct access to a high pressure, high temperature test rig facility to fully evaluate the combustion designs is a must. Finally, there is the ability to support the commissioning of the retrofit solution and offer post-installation services like repair.   These capabilities and the business value of the product to the customer are an absolute must to convince them to purchase and install our solution into their gas turbine fleets,” he told Gas to Power Journal.

Dow Chemical’s as 1^st customer

The first LEC-III upgrade was carried out in 2003 at Dow Chemical’s GE Frame 7EA gas turbine at their Oyster Creek facility in Texas. The straightforward and direct retrofit achieved a commercial world record of sub-5ppm NOx emissions over the necessary operational load range. 

To date, the PSM fleet of LEC-III systems operate on five different types of gas turbines (GE Frames 6B, 7B/E/EA and 9E plus Siemens Westinghouse 501B6 and 501D5) and have more than 1,500,000 hours of operation on over 80 customer gas turbines.  Additionally, design enhancements recently implemented and operating on customer machines are allowing the consumption of up to 35% by volume of hydrogen mixed with natural gas fuel, significantly reducing the turbine’s carbon emission intensity.   

“LEC-III is patented technology first incorporated into GE Frame 7E/EA gas turbines in 2003 and into the Frame 9E in 2004,” Benoit underlined. This can-annular, reverse-flow combustion system was designed to be a direct replacement into an existing gas turbine outfitted with the OEM’s DLN-1 system. 

The PSM lean premixed system, includes fuel nozzle assemblies, transition pieces, flow sleeves and combustion liners which were initially designed to achieve less than 15ppm NOx (corrected to 15% O2) at baseload conditions or 30mg/Nm3.

“Lower oil prices, if sustained, are bad news for highly responsive US oil companies, but we are unlikely to see an impact on output growth until later in the year,” analysts at the International Energy Agency (IEA) commented.

As the novel coronavirus (Covid-19) has turned into a global public health emergency, analysts expect are lasting slowdown in oil and gas consumption in China and beyond. Demand for crude oil is expected to contract by 435 thousand barrels per day (kb/d) in the first quarter, and for 2020 as a whole the IEA has lowered its forecast by 365 kb/d to 825 kb/d.

Sluggish demand in China and a global supply overhand have had a sharp impact on prices. Brent values fell by about $10 per barrel, or 20 percent, to below $55/bbl. However, analysts remarked “the effect of the Covid-19 crisis on the wider economy means that it will be difficult for consumers to feel the benefit of lower oil prices.”

China’s gas demand could plunge up to 14 Bcm

The coronavirus health crisis has slashed China’s gas demand by 2 billion cubic metres (Bcm) by the end of the first week in February, mostly due to industry closures and quarantined workers. Anticipating a “limited resumption of economic activity,” Wood Mackenzie says full-year 2020 gas consumption could be between 6 Bcm and 14 Bcm lower.

“LNG will bear the brunt of this reduction in domestic gas demand,” analysts commented, estimating the downside impact to Chinese LNG demand as between 2.6 million tonnes (Mt) ‘best case’ with recovery by April, and 6.3 Mt in a more ‘prolonged case’ with a slower return to normal.

Prior to the coronavirus outbreak, analysts had hoped the Pacific Basin gas market would 9 Mt of the approximately 27 Mt of new supply growth in 2020. However, a mild winter had already weakened prices at the North Asian spot market before the virus stifled demand in China.

Supply correction needed

“With too much LNG, and nowhere left to place it, it looks like a supply correction is needed to balance the market,” Sims said. “We are expecting supply response in some markets like Egypt and potentially in Eastern Australia, where the likes of Shell and APLNG could attempt to sell gas into the domestic Queensland gas market.

“However, it is US Gulf producers who have the highest marginal cost of supply and the most flexibility,” he stressed, implying there might be some shut-ins of liquefaction capacity along the Gulf of Mexico.

Despite the current gas demand destruction, analysts remain bullish on China’s gas demand for the remainder of this year, provided there is no second outbreak of the virus. “We still think that the political importance of ensuring robust GDP growth this year and further coal-to-gas boiler switching should provide strong demand growth in H2 20, provided there is no second outbreak of the virus,” Energy Aspects said in market note.

Floating cargoes “look distressed”

The recent slump in Chinese LNG imports left several cargos stranded in the Pacific Basin, with over 25 cargos counted as being held as floating storage, according to Kpler cargo-tracking data. Ten of these cargoes originate from Australia, seven from Qatar and three from Nigeria.

Cargoes loaded in Asia-Pacific, notably Australia, are unlikely to be shipped all the way to Europe. “The cost of freight would generate an unprofitable netback, given the weakness in European near-curve prices,” Energy Aspects said, but noted “there is no financial incentive to store these cargoes in Asia either,” given that the JKM near-curve was backwardated into Apr-20 and then in a weak contango through the following summer 2020 months.”

The cost of storing a cargo for a month is around 0.69 $/mmbtu, while the while the JKM Apr-20 contract closed on 14 February at a 0.15 $/mmbtu discount to the May-20 contract. Energy Aspects consequently concludes that “all of these floating storage cargoes look distressed.”

Floating LNG storage weakens demand for spot cargoes and will likely keep the prices for JKM Apr-20 and May-20 contracts around the same level as TTF equivalents in Europe. This narrow spread discourages deliveries of any excess cargoes from northeast Asia to the Atlantic Basin.

Delaying, or cancelling shipments

Trying to accommodate, Qatargas agreed to reschedule some of its long-term contracted shipments to China. Others contractual suppliers are seeking to reinforce their delivery rights. Shell and Total, for example, have recently rejected China National Offshore Oil Corp’s (CNOOC) move to invoke ‘force majeure’ to cancel LNG import contracts. Though CNOOC can still cancel delivery of spot cargoes, the two European suppliers threatened to seek compensation.

CNOOC took the drastic step encouraged by the Chinese government, which said it would hand out ‘force majeure’ certificates to domestic companies if they cannot fulfill their offtake obligations as the coronavirus crisis accelerates. Beijing apparently tries to mitigate potential losses of state-owned gas companies. PetroChina and Sinopec followed suit by invoking ‘force majeure’ on some contracts, claiming they cannot get enough workers to run their regasification and import terminal at full capacity.

The hybrid power unit has been ordered by an unnamed oil and gas producer active in Sierra Chata, in the province of Neuquén. Under the contract, Aggreko will provide a bespoke hybrid package comprising of 6 MW electric capacity from gas generators, combined with a 1 MW energy storage unit.

This hybrid approach will increase the power plant’s overall efficiency while reducing consumption by between 13 percent and 20 percent. For the client, this means lower power generation costs, carbon emissions, and improved reliability. The site uses gas produced on site, lowering fuel costs and increasing the site’s energy efficiency.

The project marks the first time Aggreko installs a battery storage system in Latin America, in the challenging region of Patagonia. Demand for such for hybrid power technologies are expected to rise as the energy transition progresses.

“As the market for off-grid generation capacity continues to evolve, we are seeing our customers demand ever-more innovative solutions to cut costs, reduce emissions and increase the reliability of their power supply,” said Aggreko’s Managing Director for Latin America and the Caribbean, Pablo Varela.

Net injections during the refill season (April 1–October 31) will bring the total working gas in storage to 4,029 Bcf, the U.S. Energy Information Administration’s (EIA) forecast. If realized, would be the largest monthly inventory level on record.

Mild winter weather pushed down gas prices and led to smaller gas withdrawals from storage for heating and power generation. Demand for natural gas tends to be highest in winter months due to space heating, while gas-burn in the power sector greatest in summer months, when overall electricity demand rises because of air conditioning.

Abundant production outpaces exports

On the supply side, the continuous growth in gas production outpaced exports of both pipeline gas to Mexico and LNG which propped up storage levels to record high.

At the start of this heating season, total gas in storage stood at 3,725 Bcf at the end of October. EIA analysts anticipate withdrawals from working gas storage to total 1,790 Bcf at the end of March 2020.

In its February Short-Term Energy Outlook (STEO), the EIA expects the total working gas in storage will exceed the previous five-year average for the remainder of 2020, despite declines in dry gas production, increases in gas-burn in the electric power sector, and rising exports.

Monthly gas production is seen ease off 2020 from last year’s record levels as lower Henry Hub prices reduce incentives for gas-directed drilling and as lower crude oil prices curb drilling activities for oil and associated gas.

Some observers said the Palmdale Energy Project was the victim of fierce opposition from environmental and community groups. The Antelope Valley, where the power plant was to be built, already has a smog problem so residents filed a lawsuit challenging the EPA’s reliance on fossil energy sources. Ultimately, the developer and the Palmdale City Council agreed to shelve the project.

Palmdale Energy, a subsidiary of Summit Power Group, had purchased the project in 2015. It was first proposed in 2001 to help reign in California’s energy crisis and rolling blackouts at the time.

The city of Palmdale has spent some $9.25 million on the project in recent years as the proposed power plant evolved from a 570 MW hybrid unit, based on gas and solar, to the most recent 645 MW gas-only power plant.

Renewables favours over fossil fuels

Over the course of ten years, Californian lawmakers developed a renewable portfolio standard that requires 60 percent of the state’s electricity mix be renewable by 2030. Some 34 percent of California’s energy mix was renewable last year, and energy storage is also strongly on the rise as a balancing tool.

The Bill 2514 mandated the California Public Utilities Commission (CPUC) to adopt an energy storage program and procurement target. As a result, the regulator set a target of 1,325 MW installed energy storage by 2020.

Technology improvements could allow for a further slide in price to 80 cents by 2050, equivalent to a natural gas price of $6/MMBtu. At this price, green hydrogen-fuelled power stations would be cost competitive with natural gas-fired power plants in most market zones around the globe.

Green hydrogen “already cost competitive”

Producing green hydrogen via electrolysis of water, using electricity from wind and solar power sources, is still more costly in most markets than the alternative method where natural gas is ‘reformed’ into hydrogen and CO2.

In Germany and Texas, however, hydrogen produced using wind power is already attractive for small- and medium-scale users, Gunther Glenk and Stefan Reichelstein write in a research paper.

Renewable hydrogen, produced for €3.23/kg, is already cost competitive in niche applications, although not yet for industrial-scale supply. This might well change within if the cost for renewable hydrogen continues to fall towards €2.50/kg.

If a power-to-gas facility can also source electricity from the grid, it would achieve higher capacity utilization which may substantially lower break-even prices for hydrogen.

Hybrid power plants, combing renewables with a power-to-gas station, can produce hydrogen cheaply by taking advantage of fluctuations in electricity prices and intermittent renewable energy supply. Once produced at scale, hydrogen is very valuable as it can be used for power generation or for storing excess renewable energy in the natural gas grid.