“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.

Supply correction needed

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.

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.

“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.

LNG contracts under force majeure

Encouraged by the Chinese government, CNOOC declared force majeure on LNG import contracts. CNPC and Sinopec could soon follow suit. However, Shell and Total already dismissed the validity of ‘force majeure’ in the current circumstances and threatened to seek compensation.

Critics argue the wide spread between high contracted long-term prices and low spot market prices have prompted CNOOC to exercise force majeure. If Chinese buyers succeed in doing so, the revenue impact on sellers could be significant.

The approximate price for many of these oil-indexed contracts is around 14.5 percent of oil range, equating to $8.83 per million British thermal units (MMbtu), using $54 per barrel of oil equivalent. According to Wood Mackenzie figures, this compares with spot prices of around $3.15/MMBtu.

Total contracted volume into China in 2020 is 54 million tonnes per annum. “While major Chinese buyers may call for force majeure, suppliers may instead insist on trying to defer deliveries to later in the year once the demand impact of coronavirus has diminished,” Sims concluded.

The USTDA-funded feasibility study will evaluate the Abuja CCGT project as a means to enhance critical electricity supply in Nigeria. The aim is to reduce recurring power shortages, load-shedding and frequent blackouts that cripple the local economy.

NNPC Group’s managing director, Mallam Mele Kyari said he was convinced the grant will help “concretize arrangements to provide stable power supply to Abuja in the foreseeable future.” The project is hoped to soon reach financial close.

Developed as an Independent Power Project (IPP), the Abuja plant will be fuelled by natural gas from NNPC’s large upstream resources, delivered to the plant’s site through the proposed AKK gas pipeline. Mr. Kryandi explained the Abuja CCGT project was part of the national strategy towards monetising Nigeria’s abundant natural gas resources

Most of the generating equipment will be supplied by GE.

Technical support for the project will also come from the U.S.-firm Continuum Associates whose chief operating officer, Sandeep Baidwan, said the proposed CCGT “will provide important relief to the power deficit situation” in and around the Federal Capital Territory region, and northern Nigeria.

“This agreement will support the continued growth of New Fortress’ customer base in international markets as the company develops LNG terminals and natural gas infrastructure,” New Fortress said without disclosing the counterparty of the deal.

From its 100,000 gallons per day liquefaction and export plant in Miami, NFE produces LNG for export in intermodal ISO containers to the Caribbean and to small-scale customers in southern Florida. It operates a floating LNG import terminal in Montego Bay, Jamaica, along with a fuel-handling facility and an associated import contract in Puerto Rico.

At San Juan Harbor, Puerto Rico, NFE is building a micro fuel handling facility to serve on-island power and industrial customers via LNG truck loading and onward distribution.

In Jamaica, NFE pledged to invest close to $1 billion into the country’s gas and power sector – the latest milestone being the ground breaking for a $265 million LNG-fuelled combined heat and power plant (CHP) at Jamalco’s Halse Hall headquarters in Clarendon.

The offshore Old Harbour Terminal, commissioned in 2018, features an FSRU and natural gas pipeline to supply fuel to a nearly 190 MW power plant and the about 150 MW Jamalco combined heat and power plant.

Regasified LNG helps transform Jamaica’s power mix. Two years ago virtually 100 percent of the energy in Jamaica was generated by oil, and now some 600 MW of capacity is powered by natural gas and renewables.

Uniper’s CEO Andreas Schierenbeck said Germany needs a consensus on how to ensure future supply security. “Until that is clear, nobody will construct power plants.”

Several mechanisms are under discussion to “optimise the energy-only-market” such as auctions for a “strategic capacity reserve”, a focused or comprehensive capacity market, or simple direct payments to operators per installed capacity they keep in standby mode. In contrast to an energy-only-market, in which operators are paid for the kilowatt-hour they produce, in the capacity market they receive remuneration for the capacity they keep ready for certain situations.

The government, eager to advance its Energiewende policy, concedes that natural gas will play an important role as a bridge fuel. Coal use fell significantly in 2019, while power generation from gas increased 11 percent compared to the previous year. But due to high operating costs, gas-fired power plants are often pushed down the merit order and throttle production, especially when there is a lot of renewable electricity available.

In fact, Germany’s gas power plant tend to produce less than 30 percent of the electricity they could have generated had they run at full power all year. This rare dispatch undermines their business model and affects German power plant operators and manufacturers alike.

Growing need for backup capacity

With the continued electrification of transport, buildings and industry, there is a growing need for reliable backup generation at times of high power demand and when wind and sun are in short supply. 

“Today, on a cold, dark winter day, the loads created in heating are about five to six times the peak loads of the power system,” said Timm Kehler, head of Zukunft ERDGAS.

Gas power units can be ramped up and down comparatively quickly, meaning they could be a good partner for fluctuating renewables. Some see it as a “bridge technology” for the energy transition. Battery storage technology can partly be used to balance out the variations in power feed-in.

Deregulating the gas market, with Thailand’s Energy Regulatory Commission (ERC) has assigned country’s prime power producer EGAT some 1.5 million tons per annum (mtpa) of import capacity at the Map Ta Phut LNG terminal. Prior to the market liberalization, only the state-owned oil and gas champion PTT was granted a license to import LNG.

Though PTT is mandated to provide gas storage capacity to EGAT until the latter’s LNG stock has gradually been fed into its thermal power stations, PTT is bound by ‘take or pay’ clauses to fulfill its contractual LNG import obligations regardless of domestic demand. This has prompted the regulator to deny EGAT to enter direct long-term gas supply contracts, e.g. with Petronas of Malaysia.

Instead, EGAT has been limited to buying relatively small volumes of LNG on the spot market, with the first of two cargoes arriving in December last year and second not due before April this year. For the time being, EGAT need to continue sourcing most of its gas for power generation from state-owned PTT.

Policy makers in Bangkok are actively backing a coal-to-gas shift in the power sector. Seeking to stop burning lignite eventually, the government expects more than 24 mtpa of LNG will have to be imported starting from 2027, compensating for depleting domestic resources. Costs for locally produced gas have reached $7-8/MMBtu, with analysts anticipating costs to rise further as PTT is forced to employ more field support measures to prevent production from collapsing.

To finally open up the gas market, Thailand’s energy ministry has proposed a free-trade hub whereby each company would be permitted to import and re-export LNG on the spot market. This would help balance the market and allow PTT to gradually turn away from ‘take-or-pay’ contracts. However, limited import capacity and vested interest from incumbents have so far hampered the realization of such a free-trade hub.

"Green hydrogen is tomorrow's oil and offers huge opportunities," research minister Anja Karliczek said after a meeting with her colleague from Niger, Yahouza Sadissou. The ministry is surveying 15 states in search of suitable production locations and is prepared to invest 30 million Euros to initiate a "true cooperation" with African partner states.

From West Africa, hydrogen would need to be shipped to a German port as a liquid in super-insulated, cryogenic tanks. Kawasaki Heavy Industries in December launched the world's first liquefied hydrogen carrier, featuring a 1,250 cubic meters hydrogen storage tank. The first tanker is currently used to ship liquefied hydrogen produced in Australia to Japan.

Aiming for 20% green hydrogen by 2030

The German coalition government in Berlin is working on a hydrogen strategy that will specify how renewable hydrogen could become a cornerstone of country's decarbonisation efforts. The draft document says that by 2030 about 20 percent of hydrogen could be produced from wind and solar power. However, Germany is unable to cover its expected demand for green hydrogen itself, so additional volumes need to be imported from Africa or possibly Australia.

Ultimately, hydrogen is meant to replace oil and natural gas in cases where other decarbonisation measures are difficult to apply, for example in aviation or in energy-intensive industries.

Few new pipelines needed to build hydrogen network

Germany's gas industry plans to establish a 5,900 kilometres pipeline network to enable the large-scale use of hydrogen use. FNB Gas, representing German gas TSOs, intends to use mainly existing infrastructure to transport hydrogen from future generation sites in the north of the country to industrial centres in the west and south.

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

The industrial park is currently operating on electricity from the national grid. However, as more and more factories are being built, independent on-site power generation is needed to ensure a reliable electricity supply, and to control the cost of that supply.

“An uninterrupted power supply is a basic need for industry, and to ensure this we need to have our own captive plant. Wärtsilä has a strong presence in Bangladesh with a first-rate track record and excellent support capabilities. What is more, they can deliver the plant quickly,” said Mr Shamim Islam, Managing Director, Jamuna Power.

Delivery of the equipment will be completed during the first half of 2020, Wärtsilä said, and the aim is to get the plant fully operational in early 2021.

Gas supply infrastructure already exists at the location, so choosing gas engines was a “natural choice” to power the industrial park. Steam produced by the engines will be used in various industrial processes within the complex, which will enhance the operational efficiency of the plant.

“Economic growth is difficult to achieve unless the power supply can be relied on, and the need in this case is very clear. Since the Jamuna Industrial Park is a large local employer, jobs also depend on the new power plant,” said Jillur Rahim, Managing Director, Wärtsilä Bangladesh.

Across Bangladesh, Wärtsilä currently has more than 4,900 MW of installed or ordered power generating capacity, of which about a quarter is operated and maintained by the Finish OEM. Factoring in the new order, 84 Wärtsilä 34SG gas engines will be in use in the South Asian country.

Varegro has chosen to install an onsite generator to have a dependable energy source at hand that protects the industry from potentially damaging power outages. Even during extreme climate conditions, the reliable generator can ensure that farmers will not lose their crops.

Cummins said its HSK78G gas generator has been designed to operate in extreme weather conditions and so has a full power capability up to 40°C (104F) with standard turbo offering and up to a blistering 55°C (131F) with high ambient turbo offering.

Total CHP efficiency reaches 103%

Electrical efficiency of the CHP generator reaches 44.2 percent, allowing fuel savings by turning waste heat into productive energy. “In an energy-intensive greenhouse environment its total return is greater than 100 percent,” Cummins claims, suggesting that Varegro can use this reliable power source to flexibly meet its own energy needs. The electricity that is produced can be used for lighting, recuperation and hot water.

“The HSK78G generator at the facility is designed to provide reliable power, regardless of the natural gas source or the climate. With the addition of the exhaust gas heat exchangers and heat condensers, low and high temperatures can be recuperated achieving a total efficiency of 103 percent,” said Stefan DeWit, project manager at Cummins Power Generation.

Any surplus of electricity hat is being produced at the facility is then sold back to the grid network, which offers greater financial savings for Varegro. In general, HSK78G generators are suitable for a diverse set of industries from mining to manufacturing to shopping malls and hospitals.

“During film cooling, cool air is bled from the compressor stage, ducted to the internal chambers of the blades and vanes, and discharged through small holes in the blade and vane walls. This air provides a thin, cool insulating layer along the surface of the blades and vanes,” explained Jens Dickhoff, technical manager at B&B Agema.

Tests were carried out at Kawaskai’s L30A gas turbine. Hereby, Nekomimi technology combines the two cylindrical holes of the DJFC within a single hole design to overcome the inefficiency of the air supply situation. This was achieved by shifting the holes of the DJFC configuration to the same streamwise position, uniting both holes, and replacing the two supply holes with a central one.

The computational domain used to virtually test the cooling effectiveness of different shaped holes: The result has been profound cooling improvements of 200% to 300% in the nekomimi designs over reference shaped holes – technology that has been co-patented by KHI and B&B Agema

Recently B&B Agema and KHI decided to automate their design search through the use of HEEDS, the design exploration software from Siemens PLM’s Red Cedar Technology subsidiary, and the HEEDS-based Optimate+TM add-on module for STAR-CCM+.  “This change makes it possible for them to evaluate hundreds of designs in the time previously required to assess just a handful, methodically comparing large numbers of traditional fan-shaped hole designs to nekomimi-shaped holes,” researchers explained.

During the design search procedure, Optimate+ was used for the automated design exploration process, STAR-CCM+ for fluid flow and heat transfer simulation as well as geometry modeling of the fan-shaped holes, Siemens NX for parametric geometry modeling of the nekomimi-shaped holes, and HEEDS Post for visualizing and interpreting results.

This novel approach makes it possible to build a database of the best nekomimi cooling-hole designs for a variety of pressure ratios and coolant mass flow rates. From this database, cooling-design engineers can select the best design to achieve higher cooling effectiveness and lower cooling air consumption.

“For all kinds of film cooling holes, this study strongly enhances basic understanding of secondary flow phenomena and their impact on cooling effectiveness. Further, it proves the value of automated design space exploration for solving a broad range of standard engineering problems,” Dickhoff concluded.

The Narrabri coal seam gas project spans around 95,000 hectares in the Pilliga forest in the north-western part of New South Wales (NSW). Santos is seeking approval to drill up to 850 natural gas wells on no more than 425 sites, as the developer believes the prolific acreage could hold supply up to 50 percent of NSW natural gas needs.

Prime Minister Morrison just entered an agreement with the Premier of NSW to double local gas production and to jointly underwrite the projected gas interconnectors between the Snowy area and Sydney. The deal involves Commonwealth funding for renewables and power grid upgrades in return for the NSW Government setting a target of delivering 70 petajoules a year of new gas into the market. Strikingly, that is almost exactly the estimated output of the Narrabri project.

Dispute over cost estimate

The aim is to lower energy bills by making use of comparatively cheap domestic gas resources and gradually replace coal use in the power sector to reduce emissions. Critics warn, however, that the Narrabri gas is relatively expensive to produce. According to an estimate from the Australian Energy Market Operator (AEMO), the cost at the well head is $7.40 a gigajoule.

Santos CEO Kevin Gallagher disputes the AEMO’s estimate of gas production cost at Narrabri, claiming these were "based on old data and simply wrong."

The Prime Minister has pledged NSW will receive A$960 million in federal funding to upgrade the energy grid and invest in coal-to-gas switching. Another A$2 billion co-investment will go towards clean technology, hydro research development and commercialization as well as energy efficiency to reduce power bills.

“Working with the states is absolutely critical. The NSW deal commits both governments to do even more to encourage investment in reliable energy generation and transmission, I should stress, in transmission,” the PM explained.

Next in line seems to be the state of South Australia, where the state premier Steven Marshall plans to release a strategy on how the state will achieve emission reductions.

Beltransgaz, now renamed Gazprom Transgaz Belarus, needs to renegotiate terms of Russian oil and gas deliveries every year on December 31 – the very date when Gazprom’s transit agreement with Ukraine also comes to an end. However, while Naftogaz Ukrainy and Gazprom are embroiled in a lengthy dispute over gas supply, pricing and payment, Russia’s energy relations with its western neighbour Belarus have been very smooth sailing given that the long-serving Belarusian President is a political allay of Russia.

The latest deal is vital for European security of supply because the Belarus-Poland pipeline link is one of Gazprom’s three main arteries of supplying Russian gas onwards to Germany and beyond. Russia currently supplies one-third of Europe's natural gas and wants to maintain its export at this level, which is why it is pressing ahead with the completion of Nord Stream 2, the second pipeline leg of a major interconnector through the Baltic Sea to Greifswald in northeast Germany.

Pipeline politics

Once Nord Stream 2 is in place and fully operational --and provided gas transits via the Belarus/Poland route resume -- Gazprom would no longer need to use the route through Ukraine which would jeopardize supply security in Ukraine itself and in several eastern European countries.

Gazprom said is striving to complete construction of the Nord Stream 2 and TurkStream pipeline projects in 2020. Over the past few months, Gazprom has already substantially reduced the volumes of gas it transits across Ukraine, and seeks reduce the level further by ramping up export volumes through Nord Stream and Turkish Stream instead. The Ukrainian state is at risk of losing roughly $3 billion gas-transit fees — about 3 percent of national GDP.

Rumours of Russia-Belarus 'merger'

The Belarusian President Alexander Lukashenko has rebuked „peculiar hints“ from the Russian President Vladimir Putin that the two countries could merge into a new „Union State“ in return for cheaper oil and gas supplies.

For Putin, the creation of a new “Union State” would allow him to remain in power even after his presidential term comes to an end. Absorbing Belarus would extend Russia’s political reach towards the west, but Lukashenko stressed he is neither the Belarusian people nor the Russians “want to go this way.”

This futures price was the lowest February closing price for the near-month contract since at least 2001, in real terms, and the lowest near-month futures price in any month since March 8, 2016, according to Bloomberg and FRED data.

Gas production, once again, outpaced demand growth which reduced the need to withdraw additional gas from storage. Dry gas production in January 2020 averaged about 95.0 billion cubic feet per day (Bcf/d), the third-highest monthly U.S. natural gas production on record but down slightly from the previous two months.

Consumption of natural gas by residential, commercial, industrial, and electric power sectors averaged 96 Bcf/d for January, some 4.4 Bcf/d less than in January 2019, largely due to falling residential and commercial gas use amid warmer temperatures.

LNG feed gas doubles

Feed gas for LNG export facilities and exports by pipeline to Mexico averaged about 117.5 Bcf/d in January 2020, an increase of about 0.2 Bcf/d from last year. “This overall increase is largely a result of an almost doubling of LNG feed gas to about 8.5 Bcf/d,” according to IHS Markit estimates.

As supply growth outpaces demand, working gas inventories reached relatively high levels for mid-winter. The U.S. Energy Information Administration’s (EIA) data on natural gas inventories for the Lower 48 states as of February 7, 2020, reflect a 215 Bcf surplus to the five-year average. In EIA’s latest short-term forecast, more gas remains in storage than the previous five-year average through the remainder of the winter.

Temperatures are forecasts to stay mild, and according to the National Oceanic and Atmospheric Administration (NOAA), January 2020 was the fifth-warmest in its 126-year climate record. The warm winter reduces the number of heating degree days. Through February 8, residential natural gas customers in the United States have seen 11% fewer HDDs than the 30-year average.

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.

To win the Fujairah F3 IPP contract, Marubeni participated in a competitive tender and submitted the best bid for the development, financing, construction, operation, maintenance and ownership of a combined-cycle gas turbine (CCGT) power plant.

EWEC received 30 expressions of interest from potential bidders for the Fujairah F3 IPP project, of which 20 were qualified to bid after submitting statements of qualification. The project received final six bids out of which Marubeni was selected.

Boosting Fujairah complex output beyond 20 GW

The F3 unit will be built by Marubeni 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.

Asset transfer to TAQA on the cards

Through the lifetime of the project, the government of Abu Dhabi will indirectly own a 60 percent stake, while Marubeni will hold the remaining 40 percent. Government-owned ADPower, might ultimately transfer is power gen assets – including the Fujairah F3 IPP project – to the Abu Dhabi National Energy Company (TAQA).

If approved by UAE regulators, this asset transfer could create one of the largest utility companies in the Gulf Cooperation Council, and the third-largest company listed on the UAE stock exchange by market capitalization.

If enacted early, the complete coal-to-gas and a faster renewable energy build-out switch could curb CO2 emissions by some 1.8 billion tonnes and thus help Germany to meet its Paris climate targets.

"Raising the 2030 emission target by at least 10-15 percent, in line with the European Commission's plans, would be a first step in this direction," the DIW report reads. It recommends and tightening up the country's current target to lower emissions by 65 percent by the end of the next decade.

Critics dismiss late lignite shut-downs

The agreed coal exit schedule means the energy industry would use up Germany's emissions budget prematurely, the report’s co-author Claudia Kemfert warned. The draft law, in her view, translates into additional emissions of about 134 million tonnes in comparison with the recommendations of the country's coal commission.

“A quick shutdown of hard coal-fired power plants reduces emissions in the short term. However, due to the late shutdown of dirtier lignite-fired power plants, they are then significantly higher than targeted after 2030," she said. Moreover, commissioning of the controversial hard coal-fired power plant Datteln IV alone will cause an additional 40 million tonnes of carbon emissions.

The German cabinet adopted the coal exit law in January, more than one year after the multi-stakeholder coal exit commission recommended an end to coal-fired power generation in the country by 2038 at the very latest. The coal exit law – now to be debated in parliament – translates the coal exit commission’s energy policy recommendations into German law.

But some former commission members are discontent with the latest roadmap, claiming it “violates the original coal compromise.”

For Qatari spot supply it is more attractive to head rather to European gas markets than to Asia. For US cargoes, a JKM premium at 0.51 $/MMBtu would be still insufficient to offset the higher freight costs for US cargoes to go to Northeast Asia ahead of Europe.

The pace of recovery in Chinese LNG buying hinges on the ramp-up of economic activity in the coming weeks. Analysts anticipate a rather slow rebound which could leave gas demand subdued throughout most of the second quarter.

Though workers were to return to work on February 14, many factories appear to remain shuttered amid reports that many people are not returning until March 1. Travel restrictions between affected provinces and quarantine measures are also greatly reducing demand for petroleum and natural gas.

Q2-2020 may be worst hit

With China’s three main LNG importers all having declared ‘force majeure’ for Q1 delivery, between 35 and 50 February cargoes could be at risk. Suppliers are struggling to offload the contracted cargo elsewhere in an oversupplied market.

Total and Shell have rebuked the ‘force majeure’ measures, suggesting the Chinese state buyer might be trying to forego their contractual offtake commitments to be able to buy cheaper gas on the spot market.

Kpler date indicates some cargo diversions away from China as well as eight cargoes held as floating storage in the Pacific basin.

Demand destruction might continue if the spread of the virus is not contained in due course. Though China has been claiming a slowdown in the number of new cases in recent days, the World Health Organisation (WHO) warned the infection rate could again accelerate. In this event, the second quarter would see gas demand destruction on an even larger scale than at the start of this year.

"Soon you will hear about the ability of the kingdom to be a gas exporter and a petrochemical exporter," Prince Abdulaziz bin Salman said in a televised speech, without disclosing further details.

Red Sea gas discovery

Large gas reserves have been found the Red Sea last year, which could soon be developed by the state-run energy giant Saudi Aramco, the world largest oil producer.

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 (cf/d) of gas by 2030, up from around 14 billion cf/d currently, and the energy giant has undertaken key projects to boost output from conventional gas fields.

Ending 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.

New Fortress pointed out the project will be “funded with cash on hand and funds from operations.” Both the FSRU and the gas-fired power plant are slated to start commercial operations in the second half of 2021, subject to obtaining all necessary licenses and permits.

25-year PPA in place

All electricity produced at the 300 MW plant will be sold by NFE to Nicaragua’s electricity distribution company DisNorte under a 25-year Power Purchase Agreement (PPA). The gas-fired plant will assist Nicaragua’s transition to cleaner-burning fuels while supporting the country’s economic development.

To fuel the plant, New Fortress will deploy an offshore LNG receiving, storage and regasification terminal off the coast of Puerto Sandino. Under the terms of the PPA, New Fortress is expected to provide more than 21 trillion British termal units (TBtu) of natural gas per year over 25 years, the equivalent of approximately 700,000 gallons of LNG (60,000 MMBtu) per day.

New supply deals

In the Caribbean, New Fortress recently signed a long-term LNG supply agreement for eight cargoes a year for 10 years through January 2030. Most cargoes are understood to head to Puerto Rico, where NFEnergía supplies regasified natural gas to two converted units at the San Juan power plant.

From its 100,000 gallons per day liquefaction and export plant in Miami, NFE produces LNG for export in intermodal ISO containers to the Caribbean and to small-scale customers in southern Florida. It operates a floating LNG import terminal in Montego Bay, Jamaica, along with a fuel-handling facility and an associated import contract in Puerto Rico.

The six SGT-800 industrial gas turbines, like the five machines of the same type that Siemens is supplying for two peaking plants in the Vitebsk region, will help increase regional grid stability to guarantee stable power supply.

The peaking plant is designed for 700 operating hours and 350 cold starts per year, Siemens said. The manufacturer stressed the plant’s full capacity of 300 MW can be made available in as little as 15 minutes after a cold start.

“Once again, we chose to go with Siemens machines, since they offer excellent performance and can be brought to full load in a very short period of time,” said Minskenergo’s general director, Aleh Shchemel. “This makes these turbines an outstanding choice for increasing grid stability and supply security in Belarus.

For the Minsk power project, Siemens’ scope of supply includes the six SGT-800 gas turbines as well as associated generators and the control system PCS 7. It also includes the gas receiving station as well as high- medium-, and -low-voltage equipment.

With the new order, Siemens also strives to help Belarus decarbonise its power generation sector. “The intelligent combination of efficient and flexible gas turbines with wind and solar power plants makes it possible to cut significant quantities of greenhouse emissions,” said Olaf Kreyenberg, head of Power Generation Europe & CIS at Siemens Gas and Power.

High capital investment required for the deployment of energy storage systems, however, limits the number of projects that are actually carried out. The lack of project financing, in particular, is making it difficult for smaller players to gain access to debt funding to realize energy storage projects.

At grid level, batteries have three key functions notably peak shaving and load leveling, voltage and frequency regulation as well as emergency energy storage.

Trade-off between technologies

“Battery energy storage technologies with rapid response, low cost, long lifetime, high power, and energy efficiency can be distributed throughout the grid and therefore are desirable for utilization in grid-level electrical energy storage,” researchers at China’s Tianjin University noted. “However, some trade-offs often exist among different properties and no existing batteries can meet all the requirements.”

Researchers have analysed a wide range of battery technologies including lead-acid, nickel cadmium, nickel metal hydride, sodium-sulfur, lithium-ion and flow batteries of various chemistries. In conclusion, they recommend focusing R&D efforts on batteries based on cheap, abundant materials – such as sodium-ion in order to keep costs under control.

Key developers of battery energy storage systems are LG Chem., ABB, AES Energy Storage, BYD Company, Convergent Energy and Power, Greensmith Energy Management Systems, Eos Energy Storage, Seeo, S&C Electric Company, Schneider Electric and many more smaller players.

With cheap LNG available practically anywhere with access to the sea, and a receiving LNG terminal, electric utilities can switch to cost-effective gas power generation even in the absence of pipeline infrastructure.

Calculating a pilot LNG-to-Power project that could support decentralized areas of the Philippines grid, MAN assumes an indicative price for EPC (engineering, procurement and construction) of 750 Euros per kW plus maintenance cost of 4.5 Euros per MWh under natural gas operation. The power plant is scalable – from 20 MW to 220 MW – dependent on how many engines of the type 18V51/60DF are being used.

Finance linked to fuel supply

Project finance for small-scale LNG-to-Power projects is often linked to a fuel supply concept. Hereby, the LNG supplier steps in and supports with the LNG infrastructure, which is refinanced by higher supply costs.

“It’s a bit like the Nespresso principle,” MAN Energy Solution’s business development manager Carsten Dommermuth told Gas to Power Journal.

“For the reference scenarios we expect the small-scale LNG-to Power project to be situated in a remote location, reachable with an LNG carrier with a transport capacity of about 30,000 cubic meters (cbm). Best case would be to use existing power plant sites with related infrastructure and already available site with access to the high voltage grid,” he explained.

The LNG is assumed to arrive at a central terminal on the island, situated not more than 25 km from the power plant site. From the import terminal, the LNG can either be transported by truck to the power station or be regasified at the terminal and supplied via a natural gas feeder pipeline.

The actual power plant is assumed to be operated in baseload mode with 8,000 hours per year. Scalable between 20 MW and 220 MW, the power plant will be driven by dual fuel engines type 51/60 DF in single-cycle installation.

Modeling future plant economics

For prospective customers, MAN can deliver an LNG logistics and power plant concept; a technical proposal for the LNG infrastructure [which would be realized with a subcontractor]. Non-binding calculations are also being made for CAPEX and OPEX for the small-scale LNG-to-power solution, and based on modeling of future electricity tariffs these calculations give a first indication of the project’s financial profitability.

Asked about the customer types, he specified that on IPP markets there is quite some private equity involvement, with players looking for an attractive PPA which has to cover the investment and debt re-payment. On the other side of the spectrum, there are state-owned utilities on non-liberalized markets which cater for the nation’s fuel supply for power generating.

In principle, MAN Energy Solutions can deliver all necessary parts to set up the project. “The LNG import terminal with Jetty´s can be provided by MAN together with an EPC partner. Regasification solution, storage solution and a power plant can be provided by us,” Mr. Dommermuth said.

“The LNG obviously is to be provided by a global gas supplier, e.g. Shell, Gazprom or BP,” he added, concluding: “Accordingly we can cater the full value chain, and only may need third party support to set up a jetty dependent on specifications of the coastal strip.”