Synchronous condensers are special electric generator applications that, when grid-connected, exchange reactive energy with the grid and increase the short-circuit power. They also contribute inertia to the power grid, increasing stability in order to accommodate a rising number of renewables energy sources. Wind and solar power units are intrinsically discontinuous sources of electricity supply and characterised by low or no inertia.

Flywheel system

The latest order-wins are for synchronous condensers with a so-called flywheel system, designed and developed by Ansaldo Energia. The system boosts the overall inertia of the rotating system while minimising mechanical losses because it is contained inside a vacuum chamber.

For this tender, Ansaldo Energia chose to partner with ABB due to the latter’s expertise in implementing intelligent, robust and sustainable power grids.

ABB will supply, install and commission the system that connects the synchronous compensators to Terna’s power transmission grid, including control systems as well as monitoring and diagnostic solutions. The contract also entails 20-year maintenance services.

Stabilising supply chains as well as mature and experienced players will benefit the market in the long run and facilitate further cost reductions. As they do, continued policy and regulatory efforts will be key to driving upside in the market.

“The energy storage industry is in the enviable position of juggling growth game-changers from multiple directions. Plunging costs drove speculation in the first scaled markets but as price declines enter a steadier rate, further recognition of storage’s value - rather than cost - will be the key factor in determining growth,” said Daniel Finn-Foley, Wood Mackenzie Head of Energy Storage.

Industry embraces energy storage

Oil majors, utilities and manufacturers alike, all embrace energy storage as part of their onsite power generation units.

“When Google announced a partnership with NV Energy for significant solar-plus-storage investment to power data centres, they were pioneering a new way corporations value renewable energy,” Finn-Foley commented. “Rather than simply offset consumed electricity, Google seeks to time-match consumption with availability and that requires storage. If this catches on among other climate-forward corporations, the upside could be huge.”

“Daimler’s commitment to procure renewables in real-time shows that this trend may become global,” he added. The carmaker Opel, meanwhile, is partnering with the French oil major total on electric vehicle (EV) cell manufacturing. Total already invests in stationary energy storage applications.

Finance refocuses on clean tech sector

Apart from private financing, research in novel energy storage technologies also benefits from a €10 billion innovation fund launched by the European Commission. On the other side of the Atlantic, the US Department of Energy’s Energy Storage Grand Challenge represents the US federal government’s largest-scale action to date.

Massive investment from international development entities, notably the World Bank and the Asian Development Fund, is reshaping relations between finance and cleantech. This trend is quickly moving into the private sector. Blackrock, for starters, decided to end investment in thermal coal and now put sustainability front and centre.

“Storage has emerged as a potential focal point for sustainability, with significant investment from a new multi-billion renewable energy fund set to flow into the storage space,” Finn-Foley forecast. He cautioned, however, that constraints in key commodity availability, delays in manufacturing scale-ups and the gradually diverging priorities of the EV and stationary energy storage space “could throw sand in the gears,” though that could be alleviated through second-life and battery recycling program.

At certain times, gas-fired power plants with as little as 35 percent efficiency will be in the merit order and will be dispatched at a profit, largely thanks to record low fuel prices.

Germany’s most modern combined-cycle power plants can reach nearly 63 percent efficiency, but older units lower the fleet’s average efficiency to around 50 percent, according to findings by the German Environment Agency (UBA). Now, the race for operational efficiency is no longer all that relevant as low-cost gas outcompetes thermal coal in large parts of Europe.

Analysts see ample room for coal-to-gas switching in European power markets this year – especially in Germany and Italy – but energy Consultancy ICIS cautioned this trend will mostly be unlocked at carbon prices above €30/t.

More US LNG cargoes head to Europe

Demand destruction in China due to the coronavirus outbreak is effectively making more and more LNG shipments head to European markets.

Cheniere Energy’s chief commercial officer (COO) Anatol Feygin that European LNG import levels continued to increase in the fourth quarter despite record seasonal amounts of volume in underground storage. Imports reached a record 9.5 million tonnes or more than 145 cargoes of LNG in December. “The incremental LNG flows into Europe were enabled by a combination of additional gas being placed into underground storage, coal-to-gas switching and a reduction in other gas supply sources,” he said.

Feygin believes that a production decline in the Netherlands of about 6 billion cubic metres and a drop in piped gas supplies of a combined 19 Bcm helped accommodate approximately 50 percent of the increased LNG receipts.

“The push of LNG into the European market and resulting drop in spot gas prices and tight gas burn in power generation, were important factors that helped balance the market and that we believe will continue to be important over the medium term,” he said. “Gas-fired power generation in the EU increased by 12 percent in 2019, while coal-fired power generation decreased by 24 percent.”

The Cheniere COO holds the view that Europe’s declining gas production and union’s environmental targets will provide substantial upside to European gas demand, making it a home for rampant US LNG supply.

Prior to being fed into the ‘Power of Siberia’ gas interconnector to China, the Russian gas undergoes treatment at Amur, producing valuable petrochemicals and gases.

The Amur Gas Processing Plant (GPP), situated in the Russian Far East, has a design capacity of 42 billion cubic metres of gas per year and when fully completed will include the world's largest helium production facilities. The first two of the plant’s six production lines are slated for commissioning in 2021. The remaining Amur GPP lines will be consecutively put into operation before the end of 2024. The Amur plant is expected to reach its design capacity by 2025.

Monetizing Amur GPP by-products

Keen to monetize the by-product of Amur GPP, Gazprom Gazenergoset Geliy plans to purchase gas-powered vehicles to transport liquid helium.

To that end, freight trucks powered by LNG will be used. Batch production of these trucks will be carried out at the facilities of KAMAZ, part of Rostec. The infrastructure for producing LNG and refueling these trucks will be set up by Gazprom Gazomotornoye Toplivo, a special-purpose company set up aspart of the Russian gas giant’s systematic efforts to develop the natural gas vehicle (NGV) market

The first 18 trucks are meant to be in service by 2021. These LNG-powered trucks will transport helium in special thermally-insulated containers.

Siemens had been initially awarded a contract to supply the first 10 compressor trains for the Magnolia LNG project at the Port of Lake Charles, Louisiana. The mid-scale project, with a capacity of 8 million tons per annum (mtpa), is developed by Australia-listed LNG Ltd.

Siemens' initial scope of supply comprised a total of eight refrigeration compressors and two feed gas booster compressors for the initial two liquefaction trains. Four mixed refrigerant (MR) Siemens STC-SV compressors will each be driven by a Siemens SGT-750 gas turbine, while four ammonia refrigerant (AR) STC-SV compressors will each be driven by a Siemens SST-600 steam turbine. Additionally, two motor driven feed gas booster compressors will be delivered.

The subsequent two LNG trains necessary to achieve the full 8 mtpa capacity for Magnolia will bring the total number of compressor trains to 20 at this site.

Eager to venture into the LNG market, Siemens has set up a supplier alliance agreement for process compression equipment and drivers. The company’s strategy is to standardize the implementation of the optimized single mixed refrigerant (OSMR) liquefaction technology worldwide.

Record low prices for natural gas, combined with rising UK carbon price support levy, left thermal coal as being uncompetitive. Less emission-intensive gas power units are also burdened by the carbon price, although to a much lesser degree.

With an installed capacity of 3.9 GW, the giant Drax Power Station can provide electricity for around 13 million homes. The operator has already converted four of six former coal-fired power units to run on biomass wood pellets. A new combined-cycle gas power plant will be built to replace Drax’s two remaining coal units. Approval for this CCGT is still subject to a judicial review.

Coal exit curbs OPEX

Ending coal generation at Drax will reduce operating costs at the plant by between 25 million and 35 million Pounds per year, once the phase-out it complete. It will also lead to layoffs of up to 230 employees at the plant from April 2021.

Posting full-year results on Thursday, Drax said earnings before interest, tax, depreciation and amortisation (EBITDA) increased by 64% to £410 million for the year ended December 31, up from £250 million a year earlier. The rise in profits was attributed to the integration gas-fired and hydro power assets, acquired from Scottish Power.

At the UK government’s latest T3 auction, Drax has secured capacity contracts for 2,562 MW, mainly for gas-fired and hydro power units. These contracts, running from October 2022 to September 2023, are priced at £6.44 per kilowatt and worth some £15 million.

“Ending the use of coal at Drax is a landmark in our continued efforts to transform the business and become a world-leading carbon negative company by 2030,” said Drax CEO Will Gardiner. “Our journey away from coal began some years ago and I’m proud to say we’re going to finish the job well ahead of the government ... deadline.”

Bowing to growing regulatory pressure, several other UK utilities have announced the closure of some of their left-over coal power assets, including SSE’s Fiddlers Ferry unit in Cheshire which is meant to close by March 31.

Delta Offshore Energy, the lead-developer for Bac Lieu CCGT, had been waiting for the permit before commencing with the full development phase.

“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.

Start-up scheduled for 2023

Delta is the lead-developer for the 3.2 GW power station at Bac Lieu, designed to consist of four 750 MW gas turbine units and a fifth unit with 200 MW. The integrated LNG import and power gen project is scheduled to start operations in 2023.

Detailed engineering work and a full feasibility study have been completed, with the LNG import solution being developed in cooperation with Norway’s 7 Seas.

“The Bac Lieu project addresses Vietnam’s need for an LNG import terminal to provide access to growing the LNG industry as a feedstock for electricity generation,“ said Bobby Quintos, engineering managing director for Delta Offshore Energy.

“Our alliance with LNG Limited will allow the Government of Vietnam to have a stronger relationship with the U.S. market and the long-term stability of the Henry Hub Index, which fits perfectly with the Vietnamese National Power Development Plan.”

Plans for 2^nd LNG import terminal

Vietnam seeks to shifts its power sector towards gas generation and has made plans to import 5 mtpa of LNG by 2020, which will be gradually increased to 10 mtpa by 2030 and 15 mpta by 2035.

To accommodate these LNG import volumes, the Vietnamese government is supporting plans to develop a second LNG import terminal near a projected power plant in Ninh Thuan province. That project is backed by Novatek which will seek to supply it with fuel from its Yamal LNG export plant in northern Siberia, or the Arctic LNG II project in the long run.

Entergy Louisiana CEO Phillip May pointed out that “battery technology provides another tool to buttress the overall reliability and resiliency of our system.” Hence, the Perryville Power Station is supported by GE’s 7.4 MW battery-based energy storage system paired with the plant’s OCGT gas turbine.

To provide a black start, traditionally power stations have small diesel generators. Such a black start diesel generator (BSDG) can be used to start larger generators of several megawatts capacity, which in turn can be used to start the main power station generators.

Black start technology proves that flexible open-cycle gas plants, integrated with battery energy storage, are a “good method to effectively support the grid,” said Prakash Chandra, Renewable Hybrids CEO, GE Renewable Energy. “We are proud to have successfully completed the first ever black start of a GE heavy-duty turbine.”

According to GE, this project demonstrates the complementary nature of gas-powered energy and battery storage. “With the battery energy storage system integrated to our heavy-duty gas turbines, we have created a first-of-its-kind backup support system,” explained said Amit Kulkarni, General Manager for Large Blocks product segment, GE Gas Power.

Going forward, GE strives to develop similar projects with customers globally. The black-start at Perryville Power Station serves as a model for future projects in GE’s F-class gas turbine fleet of approximately 900 units in service, with a combined capacity of around 150 GW.

Though a U.S.-China trade deal includes a promise for $52.4 billion in further purchases of American energy such as LNG, crude oil and coal in 2020 and 2021, Beijing has left import tariffs in place. This could allow Russian gas to gain the upper hand over US LNG imports in the short run.

Beijing strives to diversify China’s gas sources, but the cost of any new supply option matters. Considering the huge expenses of transporting Russian pipeline gas over thousands of miles towards Beijing and Shanghai, analyst deem it “unlikely” that CNPC will want to quickly ramp up gas supply from Siberia at the expense of imported LNG.

Eventually some 8 Bcm/y of Russian gas will be exported to China’s CNPC through the new interconnector, but the competitiveness of PoS gas imports in China is entirely dependent on where it is sold.

Costs hinge on point of sale

Considering the cost of PoS gas into the Yangtze River Delta versus recent LNG contracts, Wood Mackenzie says this is “not a major competitive threat.” Particularly because the Yangtze River Delta is a region that already has six regas terminals, with a further three greenfield projects under construction and two more proposed.

Things look different further north. “In the Northeast, tariffs from the Russian border will only be around $1/MMBtu to reach a city such as Shenyang, making ‘Power of Siberia’ gas attractive against LNG,” Mr. Thompson said. “But to take gas further south to Shanghai will increase tariffs to around $3/MMBtu.”

“LNG doesn’t have this problem. And the world is awash with dirt cheap LNG right now,” he added, suggesting “this will continue over the next couple of years as more projects come onstream.” Moreover, China is rapidly expanding regas capacity and pushing third-party access policies to encourage more participants.

While legacy LNG contracts are the marginal source of supply into China, recent LNG contracting trends are seeing term deals signed around 11% of oil, Wood Mackenzie understands. At this level of oil indexation, new LNG projects would not really have fear Russian pipeline gas into China.

Uncertainty on PoS gas price, future tariffs

Wood Mackenzie’s team of China gas analysts hence argue that the ‘Power of Siberia’ pipeline will take 7 to 9 years to reach full capacity. Analysts in the West, however, have only limited understanding of exactly how the Power of Siberia gas contract is priced and what future pipeline tariffs will be following the establishment of China’s new national pipeline company in early December.

“China’s recent proposals to exclude city-gate prices from national regulations, mean Russian gas prices will be deregulated, potentially encouraging PetroChina to raise wholesale prices (which would also benefit LNG),” Mr. Thompson said. “But what we do know for sure is that even with Russian pipeline gas now in China, LNG is increasingly competitive into China and should continue to play a key role in supplying cleaner energy into this most critical of markets.”

Capacity factors are calculated by dividing the actual electricity produced by a generating unit by the maximum possible electricity that could have been produced if the generator operated at continuous full power. A capacity factor of 100 percent, for example, means the unit is operating all of the time and produces baseload power.

The new EIA’ Electric Power Monthly contains capacity factor data for 16 power plant technology types. In focus are time-adjusted total capacity values by technology type considering fuel costs and plant retirements.

Usage factors of energy storage

Gross generation data for battery and pumped storage applications are also included in the EIA’s detailed electric power survey. This includes capacity factor data based on gross generation for pumped storage and batteries.

Usage factors for storage generators differ from capacity factors because usage factors are based on gross generation rather than net generation, analyst pointed out. Energy storage technologies tend to consume more energy than they store and, therefore, always have negative net generation.

Storing excess electricity at times of low demand and often relatively inexpensive prices, can create value when that stored electricity is resold in high-demand periods at high, peak-load power prices.

Pumped storage, based on pumping water in storage reservoirs for hydro-electric generation, is still the largest source of electricity storage in the United States. Usage factors for pumped storage tends to have a large peak in summer, a smaller peak in winter, and the lowest use in spring and fall. By comparison, the usage factors for batteries are relatively low and less seasonal.

The Tesla/PG&E energy storage will be used to store wind and solar power during offpeak hours, similar to Vistra’s 300 MW/1,200 MWh, battery energy storage at the same site. Nearby, Dynegy is also going to deploy a 300MW / 1,200MWh energy storage unit on PG&E’s power transmission grid.

“Combined, this is going to be the largest battery facility in the world, so it's a big boost to our community and our country," said Monterey County Supervisor John Phillips. The Monterey County Planning Commission last week gave the greenlightfor the PG&E/Tesla energy storage project.

Some 268 Tesla Megapack lithium-ion batteries will be interlinked to form the 730 MW energy storage facility and then grid-connected at a PG&E substation. Each Megapack comes from the factory fully-assembled with up to 3 MWhs of storage and 1.5 MW of inverter capacity, building on Powerpack's engineering with an AC interface and 60% increase in energy density to safe cost.

To reach over 1.1 GWh capacity, Tesla will eventually deploy 449 Megapacks at the Moss Landing site.

Megapacks replace peaking plants

PG&E pointed out that Megapack can help reduce the need for fossil-fuelled peaking power plants. Placed at the end of the so-called merit order, these power units are only fired up at times of peak power demand when the local grid operator cannot meet demand.

"They cost millions of dollars per day to operate and are some of the least efficient and dirtiest plants on the grid," Tesla stated. By using Megapacks, instead Tesla said it can deploy an emissions-free 250 MW, 1 GWh power plant in less than three months on a three-acre footprint – four times faster than a traditional fossil fuel power plant of that size. The units can also be DC-connected directly to solar, creating seamless renewable energy plants.

Together – the PG&E energy storage, the Dynergy unit and Vistra’s energy storage and a 75 MW unit by Hummingbird Energy Storage – will have enough installed capacity to replace three gas-fired peakload power plants, the California Public Utilities Commission confirmed.

Linked directly to the UK’s high-voltage power grid, the battery storages will provide flexible capacity to support intermittent renewable energy supply and EV charging infrastructure. The British market for expected to expand significantly in 2020 in what has been described as “the year of the electric car” by industry analysts.

This is the largest energy storage deal in Europe for Wärtsilä, which set its sights on the UK as a key new market.

The two lithium-ion batteries systems, to be installed at Cowley in Oxford and Kemsley in Kent, are based on GEMS software which leverages artificial intelligence and machine learning, as well as on GridSolv. This modular solution links stand-alone energy storage and hybrids with thermal or renewable power units.

“We believe that a clean energy future for the UK is not just possible, it is deliverable. These projects will support a cost-effective, reliable and low-carbon energy system and promote the rapid adoption of clean transport in the UK,” said Andrew Tang, Wärtsilä’s Vice President, Energy Storage and Optimisation.

Pivot Power strives to accelerate the expansion of electric vehicles across the UK, whereby energy storage systems are meant to ensure stable supply of electricity to EV charging stations. The contracted 100 MW energy storage in the UK support EDF Group’s Electricity Storage Plan under which it aims to be the leader in Europe with 10GW of additional storage by 2035.

The French utility strives to become a leading electric mobility company by 2022 in the UK, France, Italy and Belgium. Beyond 2022, the Group’s goal is to provide power for 600,000 electric vehicles and 75,000 charging points.

The Just Transition Fund has been set up to support new companies and business incubators, as well as investments in research and innovation. Before any proposed payments can be made, however, EU member states need to first agree on a long-term budget for 2021-2027.

To alleviate structural effects of the German coal exit, the Commission has identified the 18 most-affected regions. Seven of the areas are in the eastern German region of Lusatia where 8,300 people are directly employed in lignite mining and nearly 5,000 people could be indirectly affected.

With 8,960 people employed in lignite mining, the Rhenish mining district is expected to experience “upheaval” but is deemed to be “more able to adapt,” the Commission stated. Meanwhile, the central German mining district will "face challenges," although fewer people are employed in the lignite sector there, because of "very low innovation and research potential and a rapidly ageing population."

German gov’ to pay €40 billion in structural aid

Proceeds from the European Commission may seem little in comparison with massive 40 billion Euro support that the German government has pledged to pay under a scheme to compensate electric utilities, workers and coal-mining regions.

The coal exit comes in addition to Germany’s earlier agreed nuclear phase out and its meant to ensure that Europe’s largest economy will meet its 2030 emission reduction targets. Investment in offshore wind, solar power and new long-distance power transmission lines are also in the making.

The agreed phase-out roadmap entails a boost for renewable energy sources (RES) to reach a 65 percent share in power consumption by 2030 in order to compensate for the closure of coal power plants. It will also seek to expand combined heat and power (CHP) systems and install "two gas plant capacities" to cushion "the vanishing of large quantities of controllable energy."

Timeframe of coal exit – two options

In a first step, Germany's total installed lignite-fired power generation capacity will be reduced to 15 gigawatts (GW) by the end of 2022, with eight plants operated by RWE in western Germany going offline by that year. The total installed lignite generation capacity stood at about 21 GW in 2019.

In a second phase, starting after a two-year hiatus following the nuclear exit, capacity will be cut to 8.8 GW between 2025 and 2029. A total of eleven units are to be taken offline, three of which are transferred into security standby. Five of these eleven units are operated by RWE in the west and six by LEAG, a subsidiary of Czech investor EPH, in eastern Germany. 

During the final phase starting in the 2030s, the remaining eleven lignite units in the country are scheduled for decommissioning between 2034 and 2038, the year agreed by the coal exit commission as the very last for the fossil fuel in the country. But the agreement also says there will be an assessment in 2026 and 2029 to see whether the last phase of decommissioning in the 2030s can be brought forward by three years. In this case, the coal exit would be completed in 2035 instead of 2038.

Worldwide, primary energy consumption is seen surge from 14,300 million tonnes of oil equivalent (Mtoe) per year to 21,500 Mtoe per year in 2040. This bullish scenario of the energy consultancy Xodus is based on UN projection of non-OECD population growing from 6.3 billion in 2018 to 7.8 billion in 2040.

“Recent forecasts take a developed world view showing either a plateauing or fall in energy consumption, but growing populations in developing countries mixed with increasing wealth are much more likely to result in a surge of overall primary energy consumption,” said Andrew Sewell, director of subsurface at Xodus Group.

The ‘Rapid Pivot to Gas’ scenario includes the phasing out of coal and oil in response to vehicle electrification and environmental pressures and a rapid and robust increase in renewable energy production. Aggressive growth rates have been assumed for wind and solar energy at over 1,000 percent each by 2040. In addition to sustained installation capacity, the uptime and efficiency of new capacity is projected to keep improving for the next 20 years.

Crude oil and coal, in contrast, is forecast to fall to 1,500 million tons of oil equivalent (mtoe) per year and 1,200 mtoe per year respectively by 2040. Unconventional oil and other liquids are seen rise over the entire period as is nuclear energy, assuming no major changes in policies.

“Assuming that natural gas supplies the difference in total demand, we estimate that consumption could grow up to 200% by 2040 accounting for half of all primary energy consumption and 73% of the fossil fuel component,” said Andrew Sewell, Director of Subsurface at Xodus Group.

Energy industries, in his view, need to consider this potential spike in gas demand and the huge exploration and production expenditure it would require. To secure that additional gas supply sustainably, he calls on the E&P industry to “quickly enable CCS and other decarbonisation technologies.”

These two conventional energy projects are part of a wider Memorandum that Ansaldo signed at the sidelines of a bilateral Italy - Azerbaijan that was recently held in Rome. Ansaldo and Azerenergji set up a “close collaboration framework" that will allow the Italian equipment manufacturer to submit an economic proposals for both the CCGT servicing agreements and the Yashma EPC venture.

A preparatory survey on the Yashma CCGT project can be found here.

A second Memorandum, signed with the energy ministry, will see Ansaldo analyse the economic and technical feasibility for substantial investment in renewable energy sources in Azerbaijan.

“Energy transition is a strategic goal for the Republic of Azerbaijan, which is encouraging investments in the renewable energy sector,” commented Giuseppe Marino, CEO of Ansaldo Energia. “With the signing of these agreements, we propose our help as a system integrator to allow a proper management of renewable energy sources within the energy mix”.

Headquartered in Genoa, Ansaldo Energia is 59.9 percent owned by CDP Equity (part of Cassa Depositi e Prestiti Group) and 40 percent by Shanghai Electric.

Previously, Gazprom had controlled their financial and economic performance through a KPI system while budgeting of the three sub-holdings used to be part of the parent company. By separating the budgets, Gazprom Group expects to easier identify the growth and development capacities of each for the three units.

Streamlining projects

In December, the Gazprom board had approved a 16.5 percent reduction in investment in 2020, marking the second cut in a row. In the previous year, Gazprom already revised downward its investment program and budget by optimizing capital-intensive projects in the Yamal Peninsula and eastern Russia. The monies unspent were used to improve Gazprom’s equity capitalization to give leeway for strategic acquisition in the future.

Gazprom’s 2020 capital expenditure plan has been set at 1.1 trillion rubles ($18 billion) by the management committee, down from projected spend of 1.3 trillion rubles ($21 billion) for this year. Capital investment make up 933 billion rubles ($15 billion) of the company’s 2020 budget, followed by 90 billion rubles ($1.4 billion) in acquisition spending and 81 billion rubles ($1.3 billion) on long-term projects. The Russian gas major said it would borrow 558 billion rubles ($8.9 billion) over the course of this year.

Announcing a greater focus on capital discipline, Gazprom’s management earlier this year pledged to increase dividends to 50 percent of net profits by 2021. Shareholders are still vary that their returns may shrink, given that Gazprom struggles to maintain its market share in Europe amid rising import of cheap LNG.

The new combined cycle unit, with a 57 percent yield, will achieve “the first parallel” by the end of March 2022, Ansaldo said, whereas the test exercises and inspection is due to be completed by the end of June 2022.

Based on an EPC contract, Ansaldo Energia will manage the executive design phase, the supply of the gas turbine, generators and set-up transformers, heat recovery vapour generator, the implementation of the civil works, the assembly and supply of ancillary electrical and mechanical installations.

Capacity payments

Financing of the new CCGT unit is underpinned by a capacity contract which gives Iren Energia an additional revenue stream for dispatching the plant at short notice, if required by the grid operator. The remuneration through the capacity market adds to the plant operator’s profits from electricity sales and the provision of ancillary services.

All of Turbigo’s gas-fired power units have 850 MW installed capacity, and Iren indicated the additional 430 MW unit will give much-needed flexibility to balance intermittent electricity supply from renewable energy sources.

“The repowering of the Turbigo station represents a significant upside in relation to the assumptions in the most recent business plan, which we decided to implement after the pricing signals from the first Capacity Market auctions,” said Iren CEO Massimiliano Bianco.

“Prices were positioned at highs both in terms of existing capacity and the new capacity,” he added, indicating this highlights the vital role of flexible gas power stations to supplement renewables in order to supporting system adequacy of the power grid.

Ansaldo Energia CEO Giuseppe Marino noted the latest order win “further consolidates its leading role in Italy’s energy transition.” Since November last year, the order backlog of the Italian manufacturer has increased by over 600 million Euros.

On that date, the current Iranian calendar year will come to an end and the government had initially been aiming to inaugurate 22 new power plant units with a total capacity of 3,933 MW in the current Iranian year. In addition, it wanted to upgrade several existing plants and increase their power generation efficiently.

The aim was to reach a total installed capacity of 85,695 MW by the end of the current Iranian calendar year, up from currently 80,311 MW. The most recent capacity additions were small-scale distributed power plants combined-cycle power plants, as well as renewables.

NIGC boost pressure on gas grid

Striving to increase gas supply to Iranian power plants, National Iranian Gas Company (NIGC) has said it increase the pressure on the grid to an all-time high. In consequence, gas supply to power plants now has reached 120 million cubic meters (mcm) per day.

Elaborating on the winter squeeze, NIGC said gas consumption by the households reached 600 mcm due to the extreme cold weather; hence gas supply to the power plants was reduced to 40 million cubic meters “just for two days.” Natural gas accounts for the largest share of the Iranian power mix, with 31.2 percent of total supply being produced by combined-cycle gas power plants, 29.9 percent from open-cycle gas units, followed by nearly 15 percent hydropower.

Iran currently produces some 810 mcm of natural gas per day, according to NIGC figure, mostly for the Iranian industry and domestic use as well as for power generation. As small portion of Iran’s gas production is exported to Armenia and Iraq.

Eager to avert energy shortages the government is implementing demand-side response mechanisms that helped reduce peakload power requirements by some 4,000 MW over the past summer. Some eight million household consumed less electricity than anticipated by Iran’s central planning body. The ministry said it hope this trend will continue for summer 2020.

DIP financing over $2.81 billion had been provided for McDermott during its restructuring under Chapter 11 bankruptcy. The equity-for-debt plan agreed with the court for the Lummus sale would eliminate more than $4.6 billion of McDermott’s debt.

DIP In January, subsidiaries of McDermott agreed to sell Lummus to The Chatterjee Group and Rhône Capital for a base purchase price of $2.725 billion, subject to higher or otherwise better bids received through a court-supervised auction process.

Most of McDermott’s debt was incurred by its $6 million purchase of rival Chicago Bridge & Iron (CB&I) in 2018. Eager to revive its financial structure, McDermott had been seeking for a higher bid during the solicitation period but did not get a better offer. It consequently cancelled another bidding auction previously scheduled for Monday, March 9.

McDermott said the sale hearing to confirm the sale of Lummus Technology to the joint partnership will take place on Thursday, March 12, 2020, at 9:00 am.

Under the terms of the Agreement, McDermott will have the option to retain or purchase, as applicable, a 10 percent common equity ownership interest in the entity purchasing Lummus Technology.

Vingeanne, a region of high wind energy production, was chosen as the location for a battery with 12 MW/24MWh a storage capacity, equal to the output of five wind turbines. Installation began in January this year, with commissioning and testing due by March 2021.

Designed as a ‘virtual power line’, Ringo will ultimately operate at three different locations within the RTE network. The battery capacity at each site will be of 12 MW / 24 MWh. The overall power storage experiment has been approved by the French regulator CRE for a total investment of € 80 million.

Storing excess wind power

At times of strong winds or plain sunshine, renewable energy supply tends to peak and often exceeds the transport capacity of the French national power grid. By storing the excess, the Ringo battery prevents the loss of green electricity. The system also allows RTE to better manage the electricity grid, avoiding congestion at times of peak demand.

The batteries used are of the NMC (Nickel, Manganese, Cobalt) high energy density lithium-ion type. Nidec will also supply some power electronics converters and its specific control system. Similar NMC batteries will be used that two other sites.

Nidec, for its part, underlined its customized offer was instrumental for having secured this order. Other companies in charge for the lots are Bolloré for lithium-metal-polymer batteries and SCLE-SFE, part of Engie Ineo, for the power electronics.

Going forward, RTE and its partners are seeking to develop large-scale electricity storage as an integral part of modern electricity grids.