Both parties will own 50 percent of the new joint venture, whose formation is expected to close by the end of the first quarter of 2021. The unconsolidated joint venture results will be included as part of Cummins’ New Power business segment.

Rainer vor dem Esche, managing director, NPROXX said his team “was eager to work with Cummins” to deliver industry-leading storage options that allow customers to “unlock the potential for hydrogen.” NPROXX’s containerised 10-foot solution providing a usable H2 storage capacity of 225 kg was approved by the German certification authority TÜV on June 4.

Venturing into hydrogen and fuel cells

“To move toward a decarbonised future, the world will require multiple power solutions including advanced diesel, natural gas, electrified power, fuel cells, hybrids and other solutions,” said Tom Linebarger, Chairman and CEO, Cummins. “The addition of hydrogen storage to our existing capabilities in hydrogen production and fuel cells enables us to accelerate the viability and adoption of these technologies in commercial markets.”

The acquisition of Hydrogenics Corp in September 2019, provided Cummins with both proton exchange membrane (PEM), and alkaline fuel cells electrolysers to generate hydrogen. The UK-based company also invested in LOOP Energy, signed a memo of understanding with Hyundai Motor Company and invested in the development of solid oxide fuel cells.

Today, Cummins has more than 2,000 fuel cell installations across a variety of on and off highway applications as well as more than 500 electrolyser installations.

The easing of lockdown measures has increased energy demand but daily transmission volumes in the UK power grid was still around 10% below the 2019-average in the first 22 days of June.

“Ever since the record-breaking spring Bank Holiday, when transmission system power demand troughed at a 15-year low of 14.5 GW in a single settlement period, demand has slowly resurged. But it has yet to come close to reaching the 0.7 TWh daily demand seen at the end of March 2020,” said Cornwall Insight analyst, Sam Nicholls.  

Poor economic forecasts keep a lid on energy demand

The uptick in demand can, at least in part, be attributed to the easing of lockdown restrictions. Since the UK Prime Minister Boris Johnson on May 10 encouraged employees to go back to work, the gap between 2020 daily Transmission System demand and the five-year average has narrowed from 0.14 TWh before, to 0.11 TWh after the announcement.

The opening of non-essential retail stores from 15 June led to a further boost in UK energy demand. “However, power demand is unlikely to reach the same levels as last year as a result of poor economic forecasts for the coming months, with many lockdown restrictions remaining,” Nicholls commented.

Biomass is one of the fuel source at the Drax Power Station which has partly been converted from thermal coal to cleaner-burning bioenergy. The pilot will test MHI’s CCS technology while helping realize Drax’s ambition to be a carbon negative company by 2030.

The Kansai Mitsubishi Carbon Dioxide Recovery (KM CDR) Process is installed in 13 commercial plants around the world.

Testing MHI’s proprietary solvents

During the pilot project at Drax, two of MHI's proprietary solvents will be tested, one of which – KS-1 Solvent – is already being used at 13 commercial plants delivered by MHI, including Petra Nova in Texas, U.S., the world's largest post combustion carbon capture facility, capturing 1.4 million tonnes of CO₂ a year.

The other is the newly developed KS-21 Solvent, designed to achieve significant performance improvements and cost savings. “KS-21 has many promising characteristics including lower volatility and more stability against degradation,” MHI specified, forecasting this “will result in operational cost savings making the Advanced KM CDR Process even more economic for future deployment.”

Aiming for zero-carbon cluster in Yorkshire

Drax Group CEO, Will Gardiner, said the company’s plans to develop ground-breaking BECCS at the power station in North Yorkshire would support the development of a zero carbon industrial cluster in the Humber region.

Implementing BECCS at Drax could deliver 16 million tonnes of negative emissions a year - a third of the negative emissions the UK needs from BECCS to reach its zero carbon targets by 2050 and anchor a zero carbon industrial cluster in the Humber region, delivering clean growth whilst protecting 55,000 jobs.

Kenji Terasawa, President & CEO, Mitsubishi Heavy Industries Engineering, said: "We are very proud to be a part of the BECCS pilot project with Drax. We firmly believe that our carbon capture technology would be able to contribute to the UK's zero carbon targets in a material way."

The Japanese manufacturer aims to provide providing reliable and economically feasible carbon capture technology to utilities around the world, supported by 30 years of research and development activity.

GE was awarded the turnkey contract to build the Waad Al Shamal plant in 2015 and construction works commenced in 2016. Currently, the four GE 7F gas turbines operate in open-cycle configuration.

Combined cycle commissioning works are ongoing and once complete, the facility will be able to generate up to 1,390 MW of electricity - enough for over 500,000 Saudi homes. GE’s scope of supply for the Waad Al Shamal ISCC also included one steam turbine and four heat recovery steam generators (HRSGs), as well as related equipment.

Rigorous EHS protocols

SEC has set rigorous Environment, Health and Safety (EHS) standards for project sites around workplace hygiene and housekeeping, lifting heavy loads, lighting and ventilation, waste management and other areas, with regular audits conducted by Saudi Arabia’s Industrial Security Department.

To be granted a 5-star rating, organizations not only have to meet the defined criteria but continuously adhere to them. At the Waad Al Shamal project, GE has dedicated site leaders, staff training programs and its own internal audits to implement and monitor EHS standards.

To enable project staff to work safely following the COVID-19 outbreak, there are processes of thermal screening of everyone entering the site, daily disinfection and cleaning as well as handout of mandatory personal protective equipment (PPE) such as gloves and masks.

In Saudi Arabia, GE-built technologies help generate over 50 percent of the country's electricity. The recently built GE Manufacturing and Technology Center (GEMTEC) campus focuses on turbine repair, research into turbine operations in hot and harsh weather conditions, as well as monitoring and diagnostics. GESAT, a standalone JV between Dussur and GE, is building GE-licensed turbines locally in the Saudi kingdom.

During design and construction of the power plant, Ziegler Cat will work with Fagen Inc. which was selected as the engineering, procurement, construction (EPC) contractor. The new facility will be built on the current power plant site in Huron.

“When complete, it will have a smaller footprint and a larger setback than the current building,” developers pointed out.

The Huron Generation Station is the fourth application of Cat G20CM34 generator sets in the U.S. Along with the gas gensets, Caterpillar will deliver and install selective catalytic reduction (SCR) emissions systems, switchgear, exhaust stacks, and control solutions.

NorthWestern Energy is reshaping is power plant portfolio and nearly 58% of its energy is currently provided by wind and solar power installations. Hence, the new fast-start plant at Huron is vital to provide the utility with efficient backup power at varying load levels to help balance intermittent renewable energy supply.

Load acceptance, multiple fast starts per day

The Cat G20CM34 generator set are based on a turbocharged and aftercooled gas engine that offers ultrafast start times and load acceptance, while allowing for multiple fast starts per day. The engines can deliver high operating efficiency with low emissions, even under partial loads.

Jim Williams Jr., NorthWestern Energy’s director of thermal & wind generation said: “Caterpillar offers equipment with a successful history of quality and performance, and the generator sets will meet the energy needs of our South Dakota customers for decades.”

Based in Montana and South Dakota, NorthWestern Energy’s electricity utility business includes generation, transmission and distribution. Its service area in Montana covers approximately 107,600 square miles or about 73% of the states’ land area. In South Dakota, it operates as a vertically integrated generation transmission and distribution utility, with the exclusive right to serve an area in comprised of 25 counties.

The new solution combines the two, while integrating RWE’s renewable energy assets. It can also accommodate additional units such as battery storage systems and diesel-powered backup generators. Previously, RWE had two separate control systems: one for power plants in Germany and another for the Netherlands and Belgium.

Connecting assets to VPP to manage volatility

The new SCADA system based on Siemens Spectrum Power will be used in the RWE Supply & Trading Dispatch Centre in Essen, Germany, from where RWE manages its entire European power plant fleet.

By connecting numerous small units, RWE aims to create a virtual power plant (VPP) whereby the conventional plants and pumped-storage can offset the volatile power supply of renewables. By controlling plant dispatch down to the second, operators can meet the requirements of TSO with respect to system services, grid disturbances and minimisation of balancing energy.

Automatic control in real time

The RWE control team in Essen keeps constant watch over plant dispatch and the supply/demand balance as these can deviate from projections, e.g. in the event of unusual weather conditions or major events. Up to 500 optimisation runs are performed every day, using the power plant dispatch optimisation program created inhouse by RWE experts.

The program determines the most economical use of all power plant units and machines and uses that data to create current target schedules. These are then transmitted via Optime as a target figure to the corresponding unit or machine control system of each power plant location.

“Optime gives us automatic control in real time as well as improved control performance. In addition, it allows us to better coordinate our portfolio, which consists of renewable energy plants, the existing flexibilities of our industrial customers, and conventional power stations. In view of the expansion of renewable energy, this is becoming increasingly important,” said Guido Hommelsheim, Head of Dispatch at RWE Supply & Trading.

Sabine Erlinghagen, CEO of Siemens Digital Grid pointed out the success of this project hinged on the close cooperation with RWE. By implementing new control technology for Europe’s largest trading floor, Siemens combined SCADA tools on a single platform to allow RWE coordinate generating assets in three countries and provide virtually disruption-free grid balancing system services.

“In the future, it will be possible to optimise the integration of fluctuating levels of renewables-based energy,” Ms Erlinghagen said, stressing this holistic approach to power plant management will help accelerate the energy transition in Europe and around the world.

Import flexibility in Europe dwindles as gas storages are filling up fast. Analysts expect that inventories in continental Europe will be at 90% capacity by end-August, and “at tank tops” by the end of October. This heralds a “massive downturn in LNG deliveries.”

TTF prices have dropped below Henry Hub on some days in June, increasing the risk that cargoes could be cancelled beyond the 20th of the month as offtakers seek to minimise costs.

Domestic US gas production is forecast to rise from 85 billion cubic feet per day to 118 billion cubic feet per day (Bcf/d) by the end of this week, caused by stronger output as upstream companies overestimated the uptick in demand which remains tepid.

US LNG feedgas swells up

As gas production in the United States fails to find a home abroad, the backed-up feedgas will swell domestic inventories and accelerated the shift from coal-to-gas generation.

US feedgas now sits more than 5.0 Bcf/d below its late-March highs and is a major contributor in the shoulder season’s stubbornly high injection rate despite weaker production year-on-year, Energy Aspect’s figures show.

“As more gas that was bound for US liquefaction is pushed back into storage, prices will have little room for upside outside of extended summer heat, especially as we have also noted that an initial return of associated gas volumes is taking hold,” analysts commented.

This dynamic has already played out: Moderate weather throughout the east along with anaemic LNG feedgas pushed Henry Hub cash prices down to a 16 June settlement below $1.40/MMBtu – the hub’s lowest daily settlement price in some two decades.

Some 45 cargoes cancelled for August

Analysts are eagerly awaiting a report on LNG cargo cancellations for the month of August, which need to be posted to the U.S. Securities and Exchange Commission (SEC). Cheniere sales contract, as filed to the SEC, state that buyers must decide whether to lift an M+2 cargo by the 20th day of the month. Late cancellations make buyers liable to paying the difference between the cargo’s original value and the amount for which it can be resold.

While contract deadlines for Freeport and Cameron are unknown to the market, Energy Aspects says initial market soundings suggest as many as 45 were cancelled cargoes in August, slightly higher than in June.

As for this month, the current pace of loadings indicates that 40 cargoes were cancelled across all US liquefaction terminals: 30 from Cheniere Energy’s Sabine Pass and Corpus Christi terminal and 10 from Freeport.

At the start of 2020, in the months before the demand destruction due to the Covid-19 pandemic, Cheniere used to fill 40–45 tankers per month at a roughly three-to-one ratio between Sabine Pass and Corpus Christi.

Thus far in June, Cheniere has loaded just six cargoes, and Sabine Pass feedgas intake has noticeably declined to around 0.8 bcf/d, or just 20% of the terminal’s maximum capacity, as a result of a slowdown in exports. Feedgas to Corpus Christi has been flat at 0.4 Bcf/d throughout June, Energy Aspects figures show, at roughly 25% of its pre–Covid-19 highs.

The novel heat battery can discharge completely and feed the energy in the form of steam directly into customers' industrial plants, if and when required. The use of stored heat reduces the demand for fossil generated heat, lowering fuel costs while increasing the operational flexibility of the manufacturing process.

Energy storage systems compensate for the fluctuating feed-in of renewable energies and stabilize the grids. Under the ‘Future of Storage’ umbrella, Siemens and the Norwegian startup plan to form a global team of exports that cover all aspects of energy storage technologies, from batteries to thermal and thermo-mechanical energy storage systems.

"Energy storage is the key to a decarbonized world," says Jörn Schmücker, CEO Large Rotating Equipment at Siemens Energy and sponsor of the initiative. "With Future of Storage and our partner ecosystem, we will be able to offer our customers exactly the solutions that fit their needs - with the advantage of improving the efficiency and thus the profitability of their plants.“

The JV partners want access a broad portfolio of storage technologies. “We need to have the necessary expertise and develop suitable business models to offer every customer the optimal energy storage solution that best suits their needs,” Anette Ossege-Schaffrath, who heads the team at Siemens Energy, said, adding ‘Future of Storage’ will create a “prerequisite for achieving these goals."

The feedgas to LNG export terminals in June was 1.4 Bcf/d lower than feedgas volumes last year, according to IHS Markit figures, and more than 5.0 Bcf/d lower than the record-high feedgas volumes estimated in late March. The coronavirus pandemic has caused a global plunge in energy demand, though Asian gas markets are gradually recovering.

Lockdowns to contain the coronavirus, which has hit the United States particularly hard, has substantially reduced gas consumption from industries and businesses. Estimates from S&P Global Platts suggest that average industrial natural gas consumption in June 2020 has declined about 2.1 Bcf/d, or 9.6%, compared to June last year.

Higher gas-burn despite low electricity demand

Forward gas prices are set to remain low throughout this summer, accelerating the coal-to-gas switch in the power sector where gas has become the cheaper fuel source compared to thermal coal. Average daily power burn is up about 6% in June compared to last year, according to U.S. government data.

Strikingly this rise in gas power generation occurred despite essentially flat, if not falling, electricity demand growth so far this June.

Production falls slower than demand

Another effect of historically low natural gas prices is declining natural gas production. According to data from IHS Markit, dry production totalled about 90 Bcf/d in June, down nearly 3.7 Bcf/d from March 2020.

The recent steep fall in demand has outpaced the declines in production, putting downward pressure on Henry Hub prices. Further declines in gas production are expected due to the inherent time lag between gas price changes and adjustments to production levels.

Henry Hub seen rebound in winter 2020/21

In its June STEO forecasts, the U.S. Energy Information Agency (EIA) says dry production will continue to fall steadily, reaching a low of 84.2 Bcf/d in May 2021.

Falling gas production will put upward pressure on the Henry Hub price in the coming months, if demand keeps recovering. The June STEO expects higher natural gas prices by the end of 2020, forecasting Henry Hub to average $2.95/MMBtu in December.

Tuscon Energy’s 2020 IRP, filed to the Arizona Corporation Commission (ACC), outlines how the utility aspired to shift its generation mix cleaner energy sources. Key elements of the plan are the addition of 2,457 MW of new wind and solar power, of which 457 MW is due to become operational in 2021.

Capitalizing on falling cost of RES and gas generation

“Maintaining reliable service with higher levels of wind and solar power requires responsive, efficient natural gas resources as well as storage, which is projected to become much more affordable over the next decade,” said TEP chief executive David G. Hutchens.

“Our plan is designed to capitalize on those price reductions to achieve ambitious carbon emission reductions without compromising on cost-effectiveness or affordability.”

To balance intermittent renewable energy supply, TEP also plans to add 1,400 MW of new energy storage systems. The utility stressed “energy storage systems are projected to cost significantly less after 2030 than they do today.”

Taking steps to exit coal generation by 2032

The proposed coal exit, foresees to ramp down and ultimately retire TEP’s two coal power units at the Springerville Generating Station in 2027 and 2032. That timeline would allow TEP to reduce the plant’s workforce through attrition rather than layoffs.

Beginning in 2023, TEP plans to transition to seasonal operations that idle one of the Springerville power units during cooler months. Both units are still needed to meet summer peak demand. After the closure of Unit 1 in 2027, TEP plans to continue seasonal operations of Unit 2 through 203

TEP is on track to retire more than 600 MW of coal generation by June 2022 through recent and scheduled closures at the Navajo and San Juan Generating Stations (SGS). But TEP currently still dispatches two coal-fired units at the Four Corners Generating Station that are due to close in 2031.

SGS Unit 1 can produce up to 387 MW and came online in 1985, while Unit 2 can produce 406 MW and came online in 1990. Two further units were completed in 2006 and 2009 but these are owned by Tri-State Generation and Transmission Association and Salt River Project, respectively.

Contributing a ‘fair share’ to global CO2 reduction efforts

If implemented, the TEP’s switch to gas and renewables would allow the utility maintaining a steady energy supply for customers in Southern Arizona while avoiding more than 50 million tons of CO₂ emissions over the next 15 years.

The emission reduction target represents TEP’s “fair share of worldwide efforts” to limit global warming to well below 2 degrees Celsius under the 2015 Paris Agreement, it pointed out.

“Our goal is ambitious but realistic, reflecting what we can achieve using existing technology during the 15-year time period covered by our IRP,” said TEP chief executive David G. Hutchens.

“We’ll be reducing carbon emissions at a pace that places us at the forefront of global efforts to combat climate change.”

Once operational, North Sea Link – a 1.4-Gigawatt (GW) electricity interconnector – will allow the UK to import enough clean energy to power up to 1.4 million homes.

To reach the halfway mark and lay the cable in Norway, developers had to transport materials piece by piece through a lake which cannot be accessed by the size of a regular cable-laying vessel. Hence, developers had to build their own custom-made floating platform (pictured), the first of its kind in this scale in Norway.

Construction of the platform in Suldalsvatnet, had an average of 25 people working on it daily over 11 days to allow for the start of the cable laying on the Norwegian side. Working at depths of up to 210 metres, the laying of the 2.8km parallel subsea cables was executed from a 43 x 15 metre platform, equivalent to the size of two tennis courts.

Works progress to Suldal fjords this summer

The next milestone is to lay the cable out from the fjords in Suldal, to the North Sea this summer.

Work will be carried out throughout the remainder of the year, with a view to completing the two parallel 720km cables between Cambois, Northumberland in the UK and Kvilldal, in Norway before the end of 2021.

The Marubeni-led technical study – running through to the end for February 2021 – entails a series of trials for direct usage of ammonia as a fuel in JERA’s coal- and gas-fired power plant.

In the context of the feasibility study and during technical trials, researchers from Marubeni and IHI Corp will be also scrutinizing the economics of equipment cost, operational expenses as well as the cost for producing and transporting ammonia to the power stations.

Gov’ support NEDO research

Marubeni and IHI Corp’s efforts on ammonia co-firing are in line with Japanese government’s aspirations to implement hydrogen-based energy projects. Dubbed NEDO, the research project seeks to develop multi-burner ammonia co-firing technology for pulverized coal boilers, which can later be amended for use in gas-fired power units.

JERA is looking to find out the necessary capital investment to retrofit its existing plants with the novel ammonia co-firing technology, once it is ready for commercialization. To this end, it is allowing researchers to carry out tests and trial runs at some of its thermal power plants.

Australia-based Woodside Energy is also participating in the study, striving to identify challenges related to realizing large-scale ammonia production lines.

B.Grimm Power Public Company Ltd. became the third independent Thai company to receive an LNG import licence, a the government is taking steps to liberalise the power and gas sector and increased LNG import volumes to ensure a stable supply of electricity.  

The regulator in May awarded a license to B.Grimm Power to import 650,000 tonnes of LNG imports per annum to feed its existing five gas-fired power plants.

The Thai state oil company PTT previous had a monopoly on LNG imports until the state-run Electricity Generating Authority of Thailand (EGAT) was given a licence in 2019, and in the following three further licences were awarded to B.Grimm Power, the Ratch Group and Gulf Energy Development .

Plans to build more LNG-fuelled power units

Preeyanart Soontornwata, President of B.Grimm Power said “we have new gas-fired power plants, [so] we have a right to ask for a new shipping licence for additional natural gas volumes.”

She was speaking as a land lease agreement was signed for a sixth gas power plant and water cooling venture linked to the new U-Tapao International Airport and Eastern Airport City Development Project. The U-Tapao project will see B.Grimm power operate a 95 MW hybrid plant, powered by natural gas and solar PV.

Plans also foresee the construction of a new, wholly-owned LNG import unit for procuring and delivering the fuel to the power plants. The five new power units under construction have a combined capacity of 700 MW, and B.Grimm aims to start importing LNG as early as 2022.

Gulf Energy to also import more LNG

The Thai energy regulator in May also approved Gulf Energy’s application to import 0.3 million tons of LNG for use in 19 small-scale power plants, operated by the state-owned utility EGAT. T

Gulf Energy Chief Financial Officer (CFO), Yupapin Wangviwat, said the regulator approved a licence for the amount to 1.4 million tons per year, to be used as a fuel for electricity production for Hin Kong Power Project with capacity of 1,400 MW. The plant is located in the Hin Kong subdistrict in Ratchaburi province and is expected to commence commercial operation in 2024 and 2025.

The licence awards to both B.Grimm Power and Gulf Energy support Thailand’s plans to increase imports of LNG, taking advantage from the current low prices in an oversupplied market to shift the Thai power mix from coal to gas generation.

Second train underway at Map Ta Phut LNG

Currently, B. Grimm Power’s cargoes are delivered to the Map Ta Phut LNG import terminal in Rayong. Adjacent to that first train, a second LNG import terminal with capacity of 7.5 mtpa is under construction and is expected to start operations by 2022. A third expansion is in the design phase and undergoing a feasibility study.

As one of Thailand’s leading independent power producers, B.Grimm has already developed several small-scale plants whose entire electricity output is sold to the state grid operator.

All these plants are situated in Thailand’s Eastern Economic Corridor (EEC) which comprises the three provinces Chon Buri, Rayong and Chachoengsao. The government wants to develop the EEC into a hub of high-tech industries with the added development of logistics and aviation services.

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

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

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

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

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

Growing investment appetite amid falling costs

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

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

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

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

The acquired asses have a total capacity of more than 800 million cubic feet per day (MMcf/day) and benefits from significant interconnectivity to major-long haul pipelines, providing reliable, cost-advantaged gas supply to utilities and other key end-users.

Transaction to close in H2-2020

The transaction is expected to close in the second half of 2020, subject to customary regulatory approvals. The terms are not being disclosed. Barclays served as financial advisor to Basalt, while BMO Capital Markets advised Third Coast Midstream.

“This investment expands our asset base of high-quality, demand-driven natural gas pipelines in the south-eastern United States,” said Rene Casadaban, CEO of Black Bear Transmission. “The NGT Assets are highly complementary to our existing Black Bear footprint and are strategically positioned to capture continued natural gas demand growth in the region.”

Matt Rowland, CEO of Third Coast Midstream welcomed the follow-on sale of Natural Gas Transmission assets to Black Bear. “We look forward to another successful transition with the Black Bear team following the sale of these assets, as Third Coast Midstream takes another step in its strategic repositioning to focus on its core Gulf of Mexico infrastructure platform," he said.

Third Coast Midstream owns 5,100 miles of onshore and offshore gas, oil and NGL pipelines, seven gas processing plants and 17 gathering systems. The company has direct exposure to prolific U.S. gas producing regions, including the Eagle Ford Shale of South Texas, the Deepwater Gulf of Mexico, and the Cotton Valley/Haynesville Shale of East Texas.

Despite a slow first quarter, Indonesia’s LNG consumption keeps rising from 1.1 million tonnes in the second quarter and appears to be well-cushioned against the impact of Covid-19. Reduced pipeline gas and low spot prices were likely to have supported Indonesia’s LNG demand.

Gas gains ground against coal

“Cost of generation and meeting growing electricity demand is key in Indonesia,” said Wood Mackenzie’s principal analyst Lucy Cullen. “While coal will always be cheaper, it would be interesting to see in the longer term whether lower gas prices could encourage greater role of gas in the energy mix, and eventually accelerate the country’s energy transition.”

Regulations, recently introduced by the government, are aimed at lowering domestic gas price to $6 per million British thermal unit (mmbtu) for seven key industries and the electricity sector. These measures are meant to improve industrial competitiveness, especially for exports, and create multiplier effects.

LNG is expected to make up a growing a share of Indonesia’s energy mix in the years ahead, offering opportunities for infrastructure development given that imports will be vital to balance the country’s declining domestic gas production.

“The story of Indonesia is consistent with Asia’s outlook at large,” Ms Cullen commented. “The region’s LNG imports will reach 250 Mt this year, a 2.5% increase compared to last year, and could hit 315 Mt in 2025.”

The share natural gas of Indonesia’s total primary energy demand has been about 12-13% over the past few years. By 2040, Asia is expected to account for 40% of global LNG consumption with Indonesia and its Southeast Asian neighbours being key engines of this growth.

Tangguh LNG Phase-2 delayed

“While Tangguh LNG Phase 1 showed strong performance with 117 cargoes delivered last year, the Phase 2 expansion is expected to face delays,” Ms Cullen suggested.

In 2019, BP announced a first delay by a year after the LNG EPC lead-contractor Chiyoda signalled difficulties completing the project on schedule. The project also faced challenges moving labour and materials to the remote location of the plant, while tsunami activity in Eastern Indonesia added to the amount of site preparation work required.

The coronavirus is expected to trigger additional delays with the contractor declaring force majeure in March 2020. Wood Mackenzie expects plant start-up to be delayed to Q2-2022.

Situated near Tórshavn, the Faroese capital, the power plant now has sufficient capacity to supply electricity to the almost 52,000 islanders. To that end, SEV relies on an intelligent combination of renewable energy sources, storage solutions and power-plant engines to ensure grid stability.

Sund is the largest of the Faroe’s three engine-driven power plants. Apart from Sund, EV also operates hydroelectric power plants, several wind farms and energy-storage solutions.

From base-load security to intelligent backup

“The role of the Sund power plant has changed over the past few years. Today, it still serves to secure the base load, but it has also become an indispensable backup that compensates for weather-related fluctuations of renewable energies,” said Dr Tilman Tütken, Head of Region Europe, Business Unit Power Plants at MAN Energy Solutions

Responsible for the Sund upgrade was Danish power-plant specialist, Burmeister & Wain Scandinavian Contractor A/S (BWSC), while MAN supplied the four engines. These MAN 51/60 engines are intended to run at 80% load and thus to generate district heating with the remaining 20% serving as a variable reserve.

"Our engines can increase their output at any time to compensate for power fluctuations and are throttled back when wind or precipitation conditions improve," added Tütken. "Thanks to this setup, SEV can on the one hand exploit the full potential of renewable energy and, on the other, guarantee maximum grid stability."

Hybrid systems as a vision of the future

The isolated energy system in the Faroe Islands is an impressive example of how all available energy resources can be integrated into an intelligent and innovative microgrid. In Tütken’s view “the future is hybrid,” and the hybrid power solution on the Faroe Islands’ energy system “can act as a model for other projects” in remote regions.

Innovation and generation of intellectual property have been a part of the Holset VGT success since it entered the market in 1998, Cummins underlined. The use of VGT turbos helps plant operators to improve fuel economy and reduce emissions.

“For more than 100 years Cummins has created dependable quality power technologies and we are committed to defending our intellectual property for the success of our customers,” said Shon Wright, Vice President of Cummins Turbo Technologies.

The Holset VGT from Cummins is suitable for light to heavy-duty applications. The VGT turbo has a patented one-piece sliding nozzle that continuously moves to vary the power of the turbine and the amount of air delivered to the engine.

In the power generation process, exhaust gas enters the turbine section of the turbocharger as it leaves the exhaust manifold. Pressure from the exhaust gas causes the turbine to rotate.

Headquartered in Columbus, in the U.S. state of Indiana, Cummins is a global leader in power generation equipment. The company’s products range from diesel, natural gas, electric and hybrid powertrains and powertrain-related components including filtration, aftertreatment, turbochargers, fuel systems, controls systems, air handling systems, automated transmissions, electric power generation systems, batteries, electrified power systems, hydrogen generation and fuel cell products.

Founded it 1919, the company today employs approximately 61,600 people and in 2019 earned about $2.3 billion on sales of $23.6 billion.

Dispatchable gas power capacity has been largely destroyed by the earthquake which shifted Puerto Rico’s power supply to predominantly petroleum-based generation.

On January 6, 2020, a magnitude 5.4 earthquake hit Puerto Rico, followed by a magnitude 6.4 earthquake on January 7. The epicenters of these earthquakes were not far from two of Puerto Rico’s largest power plants, Costa Sur and EcoEléctrica, both primarily fuelled by natural gas.

The earthquakes caused widespread power outages, and significantly damaged the 967 MW Costa Sur plant, knocking it offline indefinitely. Costa Sur was severely damaged by the earthquake, while use of the EcoEcoEléctrica gas power plant is reduced so oil-fired gensets currently cover 60% of the island’s power supply.

Reliance on oil-fired power units

With the Costa Sur plant offline, Puerto Rico’s five petroleum-fired plants have increased generation to meet demand. Electricity generation from the Palo Seco petroleum-fired plant has more than doubled, and the petroleum-fired Aguirre and Central San Juan plants have increased their monthly average generation by 8% and 10%, respectively.

In the first three months of 2020, heavy fuel oil accounted for 60% of generation, compared with 38% in 2019. Gas-fired generation, in contrast, has fallen to 17% of total generation compared with 41% in 2019 while the contribution of coal and renewables largely stayed the same.

In addition, two petroleum plants that normally only serve peak load and generally run at low average monthly levels in the winter and spring months, Cambalache and Mayagüez, significantly increased their generation in the first three months of 2020.

Cambalache’s monthly average has grown from 12,000 megawatthours (MWh) per month in 2019 to 40,000 MWh per month through March 2020; Mayagüez increased from an average of 8,000 MWh to 20,000 MWh per month in the same time period.

Switchgear bays are found at substations and help dispatch or cut electrical power in case of a problem on the grid. Together, German’s specialty chemicals leader Evonik and UK’s Omexom, an Engineering Procurement and Construction (EPC) company, recently ordered a total of 18 g³ GIS bays.

Evonik signed a contract for 10 F35-145kV g³ GIS bays for its Marl Chemical Park in western Germany. Commissioning is estimated for June 2021.

Omexom, meanwhile, selected GE as its 132 kV GIS supplier for an industrial customer’s waste plant in the UK. The contract for eight 145 kV GIS bays using g³ was signed in March, with commissioning estimated for September 2021.

Slashing CO₂ emissions by 99%

The innovative products feature the same high performance and reliability as SF₆ equipment but have a gas mass with more than a 99% reduced CO₂ equivalent value. More importantly, life-cycle assessments (LCAs) have shown that g³ products do not cause pollution transfers to other environmental indicators.

Jürgen Bücker, head of regulation management energy networks at Evonik said g³ was a “natural choice” for the company. “Not only do the g³ products offer us the same reliability and ease of handling as our previous SF₆ equipment,” he said, “they will go a long way in helping us reach our goal of halving our absolute Scope 1 and Scope 2 greenhouse gas emissions by 2025.”

With these two industrial orders, GE has now sold more than 100 g³ GIS bays since launching g³ on the market in 2016. Eighteen transmission and distribution utilities have installed g³ equipment at a total of 26 sites across Europe.

With the largest 145 kV GIS SF₆-free installed base, g³ is the leading SF₆-free solution for high-voltage equipment. SF₆ is estimated to contribute 23,500 times more emissions than CO₂, if leaked, and can remain in the atmosphere for up to 3,200 years.