The upgrade will turn InfraLeuna’s existing power plant into a high-performance combined-cycle gas and steam turbine plant, with improved efficiency and flexibility. Works focus on connecting the existing gas turbine to the new heat recovery steam generator (HRSG).

Fuel utilization rate of the upgraded gas-fired power plant will reach 84%.

As general contractor for the modernization, Kraftanlagen will be responsible for the engineering studies, construction and commissioning of the entire plant. The modernization of the CCGT will provide a competitive supply of process steam and electricity for companies installed in the chemical complex near Leipzig.

“This investment will enable us to optimise the energy supply of the Leuna chemical complex once again and create the right conditions for it to pursue its growth,” Christof Günther, CEO of InfraLeuna said, welcoming the support of Kraftanlagen München GmbH, as a skilled general contractor.

Kraftanlagen pointed out the latest contract win follows the commissioning of the Kiel coastal power plant in January.

The rate of significant banks, insurers and asset managers/owners announcing coal restrictions has seen a step rise to reach 127 institutions. Citi, for example, will no longer provide project-related financing for new thermal coal mines and has pledged to halve its coal credit exposure from a 2020 baseline by 2025, and cut it to zero by 2030.

BlackRock, the world’s largest asset manager, made a landmark announcement in January 2020 to divest thermal coal mining exposures from its $1.8 trillion of actively managed funds. Since then, a further 20 players followed suit and pledged to gradually exit coal financing.

China – lender of last resort for coal plant

The global renewable energy champion China is simultaneously funding over one-quarter of coal plants currently under development outside the country. China has committed or proposed about $36 billion in financing for coal-based projects in 23 countries. Most ventures are based in Bangladesh, Pakistan, Vietnam, Indonesia and South Africa.

State-controlled Chinese banks have offered funding for over one quarter, or 102 GW of the 399 GW of coal-fired power generation capacity hat is currently under development outside China. Projects include investment in export coal mines, coal-fired power plants, and the associated rail and port infrastructure.

Tide turns to renewables elsewhere

Renewables are now the low cost source of energy, and they have near zero carbon impact on our warming planet. IEEFA expects the deflation of renewable energy costs to continue for the coming decade, accelerating the realisation of stranded asset losses for aging and obsolete coal-fired power plants, and other fossil fuel technologies.

Governments and corporate leaders are also moving away from coal. President Moon Jae-in of South Korea has reiterated his Green New Deal to cease coal financing globally, while Shell, Total and BP pledged to move into zero emissions electricity generation.

It appears that coal power generation actually peaked in 2018, analysts noted. There was an unprecedented and unexpected 3% decline in coal-fired power generation globally in 2019, they said, suggesting it is now set for a second consecutive decline in 2020.

India tenders for solar PV

In India, the third largest economy in Asia-Pacific, the cost of renewable energy is now 20-30% lower than the cost of a new domestic coal-fired power plant, and 50% below that of a new import-reliant coal power plant. Even as electricity demand has collapsed 27% this month to-date, the Indian government announced the awarding of a $2 billion, 2 Gigawatt (GW) solar tender at a near record low price of Rs2.55/kWh or $33/MWh.

“Renewables are clearly the low cost, zero inflation, zero emissions source of new domestic electricity supply for India,” IEEA analysts noted.

Large amounts of landfill gas can be collected as a fuel for waste-to-energy projects, whereby the landfill gas is often complemented with natural gas to ensure a stable fuel source.

At the landfill next to the South Tripoli Gas Power Station, part of the waste is being burned in the open which negatively impacts the station. According to the station’s head of automatic control system, Abdul Sattar Al-Nayli, the smoke and ash of trash fire has been blocking the air filters which forced GECOL to halt operations at the power station.

Eager to avert the risk of further shutdowns and operational losses, the South Tripoli Gas Power Station proposed to either burn part of the landfill safely for power generation, or use methane emissions from the landfill for co-firing.

Ideally, Mr. Al-Nayli would like to close down the landfill entirely and build a new combined-cycle fired power station on the site. "We could build a new power plant on the landfill's ground with an output capacity of 2,000 megawatts, which will be a great strategic project,” he told local media.

The proposed CCGT project could benefit from the existing gas supply infrastructure of the South Tripoli Power Station, but it is questionable if the government can dedicate enough upfront funding to make it attractive for foreign investors.

With a population of six million, Libya sits on 48 billion barrels of oil and 55 trillion cubic feet of natural gas reserves. Though 80% of the country's GDP and 99% of its government income derive from the energy sector, little of this money found its way into setting up a reliable domestic power grid.

When rolling blackouts became commonplace, General Electric Company of Libya (GECOL) started rebuilding the electrical infrastructure to not only meet current demands but provide a stronger foundation for future economic growth. Rather than waiting for years to plan, build and commission new power plants, GECOL contracted with APR Energy to bring in temporary generators to provide a rapid 450 MW boost. Some of these units were equipped with inlet fogging systems, attaining a 15% increase in output in the hot Sahara operating conditions.

APR provides large-scale, fast-track solutions to provide seasonal peak capacity or for bridging power during new plant construction. Its shipping container-based fleet amounts to 1.2 GW, and includes dual-fuel gas turbines, diesel reciprocating generators and natural gas reciprocating generators. APR provided mobile gas turbines at four key sites in Libya (250 MW) as well as 200 MW of diesel generators at two sites.

Challenges during installation included having to deal with attacks from armed groups, kidnapping of engineers, remote locations, extremely high temperatures, sand storms and lack of water. Despite all the challenges, APR managed to survey twelve sites, select the six that were used, ship or fly in the containers, truck them to their destinations, build crew quarters, install and commission all the equipment, and train more than 80 GECOL staff on maintenance and operations of the turbines and diesel units. The final units came on line within five months of signing the initial contract.

Desert fogging

One of the desert locations chosen was Samnu, where it rains less than 1/2" per year. Afternoon temperatures in Samnu average over 90°F for more than half the year, and over 100°F from June through September.

APR selected Pratt and Whitney FT8 MobilePac gas turbine packages for the site. While the gas fueled, water injected FT8s can generate more than 24 MW at 40°F, the output drops below 20 MW at 113 °F, a typical summer temperature. 0ver that same temperature range, the heat rate rises from 10,000 kJ/kWh to nearly 11,000 kJ/kWh.

Given the output and efficiency losses with high ambient temperatures, it was essential to add inlet cooling to those turbines. The problem was the lack of water. While the FT8s do come with water injection, due to the lack of water in the area APR decided to use inlet fogging systems from Mee Industries.

"APR Operations observed that MeeFog could provide the equivalent amount of power boost as the water injection system while consuming almost half the amount of make-up water," says Michaud. "The quantity of water saved by not running the water injection system while maintaining the required power boost will significantly increase the overall life-cycle of the demineralized water system."

For the Samnu power station, there was a dedicated fog pump skid for each turbine. Each skid has three pumps and two motorized ball valves. These pumps are operated in a sequence that provides fourteen stages of fog output each with 24 operating nozzles. A weather station monitors the temperature and relative humidity and sends this data to a programmable logic controller (PLC). The PLC also connects to the turbines distributed control system (DCS) to receive data on the inlet air volume. The PLC computes, based on ambient conditions and air volume, how many of the 14 fogging stages can be turned on without exceeding the set points.

At Samnu, the fogging system was designed for an ambient dry bulb temperature of 113° F and a wet bulb temperature of 68°F, a difference of 45 °F. The 14 stages could each provide 3.5 °F of cooling, so the entire system can provide the desired 45 °F of cooling, plus one stage of overspray.

"Depending on ambient conditions, the fogging systems can run 100% of the time to maintain the desired increase in output," explainsed Tom Michaud, project manager for APR Energy. "By using the MeeFog system, APR experienced a power boost of approximately 3 to 4 MW per turbine."

MIGA provides political risk insurance for energy projects, helping investors in developing countries to tap debt finance. The guarantees for Globaleq Holdings protect the investor against the risk of breach of contract (BoC) by the government of the Ivory Coast.

Insulating against political risk

Globeleq CEO Mike Scholey underlined MIGA’s Breach of Contract cover provides comfort and risk mitigation to enable the company to continue supporting the project. Developers had taken Financial Investment Decision (FID) on Azito Phase-4 in January, backed by a $310 million financing package arranged by the International Finance Corporation (IFC) and other development banks.

“Amid rising concerns about the impact of the COVID-19 pandemic and stagnating foreign direct investment flows to the Ivory Coast, this transaction reflects an ongoing commitment by investors to ensure reliable and low-cost provision of electricity to consumers,” said MIGA’s executive vice president, Hiroshi Matano.

Flexible and cheap electricity for RES backup

The 253 MW expansion of the Azito CCGT will be achieved by adding a new GE gas turbine and a new steam turbine to the existing Azito combined-cycle power plant. An additional GT13E2 MXL2 gas turbine upgrade will boost the capacity of the combined-cycle plant from 460 MW currently to 713 MW, equaling about 30% Ivory Coast’s total capacity installed.

According to the Globeleq CEO, the Phase-4 expansion project will “supply the cheapest electricity in Ivory Coast using the latest, most efficient technology.” The flexible new unit will enable the West African country to integrate more intermittent wind and solar power sources to the grid, while exporting surplus electricity to neighbouring countries.

Azito Energie, founded in 1997, is owned by Globeleq Generation Ltd and Industrial Promotion Services. Located in the Yopougon district of the Ivory Coast, some 6 kilometers west of Abijan, the CCGT is run under an operation and maintenance agreement between Azito O&M and Azito Energie.

WTI front-month June was last seen trading at $10.20/bbl, while the comparative Brent front-month eased to $19.12/bbl.

Analysts said the WTI plunge was largely caused by a sell-out of the front-month June contract by exchange-traded funds (ETFs), which buy into months later in the year in a bid to avert massive losses in the event that WTI prices again turn negative. On April 20, the WTI closed at a record low of -$37.63/bbl.

Gas prices could go lower

Forward gas prices in Europe, notably at the liquid Dutch TTF hub, slumped to record lows as both Norway and Russia continue supplying pipeline gas while distressed U.S. LNG cargoes are also looking for a home in Spain, France or the UK.

Natural gas, still largely sold under oil-indexed contract, will follow the low oil prices with a three to six month time lag. Triple whammy of weak demand, unbridled production and exhausted storage capacity keeps gas prices subdued despite the cautious lift of lockdowns in some key European economies.

Energy Aspects warns the bear market is bound to continue until markets are balanced, probably after summer. “There comes a point when everything starts looking unprofitable, but prices could go lower,” lead analyst Trevor Sikorski said.

Fighting for market share

Northern Europe is drowning in gas as Russia and Norway compete for market share. Break-even costs at the biggest fields of Equinor, formally Statoil and StatoilHydro, are as low as $1/MMBtu and the company as a lot of operational flexibility which it uses to maximise value.

Russia’s state-owned Gazprom, on the other hand, is not chasing the price and might keep exporting gas to Europe even if their marginal costs were higher. “They are the last to cut production,” analysts noted, forecasting gas supply is bound to increase despite the current weak demand.

Distressed LNG cargoes are fighting for market share with pipeline gas, with shipments predominantly going to Spain and the UK. The Spanish TSO Enagas noted LNG import for January through May totaled 107 TWh, up 32% from the same period last year. In contrast, piped gas supply from Algeria’s Sonatrach have fallen 42% to 30 TWh.

By consolidating power plant technologies of Mitsubishi Heavy Industries (MHI) and Hitachi, MHPS has developed an integrated Air Quality Control System (AQCS) comprising FGD, Selective Catalytic Reduction (SCR) for denitrification, and Electrostatic Precipitator (ESP) for dust collection systems.

Yokohama-based MHPS claims it is the “world’s only manufacturer able to independently offer proposals and provide these [above-mentioned] systems.” The company’s centralized approach allowed it to develop and mass-produce technologies that greatly reduce air pollutants such as sulfur oxide (SOx), nitrogen oxide (NOx), and particulate matter.

MHPS has delivered more than 300 FGD systems to the global market. “We have expanded the business by providing technologies and guidance in countries where demand for advanced Air Quality Control Systems (AQCS) has risen alongside economic development, and applied these technologies in joint projects with Mitsubishi Shipbuilding,” the company stated.

Going forward, the Japanese manufacturer wants to focus on the widespread adoption of AQCS, accurately assessing customer needs and promote the decarbonization of energy markets.

Capable to run on dieses and natural gas, the 12V51/60 engines will generate around 24 MW of electrical power in its role as the primary base-load provider at Miyako, a small Japanese holiday island with 50,000 inhabitants.

“Our engines will mainly run on natural gas but, due to their dual-fuel capability, also offer maximum fuel flexibility and reliability. This is highly important for independent power supply for remote islands such as Miyako,” explained Martin Höhler, MAN head of sales in the Asia Pacific.

The versatility of dual-fuel engines is beneficial for supplying remote regions with reliable and independent energy, he said. The customer Kawasaki HI is one of MAN’s “longest-standing partners,” Höhler pointed out, “with a shared business history dating back to 1911.”

Okinawa Electric Power had some years ago installed two 18V48/60B engines at a power plant on the neighboring island of Ishigaki.

As Berlin is handing out generous stimulus packages to revive the economy after crippling coronavirus lockdowns, policy makers are funneling funding into research for electrolysers. Green hydrogen, produced through electrolysis from excess renewable energy, is seen as a silver bullet for sectors with particularly stubborn emissions, such as heavy industry and aviation.

Job machine

The government hopes Germany could create hundreds of thousands of jobs by the middle of the century if it can hold onto its current share of the global market for electrolysers that produce hydrogen, which stands at around 20%.

A highly anticipated National Hydrogen Strategy is due to be approved by the government in the coming week. But key questions are still open such as the volumes of green hydrogen Germany is aiming to produce, and whether hydrogen produced with controversial carbon capture and storage (CCS) should be supported for a transitional period.

Researchers and industry are keen for Germany to become a global technology leader in "tomorrow's oil" by beating Asian countries. We must seize the unique opportunity to use our know-how to become the supplier of a global energy transition,” the research ministry stressed.

Industry supportive

Germany’s export-driven industry has also become a cheerleader for hydrogen. Ramping up this technology internationally would be "a success both in terms of climate policy and industrial policy," according to Germany's industry association BDI, which insists that "the current hydrogen hype is justified."

Steelmaker ThyseenKrupp and the chemicals group BASF have detailed plans for cutting emissions, but lack viable business models to implement them - not only because green hydrogen is still too expensive, but also because massive investments are required to enable its use on a large scale.

The industry said in a study it could become largely greenhouse gas neutral by 2050 with additional investments of around 45 billion Euros. But it would need more than 600 Terawatt-hours (TWh) of electricity per year from the mid-2030s – more than Germany's entire current power production – mainly to produce hydrogen and other renewable fuels.

To become carbon-neutral by 2050, Germany will eventually have to replace natural gas in its energy mix with clean hydrogen. Technology costs would have to fall substantially, possibly supported by investment subsidies, to make green hydrogen an economically viable option.

Project finance is purely based on market consideration. “This sizable 70 MW project demonstrates the growing value being placed on energy storage; there are no government programs or regulations in place that incentivised this build,” said Risto Paldanius, Wärtsilä’s business development director for Energy Storage & Optimisation.

Playing the arbitrage

The GEMS management system will facilitate ‘energy arbitrage’ with the system’s battery storage capabilities. This allows the customer to purchase electricity from the market when prices are low, and sell stored energy back into the market when short-term costs spike.

Built on behalf on an unnamed utility customer, the will be Wärtsilä’s largest energy storage deployment tied to a renewable resource in the western United States. This adds to Wärtsilä’s portfolio of more than 20 operating energy storage projects in North America, including two grid-scale 9.9 MW energy storage systems in Roscoe, Texas.

Focus on safety

The new energy storage system in CAISO, based on lithium iron phosphate batteries, will be paired with Wärtsilä GEMS platform to increase deployment and dispatch of the customers wind and solar power assets. GEMS will increase revenue and ROI by maximising battery performance and longevity and enabling additional value streams.

“For this customer, safety starts with a lithium iron phosphate battery option, which has several fundamental safety features such as a lower thermal runaway temperature and very low temperature rise rate. Temperature, smoke and fire detection, as well as suppression systems, are all designed for early detection and prevention of any safety related incidents,” Paldanius explained.

Prior to the pandemic, analysts had forecast gas demand of 371 bcm in 2020 for these markets, which together account for 70% of European gas demand.

In Germany, Europe’s largest gas market, industrial demand initially proved relatively resilient. However, this has lost momentum since country-wide social distancing restrictions and lockdowns in some states were introduced. “Overall, demand is set to drop by 3.5 bcm if the current restrictions last for three months,” forecasts Murray Douglas, from Wood Mackenzie’s European gas team.

In the UK, the second-largest gas market, electricity demand has reduced by 14% since the start of the lockdown. “As coal is uncompetitive in this market, lower electricity demand poses a disproportionate risk to gas. We currently expect 2.6 bcm of lost gas demand if the lockdown lasts for three months,” Douglas said.

Italy, hard hit by the pandemic and subsequent lockdowns from March 10, is forecast to experience Europe’s largest loss of gas demand, reaching 4.4 Bcm. Though the nationwide lockdown has been extended to 3 May, some small retailers have re-opened and some manufacturing has returned. WoodMac figures show there is already a clear rebound in gas and electric demand over the last week” – though still well below pre-coronavirus levels. But a weaker Italian economy in the aftermath of the pandemic is likely to have lasting effects on gas demand.

Supply keeps coming from Norway and Russia

Despite the demand destruction due to the pandemic, European gas producers have delivered only minimal adjustments so far. Northern Europe is drowning in gas as Russia and Norway compete for market share.

Break-even costs at the biggest fields of Equinor, formally Statoil and StatoilHydro, are as low as $1/MMBtu and the company as a lot of operational flexibility which it uses to maximise value. Russia’s state-owned Gazprom, on the other hand, is not chasing the price and might keep exporting gas to Europe even if their marginal costs were higher.

However, with European hub prices remaining low, some operators will face challenges in covering even their short-run marginal costs. For now, some of Europe’s legacy pipeline suppliers are falling below 2019 levels.

Pressure builds on LNG as storage fills fast

“By the end of March, Europe had a record 57 Bcm gas in storage, further weakening an already oversupplied summer market,” Douglas noted.

“Attention is turning to Ukraine’s gas storage facilities as a potential solution,” he said. “Additionally, we are likely to see increased pressure on LNG suppliers to the European market – most notably from the U.S.”

In energy-hungry China, new-build solar PV projects are almost on par with the running cost of coal-fired power plants, at an average of US$35/MWh. “This is significant as China advances on its deregulation agenda, opening up competition in the power sector,” BNEF notes in its latest technology benchmark report.

New-build tracking PV projects can be realized at a cost as little as US$26 per MWh, dependent on location, while technology cost for a combined-cycle units are $66-96 per MWh and as high as $146-309 per MW for open-cycle gas power units, also known as gas peakers.

And costs are bound to fall further, especially for solar PV where best-in-class projects financed over the past half year run a an levelized cost of energy (LCOE) between US$23 and US$29 per MWh. Such projects have been realized in Australia, China, Chile, and the UAE, where they challenge existing fossil power units.

Australia starts embracing hybrid power units

In sun-soaked countries like Australia, renewables have become the cheapest source of bulk generation by far. According to BNEF, the best LCOE for solar in Australia is A$40/MWh and for wind it is A$50/MWh.

However, the conservative Australian government is still keen to expand its gas reserve and use domestic coal production for several new coal power projects. Wind and solar power projects do not have the same level of public support as they have in Europe, although savvy utilities are starting to embrace hybrid power units.

Comparing technology costs, BNEF analysts point out that pairing renewables with battery storage is cheaper in Australia than flexible gas power units. Technology costs of wind and storage have fallen to A$77/MWh, and solar and storage to A$90/MWh.

Larger reverse auctions can benefit RES

The dramatic improvements in the cost-competiveness of solar and wind are attributed to technology improvement, manufacturing efficiencies, and the impact of policy instruments such as reverse auctions.

BNEF analysis suggests that since 2016, auctions are forcing renewable energy developers to realize cost savings by scaling up project size and portfolios. “Larger scale enables them to slash balance-of-plant, operations and maintenance expenses – and have a stronger negotiating position when ordering equipment,” said lead author Tifenn Brandily.

China was the first to implement containment measures, in mid-January, and experienced the world’s largest demand reduction in Q1 2020, of 6.5%.

Impacts were more limited in other parts of the world, where restrictions began in March and were introduced progressively. Electricity demand fell by 2.5% to 4.5% in Europe, Japan, Korea and the United States in Q1-2020 relative to Q1-2019.

Unprecedented demand drop

The decline is “unprecedented,” the IEA said, explaining that in absolute terms it is the equivalent of losing the entire energy demand of India, the world’s third largest energy consumer. Advanced economies will see the biggest declines, with demand set to fall by 9% in the United States and by 11% in the European Union.

“The impact of the crisis on energy demand is heavily dependent on the duration and stringency of measures to curb the spread of the virus,” the IEA executive director, Dr Fatih Birol said. Each month of worldwide lockdown at the levels seen in early April is found to reduce annual global energy demand by about 1.5%.

Shift to renewables

Lockdowns have changed power demand patterns, with consumption levels and patterns on weekdays looking like those of a pre-crisis Sunday. Full lockdowns have pushed down electricity demand by 20% or more, with lesser impacts from partial lockdowns. Electricity demand is set to decline by 5% in 2020, the largest drop since the Great Depression in the 1930s.

Simultaneously, the lockdowns are driving a shift to low-carbon energy sources which are set to extend their lead this year to reach 40% of global electricity generation – 6% ahead of coal. Electricity generation from wind and solar PV continues to increase in 2020, lifted by new projects that were completed in 2019 and early 2020.

Thermal power plants, meanwhile, finding themselves increasingly squeezed between low overall power demand and increasing output from renewables. As a result, the combined share of gas and coal in the global power mix is set to drop by 3% in 2020 to a level not seen since 2001.

Coal demand is projected to fall by 8%, while gas demand is seen on track to decline 5% in 2020 - the first year of decline after a decade of uninterrupted growth.

Emissions set to plunge

As a result of declining coal and oil use – global energy-related CO2 emissions are set to fall by almost 8% in 2020. This would be the largest decrease in emissions ever recorded – nearly six times larger than the previous record drop of 400 million tonnes in 2009 that resulted from the global financial crisis.

“Resulting from premature deaths and economic trauma around the world, the historic decline in global emissions is absolutely nothing to cheer,” Dr Birol said. “And if the aftermath of the 2008 financial crisis is anything to go by, we are likely to soon see a sharp rebound in emissions as economic conditions improve.”

The IEA head called on governments to learn from that experience by putting clean energy technologies – renewables, efficiency, batteries, hydrogen and carbon capture – at the heart of their plans for economic recovery. “Investing in those areas can create jobs, make economies more competitive,” he said, “and steer the world towards a more resilient and cleaner energy future.”

A mild Covid-19 scenario could see power prices recover already by 2022, while a severe recession caused by the pandemic would keep prices in the doldrums for another five years. Factors taken into accounts in these scenarios are the duration of lockdowns and implication on energy demand, commodity prices and project financing.

Power markets with a large contribution of gas-fired generation are seen hit harder by the recent fall in commodity prices.

“The effects of the coronavirus have rippled through European energy markets – significantly reducing demand and prices of gas and electricity,” Felix Chow-Kambitsch, head of commissioned projects - Western Europe at Aurora said, suggesting “European power utilities are likely to experience a significant fall in revenues in 2020.”

Project at risks

Utilities seeing their revenues slashed, with merchant-exposed renewables schemes significantly affected. Analysts warn up to 34 GW of new projects could be at risk of delay or outright cancelled.

While subsidized wind and solar projects have their revenues partly or full protected by the government, despite the fall in market prices, merchant-based project will bear the brunt of the crisis. Aurora analyst estimate just under 35 GW of renewable developments could be at risk as their revenue stream could fall by 20-50% dependent on the severity and length of the pandemic.

Slow recovery

Europe’s electricity demand is seen slowly recovering as lockdowns are gradually lifted in Germany and Spain, while Italy will follow in a weeks’ time. Power demand notched up as a consequence, with EU’s total power load rising week-on-week to 49.97 terawatt hours over the past week.

But electricity demand was still 7.5% below the same week last year, while the previous week it was 13.5% lower from 2019 levels.

“The worst is over in terms of hits to demand,” said Elchin Mammadov, an analyst at Bloomberg Intelligence. “Most utilities have written 2020 off. The recession is a bigger problem than weekly fluctuations in demand. We could see another drop later in the year.”

All three power plants are run in combined-cycle operations.

Completing the sale strengthens TC Energy’s financial position and will helps fund its capital program, said President and CEO Russ Girling. “When combined with the sales of Coolidge, an interest in Northern Courier and certain U.S. Midstream assets in 2019, we’ve realized approximately $6.2 billion from portfolio management activities over the last year,” he explained.

Raising funds for Kitimat feeder pipeline

The proceeds from the CCGT divestments in Ontario will be used to pay for construction of the Coastal GasLink Pipeline that will deliver feedgas to the LNG Canada project in Kitimat, B.C.

The Alberta-based pipeline company, formerly known as TransCanada, still owns six gas-fired power plants in Canada and one nuclear plant that provides 30% of Ontario’s electricity. TC Energy’s power gen assets have a combined capacity of 4,200 MW and the utility is planning to invest $2.4 billion to extend the lifetime of the Bruce nuclear plant by 2023, with another $5.8 billion to be spent later under a long-term agreement with the Ontario Independent Electricity System Operator.

“We continue to be a significant private sector power generator in Canada… and remain interested in new low-risk investment opportunities in the electricity sector within our core North American markets,” Girling stated.

In July 2019, TC Energy sold several US shale basin midstream assets held by its subsidiary Columbia Midstream Group for US$1.27 billion to UGI Energy Services but it owns and operates the Columbia Gas Transmission system in Appalachia.

Total passenger electric vehicle (EV) car sales, including hybrid electric vehicles (HEV), were up by over 24% last year, with hybrid vehicles making up over 60% of EV sales. Wood Mackenzie expects global electric car sales (with a plug) to account for 7% of all passenger car sales by 2025, nearly 14% by 2030 and 38% by 2040.

“Battery pack sizes continue to trend larger through the medium term, resulting in overall greater battery demand. We have seen the first announcements of the commercialisation of NMC 811 cells in EVs. Unsurprisingly, China was the first mover here, but the likes of SK Innovation are intent on the mass production of 811 cells before the end of 2019,” said Gavin Montgomery, Wood Mackenzie Research Director.

“If adoption gains speed, there will be a rising nickel demand at the expense of cobalt, and to a lesser extent, lithium,” he forecast.

Weak prices defer mining

Spot prices for lithium carbonate have fallen by just under US$7,000/t since June 2018, and analysts see some weakness in realized prices for lithium which is expected to persist throughout the second quarter of 2019. But things are bound to improve, in Mr. Montgomery view: “Lithium’s use in every lithium-ion battery type means it will have double-digit annual growth, making up over 80% of total lithium demand by 2030.”

Like lithium, cobalt prices have softened over H1 2019, with analysts warning the low prices may defer some mine projects. Moreover, swing supply coming from China is likely to keep a lid on any major price upside. “Although cobalt continues to look challenging in the long-term, the increased adoption of high-nickel batteries in EVs means the emerging deficits look slightly more achievable than previously expected,” he said.

Nickel, another battery metal, is mostly being produced in Indonesia. Although the battery sector share of nickel demand is much smaller than other metals, getting the quantity of nickel that EVs will need by the mid-2020s will be a challenge. According to Wood Mackenzie, “a low nickel price has hindered any project development and with lead times often up to 10 years,” analysts stress that “investment needs to happen now.”

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

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

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

Dow Chemical’s as 1^st customer

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

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

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

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

By maximizing the use of the existing Transco transmission corridor and existing compressor stations, the Hillabee expansion managed to substantially reduce construction cost and land use. Florida’s electric utilities now can efficiently access low-cost gas supplies, which helps increase the dispatch and profit margins of flexible gas peaking plants.

On-time and on-budget

Phase -2 of the project included the construction of approximately 11 miles of pipeline looping, a new compressor at William’s Station 95 in Alabama, and modifications to a compressor at Station 100. Micheal Dunn, Chief Operating Officer (COO) for Williams underlined the latest phased was put in service on-time and on-budget.

Phase-1 of the Hillabee expansion project was placed in service already in July 2017. Now that both phases are completed, Transco’s system capacity has been increased by more than 1,025,000 dekatherms of natural gas per day to a total of 17.6 million dekatherms per day.

Covering a length of over 10,000 miles, Transco is one of the largest and most cost-effective gas pipelines that reach U.S. markets in 12 Southeastern and Atlantic Seaboard states, including metropolitan areas in New York, New Jersey and Pennsylvania.

Headquartered in Tulsa, Oklahoma, Williams is one of largest gatherers, processors and transporters of natural gas in the United States and play a critical role in bringing the nation’s abundant cleaner-burning fuel supplied to power generators and industry, helping to reduce emissions. Throughout the U.S., Williams owns and operates more than 30,000 miles of pipelines system, handling about 30% of the nation’s daily gas supply.

Emerging markets tend to allocate state funding for emergency power units, often powered by mobile diesel or gas gensets, a Technavio market report finds. As much as 23% of the growth is forecast to originate from the Asia Pacific region, where the rental power market keeps rising at a 5.04% rate this year despite the current difficult macroeconomic environment.

Infrastructure spending

Governments in most industrialized countries are currently increasing their infrastructure spending in a bid to revive economies that have been reeling under the impact of the coronavirus pandemic.

The United States, for example, allocated $200 billion for infrastructural development under the President’s Budget for 2020. Similarly, the government of Abu Dhabi announced around $2.7 billion worth of infrastructure projects in February, and more projects might be sanctioned over the course of this year.

The implementation of these projects requires uninterrupted power flow for equipment functioning, which fuels the demand of mobile power gensets, Technavio analysts noted. These mobile, often trailer-mounted systems provide temporary power in cost-effective, flexible, and reliable way.

The market for mobile power generation equipment rentals is fragmented with several manufacturers competing for market share. Technavio singled out five key providers, notably: Aggreko and Ashtead Group, both offering generators and power turbines on a rental basis, APR Energy which additionally offers mobile gas turbine power plants, Atlas Copco which provides mobile diesel generators, and Caterpillar which offers generators ranging from 20 to 2,000 kilowatt-electricity (kWe) of power on a rental basis.

Having built a substantial battery business in recent years, Tesla is seeking to benefit from the global drive to renewable energy sources by offering its energy storage solutions as a backup. The U.S. company in 2017 built the world’s largest lithium ion battery in South Australia, run on a purely commercial basis.

Batteries backup renewable VPPs

Tesla is also advancing plans to aggregate 50,000 rooftop solar systems into a virtual power plant (VPP) in South Australia. Plans for similar VPPs, based on solar or offshore wind, might be in the making for the UK.  

In the U.S., Tesla has integrated such VPPs with its Powerwall residential batteries such as in the Green Mountain Power project in Vermont.

Megapacks replace gas peakers in California

In California, Pacific Gas & Electric (PG&E) and Tesla received regulatory approval in March to build a 182.5 MW/730 MWh clean energy storage system that could eventually be boosted to 1.1 GWh at Moss Landing, California. Construction of the facility, based on 268 Tesla Megapack lithium-ion batteries, is due for completion by the end of 2020.

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 claims 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.