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.

TTF prices have averaged $4.5/ MMBtu in 2019 but will need to drop below an average of $3.8/ MMBtu through 2020 to balance the market, according to Wood Mackenzie analysis.

“Our forecast touches back down to the low US$3/million Btu range during the summer. The risks to price remain heavily weighted to the downside,” said WoodMac’s director, European Gas, Murray Douglas.

Oversupply is building up on global gas market, with several LNG cargoes headed for Europe this week alone. According to shipping data, there are at least a dozen vessels heading for the UK terminals at Milford Haven in Wales and the Isle of Grain, located 45 miles southeast of London. A U.S. cargo will berth on January 23 at the Dragon import facility, followed by a Qatari cargo on January 25 into the South Hook terminal.

Prices at Britain’s NBP gas trading hub were last seen at the equivalent of $3.75/MMBtu, while the UK NBP Summer 2020 product price was as low as 3.70/MMBtu. However, analysts pointed out that Britain will not be able to absorb much more of the global gas glut than it already does.

Over the summer, the British and European LNG marketplace is expected to become “increasingly congested. Hence, some infrastructure constraints will likely surface and place further downward pressure on hub prices. “This will become particularly acute in the UK during summer where regas utilisation will be capped at 75%, assuming Norwegian pipeline deliveries follow historical trends,” Wood Mackenzie noted.

The UK’s lack of long-range storage; low summer demand - given that UK coal has already been displaced -  and the available exit capacity into continental Europe and Ireland will place physical constraints on LNG send-out. Analysts anticipate that Norwegian pipeline deliveries to the UK will consequently come under serious pressure, saying “we will see significant volatility in NBP-TTF differentials through the summer.”

EU turns green, while Asian LNG players look for options in Europe

The EU has pledged to become climate-neutral by 2050. To bring this target into range, the Commission will outline a pathway to decrease the EU’s emissions in 2030 by at least 50% and towards 55% below 1990 levels (the current target is for 40%). Plans to introduce a ‘Carbon Border Adjustment Mechanism’ – to capture carbon costs associated with imports – features in the European Green Deal. Analysts warn this could have a significant impact for gas and LNG exporters.

“Price remains king. However, we will see a significant ramp-up in buyers and investors focused on the green credentials of companies operating along the gas supply chain,” Mr. Douglas commented. “How companies are positioned on carbon intensity and, especially, how they are measuring and tackling methane emissions will become a more central feature for gas supply in 2020.

Still, access to Europe’s liquid gas markets will “remain attractive for LNG portfolio players,” analysts stressed, as particularly “Asian utilities looking for optionality in the Atlantic basin.”

European utility players heading for LNG exits

Striving to adapt to EU policies for a low-carbon future, European utilities are investing in renewables and embrace power grids as stable, regulated infrastructure. Many are taking divergent approaches in how they position themselves across the gas value chain.

“Indeed, PGNiG will become the sole European utility with a material upstream position,” Douglas said, “given that Centrica and SSE have reaffirmed their intention to exit upstream E&P by the end of 2020.”

Shifts across the gas value chain have extended into LNG. Engie sold its business to Total in 2017 to focus on renewables and distributed energy solutions. And in June 2019, Iberdrola sold its LNG portfolio to Pavilion Energy to re-position itself towards low-carbon investments and regulated activities.

“The fundamentals provide compelling evidence for growth in European LNG imports – our latest long-term outlook forecasts more than a doubling by 2030 vs. 2018 levels,” he added. “But while we expect utilities such as Uniper and RWE to continue building their LNG exposure, some will struggle to manage long-term volume risk against the backdrop of decarbonisation. Consequently, we expect to see another European player exit the LNG business in 2020.

EV batteries are typically designed to last over 300,000 miles, and once disused by cars they still have a capacity of up to 70%, according to Nissan and EFD. This may not be enough for fast-accelerating cars, but is certainly sufficient for energy storage.

Second-life battery project often incorporate manufacturers of electric vehicles. In October, EDF Energy and Nissan embarked on a project that combines used EV batteries with demand response. Wärtsilä and Hyundai Motor joined forces already back in 2018 to develop second-life EV batteries in Germany, with Hyundai estimating there will be 29 GW of second-life EV batteries available by 2025.

The latest research by Cummins and UC San Diego is investigating the performance of stationary energy storage - made from second-life EV batteries - for embedded grid storage. University researchers will perform tests and develop an outdoor second-life demonstration system comprised of Cummins battery modules.

The collaboration will give Cummin access to valuable data on the aging behaviors of its battery modules. It can test the grid-integration of for second-life batteries, and validate the performance stationary energy storage for grid balancing proposes.

Electrification for deemed crucial for decarbonizing transport and other industries, if implemented in a sustainable way. “One piece of the puzzle that requires additional research is the second-life of batteries, and Cummins now has a highly-skilled and capable partner in UC San Diego as we move towards the development of reuse solutions." said Julie Furber, vice president electrified power at Cummins.

“Cummins is the nexus between the transportation and stationary energy storage sectors,” said Mike Ferry, Director of Energy Storage and Systems at the Center for Energy Research, University of California San Diego. “Battery module design is a crucial aspect to making second-life more feasible and their experience will be invaluable as we continue to develop solutions. Given their reputation, global footprint, and all they’ve accomplished in the last century, it’s a real privilege to partner with them on this project.”

Founded in 2018, Cummins’ electrified power business designs and manufactures fully electric and hybrid powertrain systems along with components and subsystems help commercial markets adopt electrification.

INNIO and Kraftanlagen München have designed, built and put into operation a gas engine-based combined heat and power (CHP) plants on the eastern shore of the Kieler Förde inlet.  The new gas-fuelled CHP partly replaces Stadtwerke Kiel’s 323 MW coal-fired power station. It consists of four units with five blocks each, allowing it to be “operable in slices”.

Largest investment of Stadtwerke Kiel

This construction was the largest investment in the history of Stadtwerke Kiel. “It challenged us all and required a lot of strength, time and energy,” said Frank Meier, CEO of Stadtwerke Kiel. “Now the energy supply of the future is a reality in Kiel, and we look with a lot of pride at our coastal power plant.”

Together with Kraftanlagen München GmbH (KAM), Austria-based INNIO has engineered and implemented Stadtwerke Kiels coastal power plant. INNIO provided the gas engines and engineering expertise, while KAM acted as general contractor responsible for EPC and commissioning the turnkey power plant, including the auxiliary buildings and integrating the heat storage and electrode boiler.

During the CHP’s successful completion of a 20-day trial run of the power plant in late November, the 20 Jenbacher gas engines exceeded 92% overall efficiency. As compared to the previous coal-fired power plant, decommissioned in March 2019, it emits over 70% less carbon dioxide.

Gas engines help balance wind power

Wind-generated electricity makes up a high proportion in the northern German power grid, hence, Stadtwerke Kiel resorted to building a flexible gas-fuelled CHP to effectively balance supply and demand. Fast-start capability allows the CHP to swiftly feed full power into grid, if and when needed, as J920 FleXtra gas engines can achieve full capacity in less than five minutes.

“With Germany’s plans to shutter all coal plants and rely primarily on renewable energy, our Jenbacher J920 gas engines will help balance the Kiel grid,” commented Carlos Lange, president and CEO of INNIO.

“As renewable energy usage will continue to grow across Germany, INNIO will continue to make significant investments in research and development [notably for] hydrogen and hydrogen carrier gases-to help build out 100% carbon neutral and carbon free power plants.”

In the face of a massive renewable energy build-out, more batteries will be needed to balance the grid. But stabilizing the grid will not be possible without flexible gas back-up.

“Even if you oversize the amount of [renewables] generation you need considerably, you would still need a battery so huge it would be unfeasible. You can’t account for the days when, in the middle of winter, the wind doesn’t blow for a week,” said Statera’s managing director Tom Vernon

“A battery that is load shifting for a month at a time is only doing three to four cycles per year so it would have to be unfeasibly large and very cheap,” he explained, “and we are a long, long way from that.”

One of Statera’s latest flagship project, the 49.99 MW battery storage project at Stocking Pelham, UK (pictured), was completed in under six months. The site comprises seven E-houses, 27 inverters, 12km of cable and 150,000 lithium-ion battery cells and is connected to a nearby 400kV substation via a 132kV grid connection.

Statera and Statkraft co-develop mega-VPP in the UK

The Norwegian energy giant Statkraft and Britain’s flexible grid specialist Statera are currently working on co-developing a 1 GW virtual power plant (VPP) in the UK, based on a 15-year strategic partnership. Consisting of reciprocating gas and energy storage, the VPP will match demand with supply from various energy sources “within seconds.”

Statera, backed by InfraRed Capital Partners, sees the deal as a safety net to develop, build, own and operate flexible gas generation and energy storage assets. Under the deal, Statera will provide one of the UK’s largest battery facilities to store excess renewable energy. It will also deliver gas reciprocating engines to generate electricity at times of under-production or peak demand.

As soon as new assets come online, they will be integrated into Statkraft’s VPP and advanced trading platform. The hybrid units – energy storage and recip engines – will complement Statkraft’s 3.8 GW renewable generation portfolio in Britain by greatly enhancing its flexibility. Ultimately, the partnership is meant to bring Statkraft’s VPP capacity to 2 GW.

To that end, Marubeni and the Abu Dhabi Department of Energy signed a Memorandum of Understanding (MoU) to look at efficient use of water and electricity, as well as whether hydrogen production from wind and solar energy is technically and commercially viable. The Abu Dhabi Department of Energy (DoE), established in February 2018, seeks to future-proof the Emirate’s energy sector to enables economic growth, energy security and sustainable development.  

Solar power supply is dependent on weather conditions; hence hydrogen can serve as temporary energy to provide a stable supply of electricity. Hydrogen is also an effective energy in reducing global warming, as it can be efficiently utilized without emitting carbon dioxide when combusted.

Hence, Marubeni is striving to create a hydrogen supply chain in sun-soaked UAE. Hereby, local UAE partners on the ground and Marubeni’s technical experts will research, develop, and share their knowledge in the areas of renewable energy, hydrogen production, supply and distribution.

Marubeni, a leading developer and operator of international Independent (Water and) Power Projects (IPPs), partly owns and operates five projects in the United Arab Emirates, including the Sweihan PV Solar IPP, which has an installation capacity of 1,177MW.

Consumers are mandated to pay the EEG surcharge with their electricity bill, and in 2019 the levy made up a staggering 21 percent of the power price paid by the average household. “Out of a 100-euro electricity bill, 53 euros are state-induced,” the German Association of Energy and Water Industries (BDEW) criticized.

The EEG levy had been introduced to support Germany’s Energiewende policy. It supports wind, solar, biomass and hydro power installations will rise by about 5 percent to 6.756 cents per kilowatt hour (ct/kWh) in 2020, up from 6.405 ct/kWh in the previous year. The latest rise comes after two years of decrease of the surcharge.

Proceeds from CO2 price to help lower EEG surcharge

Going forward, revenues from Germany’s planned CO2 price in transport and buildings will be used to lower the levy by 0.25 ct/kWh in 2021, 0.5 ct/kWh in 2022 and 0.625 ct/kWh in 2023.

Seeking to ease the burden on consumers, the German government had pledged to reduce the surplus on the EEG account, which fell by more than 50 percent over the course of the year to around two billion Euros. Already, German electricity users are paying less for renewable energy. Power grid operators consequently experienced a 7 percent drop in annual levy revenues in 2019 to 22.8 billion Euros

Still, the EEG surcharge is set to rise by about five percent to 6.756 cents per kilowatt hour (ct/kWh) in 2020. This could be its last increase as the government has promised to help lower the surcharge from 2021 using money earned through the new CO2 price in the buildings and transport sector.

“An economy minister cannot be happy about a rising EEG surcharge,” Peter Altmaier said at the time. However, the reforms of German renewables support away from set feed-in tariffs to auctions “have made expansion of renewable energy much cheaper.”

‘Power of Siberia’ is a 3,000 kilometer pipeline link, running from east Siberia to the Blagoveshchensk on the Chinese border. The pipeline launch on December 2 crowns years of difficult construction work and tough commercial negotiations over the price of gas supplies.

Though the pricing formula is kept confidential, it is known to be linked oil prices. The base price in the formula was set at about $360 per thousand cubic meters, Russian officials disclosed, noting this was similar to the level of Gazprom’s supply contracts to Germany.

PetroChina said the price of Russian gas supplied via Power of Siberia is competitive with deliveries from Central Asia, notably from Turkmenistan.

Talks about a Far Eastern route

Negotiations are already being held with CNPC and the Chinese government about the possibility to boost Russian supplies through new projects – Power of Siberia 2 – and through the Far Eastern route.

Shortly after the launch, Gazprom noted that Chinese gas demand surged some 10 percent and considerably exceeded 300 billion cubic meters (Bcm) in 2019. “This is why we are discussing with our Chinese partners the possibility of supplies via other pipeline routes,” Gazprom chairman Alexey Miller told shareholders.

“If new projects are implemented by 2035, the share of Gazprom's supplies could rise to 13% in consumption and to 25% in gas imports, and our company may become the largest supplier on the Chinese market," he outlined.

Russian gas competes with spot LNG

Gazprom’s strategic turn to China - the world’s fastest growing gas market - helps the Russian state-controlled energy major to reduce dependence on its traditional European buyers. Deliveries through the ‘Power of Siberia’ gas pipeline are meant to be cheaper for Chinese buyers than spot LNG cargoes.

The volumes of Russian gas to be exported to China are coming from the Chayandinskoye field in Yakutia and the Irkutsk-based Kovyktinskoye field, Gazprom said, noting these supplies will feed to the China link from around mid-2023.

Meetings with state-owned Yacimientos Petroleiferos Fiscales (YPF) led to a promise by President Fernandez to push for upstream-friendly regulation. “I will send a bill that will establish a regulatory framework to allow for the exploitation of conventional and unconventional hydrocarbons,” the Argentine leader vowed. To date, about 1,000 wells have been drilled in the Vaca Muerta Shale, out of which just 300 have been fracked.

Prolific gas resources at Vaca Muerta, spanning some 30,000 square kilometers, have attracted the likes of ExxonMobil and Chevron, Qatar Petroleum, Total and Equinor.

Striving to boost LNG exports

State-owned YPF last year commenced small-scale LNG production and export via a floating liquefaction facility, named ‘Tango FLNG’. Shortly after exports went into full swing, proposals were made for a pre-FEED design for a 5 mtpa onshore liquefaction plant, with the option to expand capacity to 10 mtpa.

Upstream costs, however, still need to come down significantly if Argentine LNG wants to become competitive on global markets, notably compared with LNG cargoes from the U.S. Gulf Coast.

Through productivity has improved as a result of increased fracking stages and longer laterals, production costs at Vaca Muerta shale are still deemed “too high for international markets. YPF in 2019 reported declining costs of $3.72 per million British thermal units, down from $4.65 per MMBtu a year earlier.

Investors sitting on their hands

Fresh investment is vital to overcome bottlenecks in gas transportation, as existing pipelines are running at limit. The government in late July 2019 launched the tender for a $2 billion pipeline from Neuquén province and the Vaca Muerta Shale. Now, it is a question of providing financial and tax incentives to attract international oil majors willing to invest in Argentine midstream gas assets.

The Argentine Minister of Energy has not clarified his policies when it comes to royalties for upstream companies, or fuel subsidies. Hence, some international investors have hence adopted a “wait-and-see” attitude.

Others are rethinking their strategy: Schlumberger, the world’s largest oil services and equipment manufacturer, is trying to sell its investments in Argentina. Shell and ExxonMobil executives openly spoke of the need for stable government policies, greater spending on infrastructure, and other incentives.

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.

The aim is to leverage the region’s abundant wind and solar resources and reduce its reliance on fossil fuels, especially as grid systems develop and economies grow.

In ASEAN, Wärtsilä Energy Business has a strong track record of delivering more than 35 EPC projects totalling 1,500 MW in the South East Asia region. The company’s latest 100 MW/100 MWh energy storage project will help provide some of the reliability necessary to support the region’s transition to renewable energy sources.

GEMS, an energy management software platform, can react near-instantly to smooth the integration of renewables, enabling the grid to emerge more stable and responsive. Grid support applications of GEMS include voltage and frequency regulation, reactive power support, spinning reserve, ramp rate optimisation, renewable energy output smoothing and energy arbitrage.

Wärtsilä underlined that GEMS will make it possible for grid operators to rely on renewables as baseload power.

State-owned banks, forced to write-off loans to operators of stranded gas power plants, are weighing heavy on the Indian public purse. A parliamentary panel urged the Government to take action, saying that “since this stranded gas-based capacity involves a significant amount of public money, it cannot be allowed to become junk.”

Prioritizing KG D6 gas for power gen

“Since these gas-based power plants were set up on the basis of the government’s assurance regarding supply of gas, it becomes incumbent upon the government to help them come out of stress,” it stressed, urging the Government to priorities gas supplies to power plants.

Dwindling domestic gas supply from the Krishna Godavari Dhirubhai 6 (KG D6) block and comparatively high prices for LNG imports have led to affordability issues. Cheaper fuel prices for other power sources—coal, solar, wind, and hydro—mean that the gas-fired plants can’t pass on these costs without losing their competitiveness.

Mixed feelings over price deregulation

Deregulating fuel prices has for long been touted as a panacea for India’s domestic gas shortages. However, the parliamentary panel has advised against it:

“The committee is of the opinion that because of shortage in availability of gas and demand being much higher than supply, the free-market pricing will result in exorbitant prices,” the report reads.

Domestically produced gas is currently priced according to a formula that is criticized by producers such as BP. Analysts at the Saudi-based Kapsarc institute have suggested to either index Indian upstream gas prices with international markets of using opportunity costs linked to LNG import parities or weighted average of fuel oil and coal.

‘Postage stamp’ transportation pricing could introduce simplicity, and substantial investment in gas transportation infrastructure would be required to realize President Modi’s vision of a ‘gas-based economy’.

Electrification requires massive new-builds

Striving to bring electricity to all Indian households, the Government is expected to add between 600 GW to 1,200 GW of additional new power generation capacity before 2050. To meet its climate goals and reduce air pollution, much of the new-build capacity should be based on natural gas or renewable energies.

India’s installed generating capacity totals 357.875 GW, with over 79.8% of that total generated from fossil fuels. Coal accounts for the lion’s share of India’s power mix, contributing 200,749.5 MW, or 56.1%, the share of natural gas has fallen to 24,937.22 MW, or 7.0%.

Renewables are gaining ground with large hydro power installation at 45,399.22 MW, or 12.7% market share, followed by wind power at 36,089.12 MW, or 10.1%, and solar power at 29,409.25 MW, or 8.2%.

Construction on the PMUG pipeline began in May 2019, and has been dragging on ever since. In addition, smaller gas pipeline projects such as the Cochin-Mangaluru-Bengaluru connector have suffered from severe delay due to extreme weather and engineering problems, which suggests the much larger PMUG project will not be completed on time.

India’s annual gas demand has been growing by an average of about 4 percent since 2015, driven by particularly strong growth in the power sector and by demand for feedstock by heavy and petrochemical industries. However, gas supply is much easier to come by on India’s west coast, notably four of the five Indian LNG terminals – Dahej, Hazira, Dabhol and Cochin. Meanwhile, the capacity of the fifth – Ennore LNG in Tamil Nadu state – is being underutilized.

Launch of new e-RLNG scheme

Eager to promote clean energies, the Indian government is about to give way to utilities’ demands and allow power plants running on RLNG to sell electricity into the higher-priced spot market, without having to adhere to their power purchase agreements.

The proposal, launched by Indian power producers, calls for a gas auction mechanism that will pool any domestically produced natural gas with imported LNG and then offer the fuel at a subsidized tariff. Analysts say the proposed e-RLNG scheme will require fewer subsidies than in past years due to the fall in global oil prices.

The aim is to revive some 25,000 MW, or 25 GW, of stranded gas-fired power generation capacity across the country, and help alleviate a looming energy crisis as the summer season approaches. Much of the 25 GW stranded capacity is lying idle given that total gas supply is hardly reaches 40 million standard cubic feet per day – a far cry from the plant’s combined gas requirements of 117 mmscm/d.

The new e-RLNG scheme has been proposed to initially run for 2 years, based on financial support from the India’s Power System Development Fund. The RLNG price is currently prices around $8/MMBtu, and in previous e-RLNG bidding rounds the government subsidized the electricity tariff at Rs 5.50 per unit. Observers expect, however, the government will this year keep the subsidies lower at Rs 4.24 per unit.

Utilities seek to stick to coal power

In contrast to the government’s pledge to gas generation and green energy, Adani Power and NTPC, two of India’s largest power producers, have pleaded to extend the deadlines of retrofitting coal power stations by two to three years. High costs for retrofits and India’s continued reliance on cheap thermal coal now needs to be weighed up against rampant air pollution.

Privately-held Adani Power, for once, calls for an extension of stricter emission limits at two of its large-scale power stations until March 2023. The two units were purchased from the GMR Group last year, and the Adani claims there would still be ownership issues to be resolved before looking into a plant retrofit. State-owned NTPC, India’s largest utility, has sought to push back the deadline by up to two years at its Bongaigaon eastern Indian plant.

Coal is by far India’s dominant energy source, and the power sector accounts for two-thirds of India's coal consumption. Now policy makers and regulators in the second largest economy in the Asia-Pacific region needs to decide on whether they want to stick to their green energy targets, or keep watering them down.

Beijing Gas new LNG import project in the Nangang district of Tianjin is backed by a $500 million loan from the Asian Infrastructure Investment Bank (AIIB). Going forward, Beijing Gas plans to gradually expand the Tianjin LNG terminal which will add to Sinopec’s existing Tianjin North import terminal and CNOOC’s floating storage and regas unit (FSRU).

Watering down Coal-to-Gas policy

Greater availability of attractively-priced natural gas, both LNG and pipeline gas, is vital to encourage power producers to turn away from burning thermal coal. The ‘Blue Skies’ policy, imposed in 2018, expands pollution controls to 82 cities across northern and eastern China. The regions that fall under the government's “Blue Sky” plan are now home to 37% of population contributing to 41% of China's GDP.

However, Beijing policy makers in winter 2019/20 slowed their green energy push due to a weakening economy and competition from cheaper coal. Still, gas demand is forecast to rise nearly 8 percent, reaching 145 billion to 150 billion cubic meters (bcm), according to Sinopec.

"Based on what is practical, we should use electricity where electricity is available, gas where gas is sufficient, and coal where coal supply is ample," Premier Li Keqiang recently commented on energy security this winter.

LNG can help reduce reliance on coal. But coal is still king in China’s energy mix as the dominance of this highly emissions-intensive fuel has increased in China in 2019, reaching 48.1 percent of global coal consumption. The People’s Republic remains the world's largest coal producer, consumer and importer.

On the supply side, the U.S. Energy Information Administration’s (EIA) projects that worldwide electricity generation will grow by 1.8% per year to reach nearly 45 trillion kilowatthours (kWh) by 2050, almost 20 trillion kWh more than the 2018 level. Growth in electricity demand in non-OECD regions far is seen outpace those in OECD regions.

Renewables competitive with fossil generation

New-build wind and solar PV installations are becoming economically competitive with fossil technologies worldwide, EIA analysts pointed out. “But without policy incentives, growth in generation from renewable sources is limited in regions with slow demand growth,” they warned.

Europe’s electricity demand is projected to grow at about 1 percent per year through 2050; however, a regional CO2-cap will lead to lower fossil-fired generation and rising renewables generation to meet demand.

By 2050, the share of wind and solar generation in Europe is seen increase from 20 percent to almost 50 percent. Fossil-fired plants will fall from 37 percent to just 18 percent, with coal power units likely to account for only 5 percent.

Green energy takes hold in India

India has the most rapid electricity demand growth, around 4.6% per year, in the IEO2019 Reference case. Although India has developed target levels for solar and wind capacity, it does not have an aggressive emissions reduction policy in place, so EIA projects coal-fired generation growth in addition to growth in solar and wind generation.

Solar, wind, and coal combined will account for 90% of India's power gen mix in 2050. The contribution of wind and solar is seen rising from less than 10% in 2018, to more than 50% in 2050. In contrast, the share of coal power in India's electricity output falls from about 75% to less than 40% over the same period.

Profit margins are squeezed amid rising fuel costs, but also because Turkish authorities limited electricity price rises in a bid to rein in inflation. Several large utilities were consequently forced to restructure foreign currency loans, agreed earlier to build power plants or retrofit and expand operations.

Several power producers across Turkey consequently consider mothballing or closing down some of their gas-fired power units, as competition with cheaper thermal coal units intensifies.

Şanlıurfa CCGT barely dispatched

The Şanlıurfa combined-cycle power unit had been running at merely 15 percent of its capacity in the first nine months of last year, Aksa Energji noted. This means it contributed just 2 percent of Turkey’s total power output from January to September, and just 0.5 percent in the third quarter.

The Şanlıurfa combined-cycle gas turbine (CCGT) power plant, built in 2011, initially had an installed capacity of 120 MW. A Dresser-Rand steam turbine with 11.5 MW capacity added later, and a further capacity increase was undertaken in 2015 which brought the CCGT’s overall capacity to 147 MW. The site also includes 12 Wärtsilä 20V34SG gas engines, each with a capacity of 9.7 MW, as part of a back-up power unit.

Enka recently halted operation of two gas-fired power station, including the large Gebze plant in western Turkey, after power purchase agreement with state-run EÜAS ended. Aksa in November 2018 closed down 115 MW plant in Manisa in western Turkey, citing pricing problems.

When designing a new 3D component, researchers normally consider how well its material composition responds to heat and stresses, or how its design impacts airflow, or aerodynamic performance. Validating of a complex part can take between 2 and 5 years.

Striving to speed up things, researchers from ORNL and GE believe they can cut in half the timeline to create, test and validate new 3D part designs. “Using multi-physics enabled tools and AI, we think we can beat the timeline for some traditional manufacturing processes by automating the entire process, said Brent Brunell, leader of GE Research’s Additive efforts.

Surrogate models

Optimization of structural characteristics has already been automated but has not extended to a part’s thermal and fluid properties. On this project, researchers from GE and PARC will use AI to automatically generate surrogate models from additive producibility data and seamlessly integrate it with multi-physics design optimization techniques.

The Summit supercomputer at ORNL will create these AI-based surrogates to analyze additively manufactured components and generate data necessary for training and evaluating the new models. Built using machine learning, surrogate models can guide the optimization models in feasible regions of very high dimensional design spaces.

"This is the type of project that leverages the unique capabilities at ORNL – experimental and computational facilities – as well as expertise in computational science and additive manufacturing," said John Turner, Computational Engineering Program Director at ORNL.

The program will culminate in the demonstration of a defect-free, high-performance additively manufactured multi-functional design capable of withstanding high temperatures and stresses with improved performance vs. conventional casting.

Tougher emission rules under the EU Large Plant Combustion Directive will further deter utilities from burning coal. Nine out of the existing 15 coal-fired power units in Spain could “possibly not be in operation” by 2021, if utilities decided to avoid the investment required to comply with tougher EU rules, the government reckons.

Gas-fired generation is also seen to fall slightly in Spain’s revised 2021-2030 energy plan, down from 27.2 GW currently to levels around 26.6 GW in 2030. In contrast, combined heat and power (CHP) capacity could rise 0.7 GW over the same period to reach 3.7 GW.

Massive renewable build-out

Across most of the Iberian Peninsula, the Spanish government envisages a massive build-out of wind and especially solar capacity, having raised its solar capacity target by 2.3 GW to 39.2 GW. By the end of the decade, Spain’s combined wind and solar capacity is meant reach 96.8 GW, making up nearly two thirds of the country’s installed capacity of 160.8 MW.

The revised energy plan is “very final,” the Spanish energy ministry noted, although it still needs approval by the European Commission.

Growth in gas demand for export started to exceed growth in gas-burn for power generation in 2019, as the U.S. shale gas revolution continues to unfold. Deliveries of shale gas production via national U.S. pipelines to liquefaction and export facilities accounted for 12 percent of gas production.

Imports from Canada, meanwhile, declined over the past four years as domestic U.S. gas supplies from Appalachia into the Midwestern states have displaced some Canadian gas pipeline imports. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.

Exports of U.S. pipeline gas to Mexico, meanwhile, keep growing amid expanded cross-border pipeline capacity which averaged 5.1 Bcf/d from January through October 2019. The increase in export was primarily caused by the newly commissioned Sur de Texas–Tuxpan pipeline the southern Mexican state of Veracruz.

Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020: Pipelines in Central and Southwest Mexico (1.2 Bcf/d at La Laguna–Aguascalientes and 0.9 Bcf/d at Villa de Reyes–Aguascalientes–Guadalajara); and pipelines in Western Mexico (0.5 Bcf/d at Samalayuca–Sásabe).

U.S. LNG exports averaged 5 Bcf/d over the past year, 2 Bcf/d more than previously, due to several new facilities that placed their first trains in service. In 2020, several new liquefaction units (referred to as trains) are scheduled to be placed in service:  Trains 2 and 3 at Cameron LNG in Louisiana, Train 3 at Freeport LNG in Texas, and Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia.

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d at baseload, and 10.8 Bcf/d at peak capacity. Analyst at the EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.

In fact, most growth in new-build capacity is seen coming from new renewable installations. Regulatory safeguard duties on solar PV modules will come to an end in July 2020, spurring greater investment in new solar and hybrid gas and solar projects.

Nuclear power is also on the rise, as India’s atomic power plant operator NPCIL is expanding capacity at the pressurized heavy water reactor (PHWR) in Kakrapar Gujarat, India. The operator is building four 700-MW PHWRs, two at Kakrapar nuclear power station in Gujarat and two at a similar facility in Rajasthan.

Gas upstream efforts show results

Licensing reforms in India may soon translate into successful bidding rounds, analysts say. Hence, natural gas production is expected to rise by 9 percent, underpinned by deepwater projects operated by Reliance (KG-D6) and ONGC (KG-DW-98/2).

Both projects are on track for a 2020 start-up, according to Wood Mackenzie projections, although only one well is likely to be onstream in ONGC’s field.

LNG demand hinges on infrastructure build-out

India’s coal-to-gas switching drive is reflected in its LNG imports. Demand for regasified LNG grew 2 percent year-on-year last year largely due to a slowdown in Q1-2019, according to Wood Mackenzie figure. Overall, the use of RLNG was driven by the fertiliser (+9%) and city gas (+7%) sectors, which offset decreased consumption in the industrial sector (-8%).

Total gas demand growth is expected rebound over the course of this year, supported by the fertiliser and city gas sectors.

In 2020, additional regas capacity is seen vital for India to fully benefit from the low spot LNG prices. The commissioning of two new terminals, Mundra and Jaigarh, slipped into 2020. The other main addition to capacity will be the expansion of Dahej by 2.5 mmtpa, which should be completed this year.

Coal production falls

Domestic production of coal as well as the use of thermal coal for power generation keeps falling in India, not least due to weather issues. “Higher rainfalls not only resulted in lower coal generation but also hindered domestic coal production. We expect domestic production to improve in 2020,” said WoodMac principal analyst Pralabh Bhargava.

Stocks of domestic coals are piling up across India, amid slowing use of the fuel for power generation and cement and steel production. “If the economy doesn't pick up in early 2020, and power, cement and steel demand remain slow, we see a downside risk to our coal imports forecast,” he said. “Currently, we are forecasting 181 million tons of thermal coal and 65 Mt of coking coal imports in 2020.”