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September 2021 • Volume 14 • No 7 • Published monthly • ISSN 1757-7365

THE ENERGY INDUSTRY TIMES is published by Man in Black Media • www.mibmedia.com • Editor-in-Chief: Junior Isles • For all enquiries email: enquiries@teitimes.com

Special Supplement

Decarbonisation of

two cities

TEI Times hears why

industrial gas turbines will

be crucial in complementing

renewables-plus-storage in an

optimised system.

With just two months to COP26, Asia

energy expert and author, Joseph Jacobelli,

compares the decarbonisation efforts of

Hong Kong and Singapore. Page 14

News In Brief

IPCC report is stark warning

in run-up to climate talks

The Intergovernmental Panel on

Climate Change’s (IPCC) recent

assessment report has been hailed

as a stark reminder of the need for a

successful outcome at the upcoming

COP26 climate summit.

Page 2

China and India unveil big

plans for hydrogen

China and India have both set out

bold strategies for the development

of hydrogen production.

Page 5

Germany under pressure to

grow renewables faster

Germany has added 240 new

onshore wind turbines with a

potential output of 971 MW

during the rst six months but that

deployment is not fast enough to

meet its renewable targets.

Page 7

Industry Perspective: A

model for nuclear new build

in Europe?

Hanhikivi 1 in Finland could offer

some clues on how nuclear plants,

including small modular reactors,

could be successfully developed in

the future.

Page 13

Technology Focus: An

imaginative approach to

long duration storage

US-based 247Solar has developed

an innovative thermal battery that

looks set to facilitate around-the-

clock wind and solar energy.

Page 15

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Conscious of its role to show leadership on climate action, the UK government has set out its

Hydrogen Strategy. But the announcement has met a mixed reaction. Junior Isles

THE ENERGY INDUSTRY

TIMES

Final Word

Budding rock stars need to

wear the right colour, says

Junior Isles.

Page 16

The UK government’s recently pub-

lished hydrogen strategy has come

under scrutiny as the country prepares

to host the crucial COP26 climate sum-

mit later this year.

As part of its ‘Ten Point Plan’ for a

green revolution announced earlier

this year, the government has outlined

how it will cooperate with industry to

achieve 5 GW of low carbon hydro-

gen production capacity by 2030.

Government analysis estimates that

up to 30 per cent of the UK’s energy

consumption could be hydrogen-

based by 2050, making it a key tech-

nology in achieving net zero emis-

sions by 2050 and meeting the

country’s target of cutting emissions

by 78 per cent by 2035.

It could also play an important role

in rebuilding an economy driven by

clean energy technology.

According to the government, the

UK’s rst-ever Hydrogen Strategy

will unlock over £4 billion ($5.5 bil-

lion) in investment and create thou-

sands of jobs in the move to establish

a low carbon hydrogen sector by

2030. It said a thriving, UK-wide hy-

drogen economy could be worth over

£900 million and create over 9000

high-quality jobs, which may rise to

100 000 jobs and be worth up to £13

billion by 2050.

“With the potential to provide a

third of the UK’s energy in the future,

our strategy positions the UK as rst

in the global race to ramp up hydrogen

technology and seize the thousands of

jobs and private investment that come

with it,” said Business and Energy

Secretary Kwasi Kwarteng.

The government wants to mimic its

success with offshore wind, where

early government action and Con-

tracts for Difference (CfD) support

have helped secure the country a lead-

ing position. It said it is publishing a

consultation on a preferred hydrogen

business model, shaped on a similar

premise to the offshore wind CfDs.

A consultation is also being initiated

on the design of the £240 million Net

Zero Hydrogen Fund, intended to

back new plants for low-carbon hy-

drogen production in the UK.

The government says it will take a

“twin track” approach, developing

both blue and green hydrogen simul-

taneously. Green hydrogen is pro-

duced via electrolysis, using electric-

ity from renewable electricity and is

therefore zero emissions. Blue hy-

drogen is generated from steam

methane reformation combined with

carbon capture and storage (CCS). It

has lower emissions than current pro-

duction, but is not zero emissions.

The decision to pursue blue hydro-

gen alongside green has drawn criti-

cism from some quarters.

Dr Doug Parr, Chief Scientist for

Greenpeace UK, said: “Hydrogen

produced from renewable energy is

genuinely low carbon, and genuinely

useful in some areas of the economy

where electrication is difcult. But

producing large quantities of hydro-

gen from fossil gas locks us into cost-

ly infrastructure that is expensive and

may be higher carbon than just burn-

ing the gas. So the emphasis put on

that part of the government’s plan

looks like a bad idea both environ-

mentally and economically.”

A recent study conducted by Cornell

University and Stanford University

found that blue hydrogen could be 20

per cent worse for the climate than

burning natural gas. The study, pub-

Continued on Page 2

UK Hydrogen Strategy

questioned ahead of COP26

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THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Junior Isles

The Intergovernmental Panel on Cli-

mate Change’s (IPCC) recent assess-

ment report has been cited as a stark

reminder of the need for a successful

outcome at the upcoming COP26 cli-

mate summit scheduled for November

in Glasgow, UK.

Britain’s Prime Minister Boris John-

son called the IPCC Report “sobering

reading” and a “wake-up call”, while

COP26 President Alok Sharma said it

“shows all too clearly… the deciency

of our response [to the climate crisis]

to date”.

The Working Group I report is the

rst instalment of the IPCC’s Sixth As-

sessment Report (AR6), which will be

completed in 2022. Prepared by 234

scientists from 66 countries, it high-

lights that human inuence has warmed

the climate at a rate that is unprecedent-

ed in at least the last 2000 years. It also

states that many changes due to past

and future greenhouse gas emissions

are irreversible over hundreds to thou-

sands of years, especially changes in

the ocean, ice sheets and global sea

level.

The report shows that emissions of

greenhouse gases from human ac-

tivities are responsible for approxi-

mately 1.1°C of warming since 1850-

1900, and nds that averaged over the

next 20 years, global temperature is

expected to reach or exceed 1.5°C of

warming. This assessment is based on

improved observational datasets to

assess historical warming, as well as

progress in scientic understanding

of the response of the climate system

to human-caused greenhouse gas

emissions.

The IPCC projects that in the coming

decades, climate changes will increase

in all regions. For 1.5°C of global

warming, there will be increasing heat

waves, longer warm seasons and short-

er cold seasons. At 2°C of global warm-

ing, heat extremes would more often

reach critical tolerance thresholds for

agriculture and health, the report

shows.

The report has huge implications for

policymakers in terms of tackling

greenhouse gas emissions and adapt-

ing to the levels of climate change the

world is already locked into. To keep

the 1.5°C target alive and adapt to a

changing climate, governments around

the world must provide unequivocally

clear policy signals to signicantly ac-

celerate the investment needed for a

zero carbon future.

Nick Molho, Executive Director at

the Aldersgate Group, said: “The UK

government has a critical role to play

in the coming months. On the global

stage, it needs to gather maximum mo-

mentum to bring emission reduction

pledges from all key emitting nations

in line with the 1.5°C target and look

to underpin this with tangible global

collaboration and initiatives in areas

where cutting emissions is particularly

complex.”

Christiana Figueres Founding Partner,

Global Optimism & former Executive

Secretary, UN Climate Change Con-

vention, said the report is yet another

reminder of the need to accelerate

global efforts to “ditch fossil fuels”

and shift to a cleaner, greener growth

model.

“We have a plan – it’s called the

Paris Agreement,” she said. “Every-

thing we need to avoid the exponential

impacts of climate change is doable.

But it depends on solutions moving

exponentially faster than impacts, and

getting on track to halving global emis-

sions by 2030. COP26 will be the mo-

ment of truth.”

COP26 presents a clear opportunity

to implement credible policies in areas

that will cut emissions quickly but

countries are failing to deliver on the

ambitions agreed at the COP meeting

in Paris in 2015.

At the start of August, it was revealed

that only just over half of countries

signed up to the Paris Agreement had

submitted their nationally determined

contributions (NDCs) before the

deadline.

By the cut-off date, the UNFCCC

revealed that it received new or up-

dated NDCs from 110 Parties. This

means that only 58 per cent of the Par-

ties have met the cut-off date.

A landmark report, aimed at inform-

ing policy and business on the task of

reaching net zero, has revealed the

huge task of achieving net zero by

2050. Providing a globally applicable

framework, with the US utilised as the

core case study, the report says that

without an unprecedented restructure

to energy project delivery, the world

may not make it even halfway to net

zero by mid-century.

Produced by Worley, a global pro-

vider of engineering, procurement, and

construction services to the energy,

chemicals and resources industries, in

collaboration with Princeton Univer-

sity’s Andlinger Center for Energy and

the Environment, the study uses path-

ways developed in the Net-Zero Amer-

ica study by Princeton in 2020.

This further examination says the US

will have to drastically exceed its cur-

rent low-emissions project build rate.

Under one pathway, to reach net zero,

individual solar projects with an area

equivalent to 260 Tokyo Olympic sta-

diums need to be built every week from

now until 2050. In another, more than

250 large nuclear power stations will

be needed – under current processes,

one such nuclear plant can take upto

20 years to get operational.

The report explores ve key shifts in

the approach to energy infrastructure

that can deliver a transition to net zero.

Dr. Paul Ebert, Group Director En-

ergy Transition at Worley said: “We

hope our work with Princeton Univer-

sity will help to equip key players in

the industry with strategic guidance for

the path ahead, using breakthrough

thinking, and shifting the focus from

what technologies we need, to how to

get them built, working to deliver a

more sustainable world for us all.”

found that blue hydrogen could be

20 per cent worse for the climate

than burning natural gas. The study,

published in Energy Science & En-

gineering, is claimed to be the rst

in a peer-reviewed journal to layout

the lifecycle emissions intensity of

blue hydrogen

Concluding that there is “no role

for blue hydrogen” in a carbon-free

future, the authors suggested that

“blue hydrogen is best viewed as a

distraction, something that may de-

lay needed action to truly decarbon-

ize the global energy economy”.

Robert Howarth, co-author of the

study and Professor of Ecology and

Environmental Biology at Cornell

University noted: “Politicians

around the world, from the UK and

Canada to Australia and Japan, are

placing expensive bets on blue hy-

drogen as a leading solution in the

energy transition.”

Others, however, see the strategy

as a welcome development for both

the energy industry and communi-

ties alike, as it creates a road map

for future power generation from

both blue and green hydrogen.

Stuart Carter at Keystone Law,

commented: “This also plays into

the government’s model for carbon

capture and storage, which is fo-

cused on the UK’s industrial hubs

such as Teesside and Humber-

side… if the government aims to

achieve its net-zero targets, the

blue hydrogen model and the

CCUS [carbon capture usage and

storage] model will need to be

fully integrated. This may mean

that blue hydrogen solely becomes

the fuel for power generation at

industrial hubs where CCUS will

be highly developed, and leaving

carbon-free green hydrogen, to be

produced, possibly at a more re-

gional level, to be used by domes-

tic consumers for transport, heat-

ing and cooking.”

David Parkin, Project Director

from Progressive Energy and Proj-

ect Director of HyNet North West,

a project to capture and store car-

bon from industry in the North

West of England and North Wales,

said: “Industry across the UK’s

North West industrial heartland is

crying out for low carbon hydrogen

so we welcome the promise of

more support.

“With initial engineering nearly

completed on HyNet’s rst hydro-

gen production plant at Essar’s

Stanlow Manufacturing Complex,

hydrogen production will begin as

soon as 2025 and deliver up to 4

GW of low carbon hydrogen by

2030. The key now is for the govern-

ment to build momentum by pri-

oritising projects that are ready for

development today.”

Continued from Page 1

The UK’s plans for a new eet of large

nuclear power plants could be under

threat, as the government is report-

edly reconsidering China’s involve-

ment in the development of projects

amid cooling diplomatic relations and

concerns over potential security

threats.

According to the Financial Times,

the British government is exploring

ways to remove China General Nu-

clear (CGN) from the consortium

planning to build the Sizewell C nu-

clear power station in Suffolk. It said

ministers are also going cold on plans

by CGN to build a plant at Bradwell-

on-Sea in Essex using its own reactor

technology. CGN is already a minor-

ity investor in the 3.2 GW Hinkley

Point C nuclear power station, which

France’s EDF is currently building.

One nuclear industry executive told

the FT that CGN might now reassess

its involvement with Hinkley Point.

They pointed out there were four in-

terlinked agreements between CGN,

EDF and the government dating to

2015: Hinkley Point, Sizewell,

Bradwell and the pursuit of regula-

tory approval for China’s own reactor

design.

CGN is eager to get UK regulatory

approval at Bradwell for its own Hua-

long One HPR1000 reactor in order

to help market it in other countries.

The reactor design is going through

the UK’s rigorous approval process,

with a decision expected in the second

quarter of next year.

According to the Daily Telegraph, a

“cross-party” group of “China hawks”

in the House of Commons is putting

pressure on the government to impose

an “outright” ban on a Chinese state-

owned rm’s involvement in all UK

nuclear power plants.

The group – led by Tory MPs Iain

Duncan Smith and Chairman of the

Foreign Affairs Committee, Tom Tu-

gendhat – reportedly has the full back-

ing of the Inter-Parliamentary Alli-

ance on China (IPAC), which claims

to be an international body working

to “reform how democratic countries”

engage with the Asian giant.

The Daily Telegraph quoted IPAC

as warning that the UK is “danger-

ously exposed” by its “overreliance”

on Chinese investment and technol-

ogy in the “critical national infrastruc-

ture” sector.

UK Foreign Secretary Dominic

Raab observed last year that Britain

could no longer conduct “business as

usual with China”. The UK’s highest-

prole action so far has been to force

the Chinese telecoms supplier, Hua-

wei, out of Britain’s 5G network.

British ministers are now said to be

“looking for ways” to enable EDF

energy to develop the £20 billion Size-

well C project without any input from

CGN, which has a 20 per cent stake

in the project.

The Times said the government is

mulling options for funding the plant,

including buying a multi-billion

pound stake in the project or nding

new investors to replace CGN.

Tim Yeo, a former Tory energy min-

ister who chairs the New Nuclear

Watch Institute, an industry-support-

ed think-tank, said concerns about

Chinese involvement in the UK nu-

clear power sector had been over-

stated. Any disruption or interference

in its operations would close down all

export opportunities elsewhere for

CGN, he argued.

“The notion that China would arbi-

trarily close down a plant which they

had built in UK for some geopolitical

reason is absurd,” he said. “They have

nothing to gain and everything to lose

by disrupting the supply of electricity

from a nuclear plant which they had

built here.”

A spokesperson for the UK govern-

ment did not comment directly on the

claims that ministers would seek to

forge a nuclear programme without

CGN, instead only saying that “all

nuclear projects” must comply with

“robust and independent regulation”

in order to meet the UK’s “rigorous

legal, regulatory and national security

requirements, ensuring our interests

are protected”.

Headline News

UK nuclear programme could be

under threat

IPCC report is stark warning

in run-up to climate talks

Howarth says countries are

“placing expensive bets” on

blue hydrogen

n Human inuence has warmed climate at unprecedented rate

n Only just over half of countries submit climate targets

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

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ENERGY FUTURE.

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making energy systems more sustainable, resilient, safe and secure. We contribute innovative

solutions that are advancing societal progress towards a carbon-neutral energy future for all.

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THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Asia News

Syed Ali

China and India have both set out bold

strategies for the development of hy-

drogen production.

In mid-August, Beijing authorities

released a blueprint for the develop-

ment of its hydrogen energy industry

from 2021 to 2025. According to the

plan released by the Municipal Bureau

of Economy and Information Technol-

ogy, by 2025 the Beijing-Tianjin-He-

bei region will achieve a hydrogen

energy industry chain valued at more

than Yuan100 billion ($15.4 billion)

and reduce carbon emissions by 2 mil-

lion tonnes.

Before 2023, ve to eight leading

enterprises with international inu-

ence in the hydrogen energy industry

chain will be setup, and the scale of the

industrial chain in Beijing-Tianjin-

Hebei region will exceed Yuan50 bil-

lion to reduce carbon emissions by 1

million tonnes.

Ahead of 2025, 10-15 leading indus-

trial chain enterprises with interna-

tional inuence will be established, and

three to four world-class industrial

R&D and innovation platforms will be

built.

At the same time China’s Inner Mon-

golia region was given the green light

for a massive hydrogen production

plan that will utilise roughly 2.2 GW

of wind and solar power capacity. The

project envisages the installation of

1850 MW of solar photovoltaic (PV)

and 370 MW of wind farms to power

the production of 66 900 tonnes of re-

newable hydrogen annually, according

to Bloomberg, citing a report by the

Hydrogen Energy Industry Promotion

Association.

These clean energy plans, however,

came as it was revealed that state-

owned rms proposed 43 new coal-

red generators and 18 new blast fur-

naces in the rst half of 2021. If all are

approved and built, they would emit

about 150 million tonnes of carbon

dioxide per year. According to the Cen-

tre for Research on Energy and Clean

Air (CREA) China limited emissions

growth in the second quarter to a 5 per

cent increase from 2019 levels, after a

9 per cent rise in the rst quarter.

India, Asia’s other major global emit-

ter, also unveiled its plans for hydrogen

last month, as Prime Minister Narendra

Modi formally announced the formal

establishment of its National Hydro-

gen Mission.

He said the aim is to make India the

new global hub of green hydrogen,

and also its largest exporter. Last year

in October, Modi outlined a new en-

ergy map for India with seven key

drivers – one of them being the devel-

opment of emerging fuels, particu-

larly hydrogen.

Announcing the Mission in his Inde-

pendence Day speech, Modi said: “Of

every effort being made by India today

the thing that is going to help India with

a quantum leap in terms of climate is

the eld of green hydrogen… We have

to make India a global hub for Green

Hydrogen production and export…

India has to make a resolution to make

India energy independent before the

completion of 100 years of indepen-

dence and our roadmap is very clear

for the same. It should be a gas-based

economy.

“There should be a network of

CNG [compressed natural gas] and

PNG [pipeline natural gas] across the

country. There should be a target of

20 per cent ethanol blending. India is

moving ahead with a set goal. India

has also made a move towards Electric

Mobility.”

The announcement comes ahead of

COP26 in Glasgow, UK, where nations

will be under pressure to pledge more

ambitious climate action and substan-

tial nancing, especially regarding

energy requirements.

In a meeting with Union Minister of

Power and Renewable Energy, Shri

RK Singh, Alok Sharma, COP 26

President, expressed the UK’s willing-

ness to collaborate with India on green

hydrogen. Both sides discussed the

possibility of establishing a World

Bank for Green Energy, which could

realise the proposal for $100 billion in

climate nance pledged by developed

countries under the Paris Agreement.

China and India unveil big

plans for hydrogen

n China to setup 10-15 leading industrial chain enterprises by 2025

n India formally establishes National Hydrogen Mission

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THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Asia News

Syed Ali

Japan is inching forward with plans to

boost its offshore wind capacity, which

will help accelerate the country’s pro-

duction of green hydrogen.

Last month Aker Offshore Wind and

global wind and solar company, Main-

stream Renewable Power (“Main-

stream”) were together selected as the

preferred bidder to acquire an initial

50 per cent stake in Progression En-

ergy’s 800 MW oating offshore

wind project in Japan. The project is

a well-formed early-stage develop-

ment asset.

The two companies will now enter

into exclusive negotiations with Pro-

gression Energy with a view to estab-

lishing a special purpose vehicle

(“SPV”) to continue collectively de-

veloping the project.

“In 2015, Progression recognized

that oating offshore wind would be-

come a major segment of the offshore

wind industry. Since that time, Pro-

gression has originated oating proj-

ects in four markets globally,” said

Chris Swartley, CEO of Progression

Energy. “Japan has set a goal of zero

emissions by 2050 with a strong focus

on offshore wind.

Japan aims to expand offshore wind

energy capacity to 10 GW by 2030

and 30-45 GW by 2040, according to

the Ministry of Economy, Trade and

Industry (METI). Project areas for

offshore oating wind will be put to

auction for interested companies to

submit their proposals.

Projects like Progression Energy’s

will be integral to Japan’s plans to

increase the production of green

hydrogen.

In late July Nikkei Asia reported that

four Japanese companies intend to

build Japan’s largest hydrogen plant

the northern island of Hokkaido as

part of a national effort to slash carbon

dioxide emissions.

Participating in the project are Hok-

kaido Electric Power, renewable en-

ergy developer Green Power Invest-

ment, Nippon Steel Engineering and

industrial gas supplier Air Water.

Scheduled to begin operation as

early as the year ending March 2024,

the plant will produce up to roughly

550 tons of hydrogen a year – enough

to fuel more than 10 000 hydrogen

vehicles, according to plans.

The Japanese government aims to

attain net-zero greenhouse gas emis-

sions by the middle of the century.

Hydrogen is to play a big part of that

goal. The government’s Green Growth

Strategy announced last year calls for

up to 3 million tons of hydrogen pro-

duction capacity to be introduced in

2030, rising to about 20 million tons

in 2050. This plan requires Japan to

develop its own hydrogen industry

without relying on imports.

n Chiyoda Corporation (Chiyoda)

and GridBeyond have signed a Mem-

orandum of Understanding (MoU) to

collaborate in providing exibility

solutions for the Japanese electricity

markets. Such solutions help grid op-

erators to balance demand and supply

on the electricity network and enables

greater integration of intermittent re-

newable generation sources into the

energy mix.

Wind power farms in Vietnam’s cen-

tral province of Quang Tri are scram-

bling to complete construction of proj-

ects to benet from the 20-year

incentive feed-in tariff available until

31 October 2021.

Quang Tri has 29 wind farms under

construction with a total capacity of

1117 MW and costing over VND30

trillion ($1.32 billion).

At two projects – Phong Huy and

Phong Nguyen – the foundations are

complete but only four out of 24 tow-

ers have been built. Nguyen Ngoc

Tien, CEO of the projects, said he has

increased the number of workers and

even transports materials at night to

nish the projects before the deadline.

Developers are also calling for a

change in quarantine restrictions to al-

low foreign experts to quarantine on-

site upon arrival and start working

immediately.

Wind power is becoming an increas-

ingly important part of Vietnam’s en-

ergy mix. Vietnam is striving to pro-

duce about 3000-5000 MW of offshore

wind power by 2030 and 21 000 MW

by 2045.

Addressing a webinar last month,

Chairman of the Vietnam Union of

Science and Technology Associations

(VUSTA) Phan Xuan Dung said the

country will benet from the develop-

ment of offshore wind power, whose

cost will gradually decrease in the

future.

Experts say, however, that the coun-

try still lacks legal regulations and

technical standards for the production,

installation, operation, and mainte-

nance of offshore wind power. A

mechanism for offshore wind power

purchase is also necessary to stimulate

this market, they said.

State-owned electricity company PT

PLN Persero has said it will increase

investment directed at renewable-

energy power plant construction in

anticipation of a ve-fold jump in

Indonesia’s electricity demand by

2060.

PT PLN said it will ensure several

old plants that are still operational are

included in the biomass co-ring

programme, and will also convert fos-

sil fuel power stations into green en-

ergy power plants to reduce the use of

polluting oil and coal.

According to PT PLN’s General

Vice Director Darmawan Prasodjo,

the company will start to phase out

the rst generation of conventional

steam plant by 2030. He said all of

these oil and coal red stations will

be replaced by renewable energy

power plants by 2060.

The announcement is timely. It co-

incides with the news in early August

that some of the world’s biggest nan-

cial institutions are working on a plan

to speed up the closure of coal red

power plants in Asia.

According to a recent BBC report,

the initiative created by UK insurer

Prudential, which includes major

banks HSBC and Citi, is being driven

by the Asian Development Bank

(ADB). The ADB hopes the plan will

be ready for the COP26 climate con-

ference in Glasgow, UK.

Under the proposal, public-private

partnerships will buy coal red plants

and shut them far sooner than their

usual operating lifespan. The ADB

hopes to launch a pilot programme in

a developing South East Asian nation

– potentially Indonesia, the Philip-

pines or Vietnam – in time for the

COP26 event in November.

The International Energy Agency

has forecast that global demand for

coal will grow by 4.5 per cent this

year, with Asia making up 80 per cent

of that rise.

Japan steps up offshore

wind activity

Indonesia to increase renewable investment, as coal nancing dries up

Vietnam wind developers

scramble for tariff incentive

n Preferred bidder selected for stake in oating offshore wind project

n Largest offshore wind powered hydrogen project takes shape

28-29 SEPTEMBER 2021

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THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Special Technology Supplement

Industrial gas turbines:

the perfect complement for

renewables-plus-storage

With the growth in

variable renewables,

energy storage is

expected to be the

key technology

for providing grid

support and shifting

renewable power to

when it’s needed.

Siemens Energy’s

Anders Stuxberg

explains to

TEI Times why

industrial gas

turbines will

be crucial in

complementing

renewables-plus-

storage in an

optimised system.

Junior Isles

prices for nal consumers, and the use

of smart meters.

“When you look at the demand for

balancing power, storage solutions

are efcient systems, with up to 80

per cent of the energy coming back

[from the storage]. But it is not eco-

nomical to design an energy storage

system for all possible situations. And

when you empty the storage, you

have to ll-in with something else,”

said Stuxberg.

That “something else”, he says, will

typically be (fuel red) thermal

plants, i.e. the backup power capacity

that must exist in the grid anyway to

ensure reliable supply when there is

no wind or solar for a long period.

There are several options as to

which technology, or group of tech-

nologies, can support renewables-

plus-storage depending on the sce-

nario. For example, arguments are

sometimes made for fuel cells while

other experts present compelling

cases for fast-start generating assets

such as gas turbines and reciprocating

engines.

Stuxberg believes industrial gas

turbines are currently the best all-

round option. He commented: “In a

deeply decarbonised energy system,

gas turbines will play a key role both

for mid-merit power supply and as

backup power. Although some argue

that fuel cells will take that role, that

can only happen if fuel cells for a

fully functional and installed power

generation plant become cheaper than

gas turbines. We are not there today

and I believe that if it happens, it will

take many decades. Fuel cells,

though, are already a good option for

microgrids and mobility applications.

The requirement that backup power

also should be fuel exible, e.g. use

both hydrogen and liquid renewable

ith the urgent need to combat

climate change, wind and

solar power are growing at a

phenomenal rate. According to the

International Energy Agency, renew-

ables will meet 80 per cent of global

electricity demand growth during the

next decade. Solar PV, for example,

dubbed by the IEA as “the new king”

of electricity supply, grows by an

average of 13 per cent per year between

2020 and 2030, meeting almost one-

third of electricity demand growth

over the period.

The variable nature of wind and

solar, however, presents challenges in

terms of grid stability and how best to

provide backup power for when the

wind is not blowing or the sun is not

shining.

With targets set for reaching zero

carbon emissions in the electricity

sector, clearly the goal must be to

support renewables as far as possible

with energy storage – a zero carbon

source of grid exibility. The ques-

tion, however, is what generating as-

sets to deploy alongside storage, and

how to achieve the best mix of storage

and those assets in terms of cost and

operability.

Anders Stuxberg, Specialist in

Power Plant Process Integration at

Siemens Energy AB said: “Gas tur-

bines (GTs) will be the technology of

choice to be dispatched when storage

power capacities are insufcient for

the demand and also when the storage

becomes emptied. If you look at bal-

ancing supply and demand through

the grid in general, you have to look

at it over a number of different time-

frames. The system has to be man-

aged, second-by-second, minute-by-

minute, hour-by-hour, using different

technologies. You also have to look at

balancing over longer timeframes…

The question is how to optimise these

storage and generating resources.

Storage will handle the bulk of energy

for balancing, but there will not be a

business case to try to cover every-

thing with storage alone, you will

need to complement it with GTs.

“By implementing storage, the op-

erating prole for GT-based plants

will be signicantly changed. GTs

will be a cornerstone of the grid infra-

structure but with a new role in future

compared to what we have been used

to seeing. You will see a shift to

backup power instead of peaking

units and exible mid-merit com-

bined cycle plants instead of baseload

plants; this will favour industrial GTs

for new installations. Industrial gas

turbines are also suited to use hydro-

gen as fuel and fuels produced

through power-to-X schemes,” said

Stuxberg.

With storage expected to take cen-

tre-stage in maximising the integra-

tion of renewables and distributed

generating sources, the market for

the technology is forecasted to grow

exponentially over the next decade

(see box).

Regardless of which of the various

storage solutions is selected, however,

they are all generally limited by two

parameters: power capacity and en-

ergy capacity, i.e. duration of storage

at full power. Stuxberg noted that

when optimising storage solutions,

power plant owners will size for the

most frequent instances that give the

most energy trade volume and then

leave the residual load to some other

technology.

He said: “There will be many days

the energy in the storage is insufcient

for the demand and many days when

storage systems have less power ca-

pacity than needed, at least during

part of the dispatch duration. So other

technologies will be called for both at

surge of power and of energy, there

will be a play between different types

of storage solutions and capacity

backup.”

He also noted: “Storage technolo-

gies that can shift operating mode af-

ter the storage is emptied – continuing

power production by ring a supple-

mentary fuel – will also play a role in

backup supply, i.e. double benets to

the system. Examples are: power-to-

hydrogen-to-power where the hydro-

gen-to power unit (gas turbine) oper-

ates on e-methanol when the gas

storage is emptied, or a thermal stor-

age plant that also can run by ring of

e-ammonia when the thermal storage

is emptied.”

Stuxberg says there will also be

competition between storage and

demand response (DR). If altering

the time of energy use (e.g. smart

charging electric cars) does not dam-

age business, then DR will be more

efcient and cost competitive than

storage.

Many types of DR will, however, be

limited in much the same way as stor-

age. For example, duration – mainly

limited by the nature of the demand

that has been put on hold – will nor-

mally be limited to a number of hours.

The amount of DR that will be avail-

able naturally depends on the price

incentive, the volatility of energy

Power plant owners will optimise storage solutions size for the most frequent instances that give

the most energy trade volume and leave the residual load to another technology

Don’t let balancing power capacity get out of balance

Storage will handle the bulk of energy for balancing but it will

need to be complemented with GTs

slightly more expensive power than

the storage system. If the dispatch is

just based on a commercial energy

trade, then hybrid plants comprising a

combination of e.g. renewable power,

storage and GT may be a good busi-

ness as smarter dispatch can be

achieved.”

Typically, many gas turbines will be

installed in an electric grid to provide

the necessary backup power. The

dispatch order for these will be based

on cost or environmental footprint.

Since the requirement will be for a

fairly low dispatch rate, Stuxberg

says a large portion of dispatch may

be based on capacity auctions where

a xed compensation for just existing

as available backup is paid out.

If efciency is also credited, e.g. by

dispatch order, then a fair portion of

these cycling GTs will be congured

as combined cycle. However, the

bottoming steam cycle must then be

suited to frequent starts, i.e. fast and

with low start-up cost. Stuxberg notes

that in a future where these mid-merit

plants need to operate on renewable

fuel, which will be expensive, a bot-

toming cycle will be required for

many of these plants for the sake of

opex. The remaining plants, which

will have a low dispatch rate of, say,

less than 500 hours per year, will not

be so sensitive to efciency but will

need to have low capex and xed

standstill cost.

“So, for the power generation busi-

ness, we will see two typical types of

GT plants for the future: combined

cycle plants for cycling operation,

dispatching in a mid-merit pattern of

somewhere between 1000 and 3000

hours per year; and simple cycle

plants, with dispatch often less than

500 hours per year. The traditional

base load plant is thus replaced by a

very exible mid-merit plant, while

the traditional peaking plant is re-

placed by demand response and stor-

age solutions plus a large quantity of

backup power.”

His absolute conviction is that in-

dustrial gas turbines present the best

suitability to this type of future duty

for both these plant types. “They have

very high reliability due to simplicity

in design concept, high combined

cycle efciency, low price, low main-

tenance cost, good fuel exibility and

much better grid stabilisation charac-

teristics (by high inertia and strong

control response) than aeroderivative

GTs or recip engines,” he said.

For both these plant types, his ex-

pectation is that there will be an aver-

age of one start every one to four

days, most frequent for the mid-merit

type. Stuxberg predicts a wide operat-

ing regime for such gas turbine plants.

For demand response (DR) and for

energy storage systems, he noted that

they will dominate dispatch of bal-

ancing power for short duration and

during periods of low demand for re-

sidual power.

He noted, however: “When looking

at capacity it is hard to rule out rare

events with low probability, thus in-

stalled GT power capacity in the grid

will need to be large. The scale of

backup capacity needed depends

predominantly on the capacity factor

fuel is also a cost issue, if not a prob-

lem, for fuel cell plants.

“Reciprocating engines compared

with gas turbines have pros and cons.

In short, they are less efcient than

combined cycles and are more expen-

sive per capacity than simple cycle

GTs, with the exception of emergency

diesels gensets, which have a shorter

lifespan. For mid-merit operation,

maintenance cost is an important

factor to consider – industrial GTs

have lower maintenance cost than,

e.g. recip engines or fuel cells.”

He also notes that conventional

boilers with steam plants are too in-

exible to handle the frequent starts

and stops to balance residual power

demand. Further, their efciency is

low, especially if designed for renew-

able fuels such as biomass.

Based on the shortcomings of these

technologies, Stuxberg believes the

focus for grid balancing should there-

fore be on a blend of industrial gas

turbines (IGTs) and storage solutions

and a probable future dispatch prole

for those assets.

IGTs in the range up to 70 MW are

typically used in a number of applica-

tions. CHP applications are common

across the whole range due to their

ability to meet heat demand. The

smaller machines may be deployed in

settings like hospitals, universities,

small industries and O&G, to provide

power in areas where the grid is not

completely stable or onsite generation

is required. Medium-sized machines

in the upper range of 30-70 MW may

be used by, independent power pro-

ducers (IPPs), industrial CHP asset

owners, the O&G industry, munici-

palities producing electrical power

for the grid and heat for district heat-

ing networks, as well as utilities.

Stuxberg believes the operating

prole of IGTs in the future will not

be same as the peaking units of today.

Units in the future he says might start-

up and shut down once a day during

parts of the year, be in standby other

periods and also occasionally run for

a longer period, as opposed to cycling

several times per day.

With storage expected to be the rst

option for supplying multiple daily

power peaks, operators must then

decide how gas turbines will operate

to complement this storage.

Stuxberg foresees gas turbines be-

ing dispatched when the energy re-

quired exceeds what is available in

the storage. This will likely be after

the large afternoon/early night peak

or possibly in the morning. Gas tur-

bines will also be called for when all

storage solutions are already provid-

ing near full power capacity, i.e. typi-

cally during the evening peak.

He explained: “If GTs are being

called on every day for one of the two

reasons, power surge or energy surge,

then that’s a signal to storage inves-

tors that here you have an attractive

business opportunity – just buy some

more capacity. It’s low-hanging fruit.

So my conclusion is that GTs will

typically start once every 2-4 days on

average; some days they might be

called on twice and many other days

not at all.

“Traditional peaking plants and

base load plants will no longer be

suitable for this kind of market. So if

we have a GT on the system to ensure

backup anyway, the question is:

should you operate it for more hours,

which means more fuel consumption,

or should you make the storage

slightly bigger?”

According to Stuxberg, that optimi-

sation determines how the gas turbine

is operated, the type of turbine se-

lected and whether the plant should

be simple cycle or combined cycle.

He explained: “Generally, each ad-

dition of duration for a storage tech-

nology comes at an added investment,

which needs to be paid for by less and

less events since long duration events

are less frequent than shorter events.

The marginal cost of longer operation

for a GT plant ring renewable fuel

on the other hand is constant as it just

adds fuel consumption (fuel storage is

relatively cheap). The duration at the

cross-over point between technolo-

gies depends on event probability, a

number of economic factors and

choice of technology. The decreasing

probability of long events explains

why even pumped hydro plants, at

present, often are sized to t just one

day cycles.”

He added: “Grid balancing of up to

a couple hundred megawatts would

be fairly common. This could be di-

vided across a number of machines so

you can follow demand better without

running machines at part-load.”

Such an installation would have to

be capable of meeting several require-

ments. Firstly, it should be capable of

starting “reasonably” fast.

“If there is some kind of communi-

cation protocol (using new IT solu-

tions and advanced forecasting tools)

in the market telling GT operators to

start in fair time before stored energy

runs out, then very fast GT start is not

required, 20 minutes should sufce,”

said Stuxberg. “Also when power

capacity becomes the issue, it should

on most occasions be possible to

predict when to dispatch GTs. How-

ever, power peaks come faster than

drainage of energy, so here dispatch

centres can reserve some power in the

storage by starting the GTs a bit in

advance when a demand ramp-up is

expected. Here a fast GT start pays off

a little as there is less need to reserve

power from storage dispatch and thus

there is a bit less operation of the GTs,

which could be assumed to produce

Special Technology Supplement

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

IGTs such as the SGT-800 are

typically used in a number of

applications

The dispatch order for

GTs in the grid for backup

will be based on cost or

environmental footprint

Stuxberg: in a deeply decar-

bonised energy system, gas

turbines will play a key role

both for mid-merit power sup-

ply and as backup power

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

through to morning and for the bal-

ancing duty that storage solutions

would otherwise provide, as there is

no surplus renewable power during

the day for charging the storage.

Here, high efciency storage is

charged from high efciency mid-

merit GT plants during the day, as

this limits the need of thermal plant

capacity during the peaks. The result

is that the required thermal plant ca-

pacity is about twice the capacity of

installed storage.

If DR is added, it would reduce the

required amount of storage as well as

the power capacity for storage charg-

ing/discharging during an average

wind day. In the low wind scenario, it

would also reduce the need for in-

stalled thermal capacity, as it attens

the thermal power supply.

“Naturally reality is more complex

than these simple scenarios, with sea-

sonal variations on both demand and

supply, effects of clouding, fast uc-

tuations, grid disturbances etc.,” noted

Stuxberg.

Fuel exibility also has to be a key

consideration. If a machine is oper-

ated for less than 1000 hours/year,

the impact of fuel consumption on

environment and economics is rela-

tively small. However, the goal is to

of wind and solar and level of long

distance power transmission. Up to

about 50 per cent of grid capacity may

be expected; in isolated grids or grids

with weak connection to other grids

one may even argue for 100 per cent.

When you also look at resilience and

tolerance for grid failures most of the

GT installations should be distributed

in the grid, this favours mid-sized gas

turbines as well as exible CHP. In

large, high capacity grids, large GTs

will also be attractive for backup

power capacity due to low specic

investment.

“When looking at energy supply

rather than the installed capacity, de-

mand response and storage will dis-

patch maybe 80 per cent of all energy

needed for grid balancing and GTs

only the remaining 20 per cent. Those

GTs should preferably operate on re-

newable fuel.” he added.

The gure below shows demand as

well as solar and wind supply in a

simplied ctitious medium size

grid. On the left, wind supply during

an average day, where energy fed into

storage covers about 85 per cent of

the balancing need. On the right,

where wind supply is low, thermal

power generation is needed to replace

lower wind supply during the evening

run turbines on renewable fuels, and

uncertain policy in the long-term out-

look in this area is a challenge.

Stuxberg said: “There are a number

of optional renewable fuels for use in

GTs, hydrogen being one of the top

candidates, but today we don’t know

which of these will be economical or

available in the future and obviously

it will always depend on the site loca-

tion and operating prole. But the

point is, industrial gas turbines are

exible”

The market for IGT-based grid

balancing assets is huge – anywhere

in the world where there is renew-

ables growth calling for day-to-day

renewables support, while offering

emergency backup for the grid.

There is also room for large frame

gas turbines, where countries have

large robust grids.

“In Sweden, we have a lot of hy-

dropower but when we close down

nuclear capacity and replace with

wind farms, there isn’t enough ca-

pacity to handle the residual power

peaks. There we will see a large de-

mand for [GT] backup power. Those

machines would probably operate

for less than 10 per cent of the time.

In many markets today, there is no

compensation for having capacity in

place and that is an issue.

“Grid integrity and resilience via

sufcient backup should mainly be

seen as part of the grid infrastructure

rather than energy trade. Solving

backup power supply with existing

coal red plants is a route that has

already proven a failure as it counter-

acts the greenhouse gas savings from

renewable power, i.e. incentives for

investment in more suitable backup

technology is needed” said Stuxberg.

He concluded: “Renewables and

storage systems will play the major

future role for energy supply but that

requires a lot of exible backup and

for that gas turbines are the most cost

effective today – if you need to build

capacity today; it’s gas turbines.

“We can only speculate on what

will happen in the future through

development of other technologies.

But we need to change the energy

system now. With the environmental

challenge, we cannot wait 30 years;

so we have to base it on the technol-

ogy we have today and industrial gas

turbines is an available technology

well t for the purpose. Backup

power also needs to be installed

ahead of renewable implementation

to ensure grid resilience, so the need

is urgent.”

Demand, solar and wind

supply in a simplied

ctitious medium size grid

Special Technology Supplement

The energy storage market is forecasted to grow exponentially

All storage technologies can store surplus renewable energy and return it to the

grid later, thus avoiding curtailment and increasing the use of renewable power.

According to analysis from IHS Markit, annual installations of energy storage

capacity globally will exceed 10 GW in 2021, more than doubling the 4.5 GW in-

crease in 2020. The existing capacity in stationary energy storage is dominated

by pumped-storage hydropower (PSH), but because of decreasing prices, new

projects are generally lithium-ion (Li-ion) batteries.

PSH capacity additions are predicted to remain constant at 5-10 GW per year,

while battery capacity is expected to grow from 2.3 GW/year in 2018 to above

30 GW/year in 2050. Total installed storage capacity was around 170 GW in

2019, a gure that is expected to reach 950 GW by 2050, according to IHS

Markit.

Another report – ‘The Energy Storage Grand Challenge Energy Storage Mar-

ket Report 2020’ – published by the US Department of Energy forecasts a 27

per cent compound annual growth rate (CAGR) for grid-related storage through

to 2030. It projects annual grid-related global employment to increase about 15

times from around 10 GWh in 2019 to almost 160 GWh in 2030.

The type of storage deployed will depend on grid design and the distribution

of generating plants and loads unique to each grid. The technology selected

depends on which offers the best economic and operational capability according

to the services, range of capacity and energy discharge duration needed.

Super-capacitors and rotating grid stabilisers (ywheels and synchronous

condensers) provide instantaneous system responses and grid control. Both

technologies are aimed at applications in the range of approximately 1-100 MW.

Pumped storage hydro is the most dominant energy storage solution in terms

of globally installed megawatt capacity, representing some 93 per cent of the

operating system. It is a gigawatt-scale technology mostly used for energy shifting

and high-capacity rming with storage durations of around days or weeks with mini-

mal energy losses.

Further, capacity and operating reserve is provided when the asset is connected to

the grid. But although a mature and widespread technology, its main drawback is the

required topology of the site (large height differences are needed) and its physical

impact on the environment.

Thermal energy storage (TES) can improve utilisation of waste heat, assist in the

electrication of process heat supply, or store renewable energy for re-electrication

using a steam turbine. TES can also be integrated with thermal generation plants,

e.g. a combined cycle plant. A wide variety of heat storage media are available,

including liquids such as molten salt and pressurised water, or solids such as stone,

steel, concrete, or sand.

Liquid air energy storage (LAES) and compressed air energy storage (CAES) are

further technologies aimed at gigawatt-scale applications. LAES is based on the

cryogenic liquefaction of air when it is compressed with the use of (preferably)

renewable electricity. The liquid and the produced heat can be easily stored and

discharged when needed for re-electrication. CAES works similar but stores com-

pressed air. By adding a thermal storage to this technology, the overall efciency is

improved.

Li-Ion batteries are currently the technology of choice driven by their cost-effective-

ness and speed characteristics. They offer several applications, such as frequency

response, exibility enhancements of conventional power generation assets, black

start capabilities or energy arbitrage. Their sweet spot is up to around 250 MW and 5

hours of duration.

siemens-energy.com/ decarbonization

LET’S MAKE TOMORROW DIFFERENT TODAY.

Improving efficiency of our energy systems. Replacing

conventional fuels with cleaner options. Building

highly flexible hybrid systems. This is how we lead the

way to mitigate the impact of climate change.

Decarbonizing

our energy systems

is a journey of many steps.

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Junior Isles

Already affected by the Covid-19 pan-

demic, wind turbine manufacturers are

now bracing for the impact of higher

wind turbine prices.

Danish wind turbine manufacturer

Vestas has lowered its full-year guid-

ance citing supply chain constraints,

cost ination, and restrictions in key

markets caused by Covid-19.

The company now expects full-year

revenue in 2021 of between €15.5 bil-

lion and €16.5 billion, including Ser-

vice. The previous expectation was

€6-17 billion.

It was a similar story for Siemens

Gamesa. The company adjusted its

guidance for nancial year 2021 with

an EBIT margin pre-PPA and before

Integration and Restructuring (I&R)

costs in the range of between -1 per cent

and 0 per cent. It said group revenue is

expected to be at the low end of the range

announced during the presentation of

results for the second quarter (April 30,

2021), i.e. €10.2-10.5 billion.

“We are operating in what is cur-

rently a very difcult environment and

have taken additional steps to balance

our risk prole as we focus on deliver-

ing long-term sustainable protabili-

ty,” said Andreas Nauen, Siemens

Gamesa’s Chief Executive Ofcer.

‘Despite current challenges, the com-

pany is soundly placed to take advan-

tage of the huge potential of wind en-

ergy, which is reected in our strong

order backlog.

Meanwhile, the Nordex Group is

maintaining its guidance for the cur-

rent nancial year of achieving con-

solidated sales of €4.7-5.2 billion and

an EBITDA margin of 4.0-5.5 per

cent. The group said the impact of the

pandemic on the operating business

only had a limited inuence on its

positive performance in the second

quarter but noted its indirect effects

were still clearly evident in the up-

heaval in the raw materials and logis-

tics markets.

According to Wood Mackenzie, wind

turbine prices are set to continue their

upward trend, rising by up to 10 per

cent over the next 12 to 18 months on

higher commodity prices and logistics

cost, as well as challenges linked to the

coronavirus.

Turbine prices have increased over

the last six months, pushed up by rises

in steel, copper, aluminium and bre

prices and a four-fold surge in logistics

costs. According to the research and

consultancy group, they will likely re-

turn to normal levels by end-2022.

“Turbine OEMs and component sup-

pliers face a double whammy of cost

increases and demand softening over

the coming two years due to the US

PTC (Production Tax Credit) and Chi-

na feed-in-tariff (FiT) phase-outs,”

said Wood Mackenzie principal ana-

lyst Shashi Barla.

Further cost pressures in relation to

the US-China trade tussle have caused

the likes of Vestas, Siemens Gamesa

Renewable Energy and Nordex to ex-

plore alternative supply hubs such as

India, the rm said.

Wood Mackenzie also warned of sup-

ply chain bottlenecks for key materials

over the next four to ve years and

advised OEMs and turbine suppliers to

adopt next-generation technologies

and materials.

Last month Siemens Gamesa said it

will expand its offshore blade factory

in Hull, England by 41 600 m

, more

than doubling the size of the manu-

facturing facilities. The expansion

represents an investment of £186 mil-

lion and is planned for completion in

2023.

Earlier, the company said it aims to

manufacture fully recyclable blades by

2030, and redesign the rest of the wind

turbine components to put a 100 per

cent recyclable generator on the market

by 2040.

A growing number of companies are

ramping up plans to build battery

manufacturing plants around the

world, as the world accelerates its

transition to low carbon economy.

In mid-August Reliance led a $144

million fundraising by US energy stor-

age start-up Ambri, as part of the In-

dian group’s plans to manufacture

batteries in its home market.

Reliance New Energy Solar said it

would invest $50 million in Ambri and

that the two were in talks “to set up a

large-scale battery manufacturing fa-

cility in India, which could add scale

and further bring down costs for Reli-

ance’s green energy initiative”.

The deal, which follows an an-

nouncement in July that ArcelorMittal

had invested in Massachusetts-based

start-up Form Energy, is the latest in a

series of tie-ups between large indus-

trial groups and start-ups seeking to

develop energy storage technology.

In Europe, Norway-based Freyr Bat-

tery recently said it remains committed

to plans to build ve gigafactories in

northern Norway, despite potential

complications caused by Brexit. There

are fears that a clause in the Brexit

agreement between the UK and EU

could mean that any cars built in the

EU containing Norwegian batteries

would face tariffs of 10 per cent to en-

ter the UK from 2027 and vice versa.

Tom Jensen, the Chief Executive of

Freyr Battery, said: “It has not caused

us to change our plans whatsoever. But

it doesn’t mean we’re not paying at-

tention to it.” The rst gigafactory is

due to produce batteries from next year.

Jensen said the rst two gigafactories

would be used for energy storage

rather than electric vehicles.

Iselin Nybo, Norway’s Minister of

Trade and Industry, said the country

has “initiated dialogue” with the Euro-

pean Commission and the UK “in an

attempt to nd solutions to the issue”.

Norway has high hopes for its battery

industry as it looks to use its extensive

renewable energy from hydroelectric

power to attract green businesses.

Freyr, whose shareholders include

Koch Industries and commodity giant

Glencore as well as institutional inves-

tors Fidelity and Franklin Templeton,

is aiming to have 43 GWh of battery

production capacity by 2025 and 100-

150 GWh by 2030.

Meanwhile, Glencore last month ac-

quired a stake in Britishvolt, the battery

start-up behind ambitious plans for

Britain’s electric battery gigafactory.

The £2.6 billion ($3.56 billion) project,

designed to equip the UK’s car indus-

try for an electric future, will be im-

portant in helping the government meet

its carbon reduction targets.

As part of the agreement, Glencore

will also supply the gigafactory, which

is under construction in Northumber-

land, with cobalt, a raw material used

in electric batteries.

CYE, a specialist in cyber security op-

timisation platforms is partnering with

Otorio, a provider of next-generation

OT cyber and digital risk management

solutions, to provide an integrated so-

lution to companies with converged IT/

OT/IOT environments looking for

proactive ransomware protection.

The partnership aims to help custom-

ers convert the new rigorous US gov-

ernment regulations for critical pipe-

line owners and operators into practical

cyber security plans, and to develop

actionable steps to improve their cyber

hygiene and overall security.

In recent months, there has been a

signicant increase in ransomware

attacks on industrial companies and

critical infrastructure, including the

Colonial Pipeline attack, which

caused fuel shortages across the East

Coast of the US for over a month and

led to the payment of a $4.4 million

ransom.

CYE and Otorio provide cyber

visibility across all IT, OT and IOT

environments, quantifying risks,

identifying exposures, and building

long-term cyber security best prac-

tices. The companies claim the solu-

tion is fully automated and simplies

compliance processes and ongoing

risk monitoring. Furthermore, by pro-

actively identifying exposure and

potential attack vectors, and address-

ing them before they become breach-

es, it enables companies to signi-

cantly reduce risks, while minimising

cost.

Two signicant deals in late July look

set to accelerate the growing hydrogen

market.

MAN Energy Solutions and Andritz

Hydro announced they have completed

a strategic framework agreement to

jointly develop international projects

for the production of green hydrogen

from hydropower.

A pilot project in Europe will mark

the start of the collaboration. Subse-

quently, the companies want to jointly

identify further projects and imple-

ment them in the context of the German

federal government’s H2 Global initia-

tive. H2 Global is a market-based fund-

ing platform, which aims to efciently

promote the market launch of green

hydrogen and hydrogen-based power-

to-X products. For this purpose, hydro-

gen energy partnerships are to be es-

tablished with countries with a

correspondingly high potential to pro-

vide a long-term, cost-effective and

reliable green hydrogen supply to Ger-

many and the EU.

Frank Mette, CEO of Andritz Hydro

in Germany, commented: “Hydro-

power is one of the few completely

climate-neutral forms of energy,

which is capable of providing base

load power. We therefore see excellent

potential for worldwide expansion –

in new construction projects just as

much as in repowering. By adding the

possibility of producing hydrogen to

hydropower plants, we are taking the

next step and also making the energy

generated there ready for export and

storage without restriction. Together

with MAN Energy Solutions, we can

open up new markets and opportuni-

ties for the operators.”

The companies are aiming to launch

an initial joint pilot project before the

end of this year to provide about 650

tons of green hydrogen by using an

electrolysis output of up to 4 MW, ini-

tially for local use. In follow-up proj-

ects, designed for the export of hydro-

gen, the installed electrolysis output is

expected to increase to up to 100 MW

in the coming years.

In another move, Johnson Matthey

(JM), a global leader in sustainable

technologies, announced its acquisi-

tion of the assets and intellectual prop-

erty of UK-based Oxis Energy Limit-

ed. Oxis Energy was a lithium-sulphur

battery developer with assets, which

can be adapted for the manufacture of

components for green hydrogen pro-

duction. The company entered admin-

istration on 19 May 2021.

With moderate additional invest-

ment in upgrades, this transaction will

signicantly accelerate the scale-up of

JM’s growing green hydrogen busi-

ness. The facility will further expand

JM’s ability to develop, test, and

manufacture catalyst coated mem-

branes and advanced materials for

electrolysers.

The site will enable the production

of tens of thousands of catalyst coated

membrane parts per year – enough to

equip hundreds of megawatts of elec-

trolyser capacity.

MAN Energy and Andritz

agree on hydrogen,

as Johnson Matthey

accelerates scale-up

Companies

charge up

battery

manufacturing

CYE partners with Otorio to combat

ransomware attacks

Changing winds for OEMs

n Vestas and Siemens Gamesa lower full-year guidance

n Turbine prices to continue upward trend

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Companies News

he challenges facing the devel-

opment of large nuclear power

plants, especially in Europe,

have been well documented over the

last 15 years or so. Finland’s Olkil-

uoto 3 is nearly 13 years behind

schedule and about three times over

the original €3.2 billion budget. It is

a similar story at Flamanville 3 in

France and Hinkley Point C in the

UK. Even across the pond in the US,

delays and costs at Vogtle 3 & 4 con-

tinue to head north.

Yet despite the poor track record

of the industry, Philippe Bordarier,

Chief Operating Ofcer at Fenno-

voima, believes the 1200 MW

Hanhikivi 1 project, currently under

development in Finland, can pro-

vide some valuable lessons for

plants going forward.

Fennovoima is owned by a number

of shareholders, which include doz-

ens of major Finnish industry corpo-

rations such as Outokumpu and For-

tum, and local energy utilities. These

shares, representing a 66 per cent

stake in Fennovoima, are held by

Voimaosakeyhtiö SF, a Finnish hold-

ing company. As these shareholders

require a large amount of energy for

their operations, a reliable and stable

priced power supply is crucial for

their businesses.

RAOS Voima, a 100 per cent

Finnish subsidiary of Rosatom,

owns the remaining 34 per cent of

the shares in Fennovoima. RAOS

Voima plans to sell its share of the

electricity from the plant on the

NordPool market.

Fennovoima operates under the

“mankala principle”, i.e. it will sell

all the electricity generated by the

plant to the owners at cost price in

proportion to their ownership. This

price includes operating and nanc-

ing costs, as well as the organisation-

al costs of the company. The manka-

la principle has been widely used in

Finland’s energy sector for decades –

about 40 per cent of the electricity in

Finland is produced by the mankala

companies.

Commenting on Fennovoima’s ap-

proach, Bordarier said: “We could be

paving the way; maybe what we are

doing here could be replicated else-

where. If you look at other opportu-

nities in the nuclear sector, like de-

veloping small modular reactors

[SMRs] for example, this could be a

useful model for future companies.

We are proving that it is possible to

develop, build and commission a nu-

clear power station design and be a

safe operator starting from the com-

mercial decision.”

Bordarier, who joined Fennovoima

from EDF in April, sees the compa-

ny as somewhat “unique” – doing

three things at the same time.

“Firstly we are building a nuclear

power plant, which is a massive in-

frastructure project. Secondly, we

are building the operator of the sta-

tion, which means we develop the

skills – the people, the processes – to

operate the station. This is quite

unique in itself because the nuclear

industry is very specic. And be-

cause Fennovoima is a brand new

company, we are building that com-

pany. All of this makes the project

very different and that’s part of what

attracted me.”

Bordarier calls Fennovoima “the

rst 21st century nuclear energy

company in the world”.

He explained: “The vast majority

of today’s nuclear new build projects

are controlled by either a large share-

holder that is usually an existing util-

ity company or state agency, or by

an EPC company. Fennovoima is a

commercial project that started al-

most from scratch – we don’t have a

massive utility or EPC company as

our main shareholder. Rosatom is the

EPC contractor but does not control

the company; it’s a kind of unique

model.”

What makes such a commercial

project possible in Finland is partly

due to the country’s long nuclear ex-

perience – it has a major regulator,

nuclear operators, experienced nu-

clear engineers and access to suppli-

ers in both western and eastern Eu-

rope that can provide both

equipment and services.

The Hanhikivi 1 plant is located in

the Hanhikivi peninsula, a coastal

site near the municipality of Pyhä-

joki in Northern Ostrobothnia on

the shore of the Baltic Sea in North-

ern Finland.

The power station is based on

tried and tested Russian nuclear

technology. It will employ a 3+

Generation VVER-1200 pressurised

water reactor that has all the safety

features proposed by the various au-

thorities post-Fukushima. It is to be

constructed by Rosatom under a

xed price turnkey engineering,

procurement and construction

(EPC) contract, which means the

price that Fennovoima will have to

pay for construction will not esca-

late in the event of an overrun on

the project schedule.

It could prove to be a smart deci-

sion. With design and licencing work

still ongoing, construction of the nu-

clear island is targeted for 2023.

Pouring of rst concrete will mark

the beginning of a six-year construc-

tion period, with commercial opera-

tion planned for 2029.

Bordarier believes this target is still

realistic despite the delays that have

already been seen due to a protracted

licencing period. The Construction

Licence was originally expected to

be issued in 2018 but 2022 is now

the new target. The process, carried

out by STUK (the Finnish nuclear

regulatory agency) is notoriously

complex, with several thousand re-

quirements having to be met.

Bordarier noted: “We are absolute-

ly preparing for construction to start

in 2023. Some facilities, such as the

training centre are already built; se-

curity gates and fences are there. We

also have some warehousing, etc. for

suppliers. At the moment, we are

carrying out work such as dewater-

ing the site and will start doing some

earthworks. But we will need the li-

cence to start construction of the nu-

clear building.

“Commercial operation in 2029 is

still realistic. If you look at the

VVER-1200, many have been built.

Akkuyu [in Turkey] is currently

making good progress and Titan 2,

the company that will be in charge of

constructing Hanhikivi 1, is becom-

ing very experienced in building

these stations. Yes it’s an ambitious

target but it’s realistic and is still our

reference schedule. We plan to stick

to that but once we get an update on

the licence, we will have a bit more

clarity.”

Still, Bordarier is seasoned enough

to realise it will not be all plain sail-

ing, and he will have to call on his

extensive experience to keep things

moving to schedule.

“In large projects like this, you

have to learn quickly. We like to use

the ‘5 P’ model in the nuclear indus-

try – Plant, People, Processes, Plat-

forms and Partners. On the ‘plant’,

which is the key challenge and prior-

ity, we need to get the licence. That

means nalising the documentation

with the EPC supplier to ensure we

address all the usual safety questions

in a coherent design.

“On ‘people’, we are developing

the owner-operator’s skills and

competencies. For ‘processes’ and

‘platforms’, we are developing our

management system. We are cur-

rently in the project phase and will

move from licencing to construction

to operation. On this journey, we

also need to develop our tools. We

are starting virtually from scratch,

with no legacy, so we have to make

the right decision to today on devel-

oping the right tools for the next 20-

30 years. ‘Partners’ means develop-

ing our supply chain. This will be a

blend of the Russian supply chain

as well as the usual western Europe-

an and of course Finnish companies

that have been involved in other

Finnish projects.”

With the immediate challenge be-

ing to obtain the construction li-

cence, Bordarier rst wants a very

clear understanding of what Fenno-

voima has to deliver in the coming

months.

“We have a clear understanding

with our supplier and the regulator

on the documentation and basic de-

sign development needed to get the

licence,” he said. “We are still dis-

cussing a couple of very important

items in terms of changes to

Hanhikivi 1 compared to the refer-

ence plant. For example, the I&C

(instrumentation and control) system

will be more [advanced] compared

to other VVER-1200 plants. We

should have all the documentation

ready for submission to the regulator

within the next few months. This is

being done in batches, so they al-

ready have most of the material… so

I’m condent we will get the licence

next year.”

In the meantime, work has already

started on some of the long lead-time

items for the nuclear island. For ex-

ample, the steam turbine generator is

currently being manufactured in Bel-

fort, France. The manufacturing doc-

uments for other long-lead items

such as the forgings are still being

approved with the suppliers, before

being submitted to the regulator. In

addition, other equipment needed for

site preparation is currently being

manufactured in Estonia for delivery

next year.

In spite of the challenges facing

large nuclear projects, Bordarier

points out that the battle against cli-

mate change has to remain at the

forefront of the minds of industry

critics.

He concludes: “We have to decar-

bonise electricity; this is the founda-

tion of Hanhikivi 1. It’s part of the

Finnish energy strategy to be carbon-

free. It is true that we have seen

many challenges for these large in-

frastructure projects in western Eu-

rope. But we have learned a lot of

lessons and have a lot of people in

Fennovoima that have been involved

in new build projects in western Eu-

rope. We have a lot to do but our re-

sponsibility is to agglomerate and

get the best of what we’ve learned

from other projects.”

New build large

nuclear plants often

come under re as

a result of delays

and high capital

costs, which usually

go over budget.

Fennovoima’s

Hanhikivi 1 power

plant in Finland

could offer some

clues on how plants,

including small

modular reactors,

could be successfully

developed in the

future. Junior Isles

Hanhikivi 1: a model for

nuclear new build in Europe?

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Industry Perspective

Bordarier: “We could be

paving the way; maybe what

we are doing here could be

replicated elsewhere”

proposed project is a long-term pros-

pect that faces multiple hurdles. Hong

Kong could easily import green and

sustainable energy from neighbour-

ing Guangdong province but It faces

little hurdles to import clean electric-

ity, given that it is an integral part of

China. Singapore would face some

geopolitical issues, but the city state

does have a history of importing some

forms of energy from its two closest

neighbours.

Hong Kong’s slow e-mobility poli-

cy-making is highlighted in my book:

‘Asia’s energy revolution’. Singapore

has been more aggressive on the

electrication of transport vehicles

policy-wise, although so far Hong

Kong has managed to add more e-

vehicles. The number of electric ve-

hicles in Singapore is still small but

has been ramping up. As of 2020,

there were 1249 electric cars and

taxis, or 0.2 per cent of the total. The

percentage of electric commercial

vehicles was just 0.1 per cent and that

of buses 0.3 per cent. In 2020, the

government announced that it will

phase out all internal combustion en-

gine (ICE) vehicles by 2040 with all

vehicles running on clean energy by

then. A year later it said it would grow

electric vehicles (EV) charging points

to 60 000, (40 000 public and 20 000

private). It committed to fuel the

city’s bus eet with cleaner energy

also by 2040. It also set up the Na-

tional Electric Vehicle Centre to sup-

port EV adoption, including the ac-

celeration of building a nationwide

charging infrastructure, as well as

regulations and standards.

Hong Kong has also set some EV

targets, but they seem rearward by

comparison to Singapore. Hong Kong

had about 686 275 passenger cars and

taxis as of June 2021. Tax incentives

resulted in Hong Kong having about

18 500 e-vehicles as of January 2021,

ingapore embraced the energy

transition faster than Hong

Kong. A clear vision and proac-

tive government support allowed ro-

bust expansion of renewables and

electrication in the ‘Lion City’. Hong

Kong has lagged despite beneting

from being a region of China, which

is a global leader in clean energy and

e-mobility. Singapore’s superior track

record will endure in the medium term.

The two cities are similar yet differ-

ent. The population of the Hong Kong

Special Administrative Region is 29

per cent larger than that of the Repub-

lic of Singapore. Its land area is about

49 per cent bigger but they both have

a similar population density (7140

people/km

for Hong Kong vs 8358

for Singapore). The GDP structure is

different and impacts the amount of

energy used. About a third of Singa-

pore’s GDP comes from industry

while over 94 per cent of Hong

Kong’s is services. The primary en-

ergy consumption and electricity

generated was 3.42 EJ and 53.1 TWh,

respectively, for Singapore and 0.93

EJ and 44.1 TWh for Hong Kong;

actual consumption is actually higher

as some nuclear power is imported

from Guangdong province. In terms

of greenhouse gas emissions, Hong

Kong’s was at 40.1 million tonnes of

carbon dioxide equivalent (MtCO

in 2019, mostly from power genera-

tion and transport, vs 47.4 MtCO

for Singapore in 2018, with about half

from industry.

Singapore and Hong Kong are keen

to cut emissions. The path includes

greener buildings, energy supply, and

transport. A clearer vision and support

by Singapore’s government has

translated into a stronger track record.

It developed solid policy frameworks

to boost investments in green projects.

Also, it provided strong support to

private sector efforts to transition en-

ergy supply and consumption to

green and sustainable resources.

This has not been the same for Hong

Kong. Many policies and efforts are

either still on the drawing board or

have been half-hearted. Its path has

been innitely slower than China’s,

which today is a global leader in clean

energy investments and e-mobility.

Climate action success by the two

jurisdictions can be evaluated from a

variety of lenses. One is clean energy.

Another is the shift to transport elec-

trication, especially that of private

and commercial vehicles.

Given land size and natural re-

sources limitations for both, the most

viable source of green sustainable

energy is primarily solar power. There

is also some potential for waste-to-

energy and offshore wind, especially

for Hong Kong. Both have a good

amount of average annual solar irra-

diance. Singapore’s is 1580 kWh/m

and Hong Kong’s 1290 kWh/m

about 20 per cent less. Singapore tar-

gets at least 2 GW in solar capacity by

2030 from about 290 MW in 2020; it

was 2.9 MW in 2010.

Hong Kong renewable energy data

is hard to nd, probably a reection of

the government’s slow approach to

renewables in general. In 2019, the

government said that renewables ac-

counted for about 0.1 per cent of

electricity consumption without pro-

viding specic numbers. A calcula-

tion showed that government and the

private sector had added approxi-

mately 4-5 MW in renewables up to

2018. The Special Administrative

Region has no formal target for 2030

or 2050. It only says that by 2030 the

potential for renewables is 3-4 per

cent of consumption, with solar con-

tributing 1-1.5 per cent. A study

commissioned by the government

concluded that the feasible maximum

amount of rooftop solar PV output is

0.88 TWh while another study by a

local university put the potential

maximum amount at 4.67 TWh.

Both Hong Kong and Singapore are

land restricted, though they can im-

port clean energy. For Singapore, it

could rely on clean power imports

from Malaysia or Indonesia. Cur-

rently, there is even the possibility

that it could possibly import renew-

able energy from Australia; albeit the

about 2.7 per cent of the total. The

government said that it would ban

ICE vehicles sales by 2035, provide a

concrete timetable for the electrica-

tion of public transport and commer-

cial vehicles by 2025, support the set

up of 150 000 private charging points

and build 5000 public ones by 2025.

It also wants zero vehicular emissions

by 2050 but has not provided a blue-

print to arrive at this goal.

Singapore is likely to retain its

strong climate action track record in

the coming years. The city-state has

consistently wanted to be a trailblazer,

especially in the energy sector. It is

likely to set aggressive clean energy

targets post-2030. Also, its e-mobility

targets could potentially be brought

forward.

Hong Kong is likely to continue to

lag, based on its past track record. It

has a wild card, however: China. The

nation is the undisputed global leader

in clean energy additions and in EVs.

It is possible that the central govern-

ment may put pressure on Hong Kong

to accelerate clean energy and e-mo-

bility plans. It could also help in many

other ways including selling clean

energy to Hong Kong and assist on a

more rapid deployment of the EV in-

frastructure. The key motivation

could be China’s ‘30–60 Goal’: peak

carbon emissions before 2030 and net

zero before 2060. As an integral part

of China, Hong Kong will have to

play its part.

Giuseppe (Joseph) Jacobelli is a busi-

ness executive, analyst, and author

with over 30 years’ experience in en-

ergy and sustainability in Asia. He

founded investments and advisory

Asia Clean Tech Energy Investments.

He is the author of ‘Asia’s Energy

Revolution: China’s Role and New

Opportunities as Markets Transform

and Digitalise’, De Gruyter 2021.

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Climate Countdown

Hong Kong and Singapore are similar yet different. The differing GDP structures impact the

amount of energy they use

Source: Author, August 2020. Data sourced from Worldometers.info; World Bank; BP; and Statista

Singapore is likely

to maintain a better

climate action

track record than

Hong Kong for the

coming years but

Hong Kong has a

wild card: China.

Asian energy expert

Joseph Jacobelli

compares these two

important markets as

COP26 draws nearer.

Hong Kong vs Singapore:

a decarbonisation tale of two cities

Singapore solar PV (MW).

Singapore has a good amount

of average annual solar

irradiance and is targeting at

least 2 GW in solar capacity

by 2030

Source: Author, August 2020.

Data sourced from: Energy Market

Company (EMC); SP PowerGrid Ltd

(SPPG); Energy Market Authority

(EMA)

ong-duration storage has long

been the missing link between

intermittent solar and wind

power and the promise of round-the-

clock renewable energy. Although a

variety of electrochemical battery so-

lutions – vanadium ow, iron ow,

iron-air – are emerging to address the

issue, these are mostly expensive,

unproven, or both. Now, US-based

247Solar has introduced an innova-

tive thermal battery design that takes

a different approach.

Because it is a thermal battery,

247Solar’s solution, dubbed Heat-

StorE™, stores energy as heat in-

stead of electricity. This enables en-

ergy to be stored in a variety of

materials, like sand, rocks or ceramic

pellets, that are both inexpensive and

environmentally benign. When pow-

er is required, the stored heat is used

to drive a unique turbine to produce

electricity on demand.

The technology behind HeatStorE

originated at the Massachusetts Insti-

tute of Technology (MIT), and was

developed by co-inventor and now

247Solar CEO, Bruce Anderson. It

was initially conceived as 247Solar’s

rst commercial product, the 247So-

lar Plant™.

This modular, scalable concentrat-

ed solar power (CSP) plant captures

solar energy using heliostats (solar

mirrors) and a unique solar collector

that heats air at atmospheric pressure

to 970°C (1800°F). Some of this su-

perheated air is directed toward a tur-

bine to produce electricity. The re-

mainder is directed toward a thermal

storage module where it is stored for

later use.

Always a feature that differentiat-

ed CSP from cheaper PV, long dura-

tion storage was to be expected as a

part of this design. However, unlike

conventional CSP, which stores heat

in caustic, environmentally un-

friendly molten salts, 247Solar’s

thermal battery uses inexpensive

dry media – initially ceramic pellets

and now ordinary sand. This not

only makes it less complex and

much less expensive, it also allows

the system to operate at much high-

er temperatures, dramatically in-

creasing efciency.

Along the way, Anderson realised

that the need for long-duration stor-

age was even greater for PV and

wind. While these were the dominant

technologies in the marketplace, they

produced electricity directly and

could only store it in expensive,

short-duration lithium-ion batteries.

The challenge was, therefore, how to

bring the benets of long-duration

thermal storage to these technolo-

gies. Simple electric resistance coils,

not unlike an everyday electric stove,

provided the answer. The coils could

convert electricity to heat for storage,

247Solar’s turbine could re-convert

the stored heat back to electricity on

demand, and the HeatStorE battery

was born.

Each HeatStorE battery is a module

of 200 kW/1800 kWh capacity. Mul-

tiple units can be combined in any

quantity to create storage banks of

any required size. Typical storage

duration is 4-20 hours depending on

temperature and depletion rate, and

unlike electrochemical batteries,

HeatStorE promises a service life of

20 years or more with little or no

performance degradation. HeatStorE

provides reactive power, and because

it produces AC instead of DC, no in-

verter is required.

HeatStorE looks unlike any other

battery, but the system is deceptively

simple. Electricity from PV or wind

heats air up to 1000°C (1850°F) us-

ing electric resistance coils. This hot

air is blown through an insulated

container containing ordinary silica

sand, which absorbs the heat and re-

tains it for up to 20 hours. As need-

ed, more air is blown through the

storage container, heated, and then

used to drive a special turbine to re-

convert the heat to electricity.

This unique turbine is the rst

commercial turbine able to be driven

entirely by atmospheric pressure hot

air, without burning fuel. 247Solar

took an off-the-shelf Capstone C200

turbine and added a proprietary ultra-

high-temperature heat exchanger.

Superheated air from the battery’s

thermal storage (or any other source

above 850°C) is passed through this

heat exchanger and transferred to

compressed air inside the turbine.

The resulting temperature and pres-

sure are sufcient to drive the turbine

without combustion, producing

emissions-free electricity.

247Solar sees a wide range of ap-

plications for this technology in the

marketplace. The foremost of these

is as a replacement for diesel gensets

in mines, microgrids and other off-

grid applications. Even when cou-

pled with short-duration lithium-ion

batteries, PV and wind are capable of

producing electricity, on average,

perhaps 40 per cent of the time. Off-

grid, when power is required around

the clock, the difference is usually

made up by diesel gensets, which

pollute and are costly to fuel. With

up to 20 hours of storage, HeatStorE

can increase renewables penetration

(the amount of time during which

power is produced from renewable

sources) to 80 per cent or higher.

In the inevitable case where both

solar and wind power are unavail-

able and thermal storage is depleted

(the remaining 20 per cent), Heat-

StorE’s turbine can also burn a vari-

ety of fuels. With an optional exter-

nal combustor that can burn natural

gas, diesel or virtually any other liq-

uid or gaseous fuel, HeatStorE can

completely eliminate the need for

backup gensets. Further, by burning

clean fuels such as biofuels or green

hydrogen, HeatStorE provides a real-

istic pathway to 100 per cent renew-

able penetration whenever such fuels

are available.

This is particularly important, as it

means the system offers 100 per

cent, 24/7 dispatchability, even when

the storage is completely discharged.

This is an unusual feature for batter-

ies and is especially valuable for

smaller (<10 MW) grid or microgrid

applications that experience wide

uctuations in demand.

In another application that is

unique to HeatStorE, the system can

also be used behind the meter in in-

dustrial settings to convert other-

wise-wasted hot process exhaust to

electricity.

As an added benet for applica-

tions that require both heat and pow-

er (CHP), HeatStorE provides two

useable exhaust streams: 250°C from

the heat exchanger and 640°C from

the turbine itself. Both can be har-

nessed for useful purposes like creat-

ing steam or to drive other high-tem-

perature industrial processes. System

efciency is approximately 30 per

cent for electricity alone and can rise

as high as 80 per cent when both ex-

haust streams are used.

As an alternative to gensets, Heat-

StorE offers signicantly lower oper-

ating and maintenance (O&M) costs.

In addition to substantial fuel sav-

ings, it has few moving parts and it is

built with proven, extremely reliable,

low-maintenance components.

The chart shows an indicative com-

parison of a 1 MW hybrid microgrid

involving PV, diesel gensets, and

lithium-ion batteries in one instance,

and PV and HeatStorE in the other.

The difference in OPEX over a 20-

year lifespan is dramatic.

Like conventional batteries, all

HeatStorE components are factory

produced, and promise rapidly de-

creasing costs with increased pro-

duction volume as the systems are

deployed worldwide. Except for the

turbine and the core storage module,

most other components can be man-

ufactured in local markets for job

creation and to meet domestic-con-

tent requirements.

Negotiations are currently under-

way in several countries to deploy

HeatStorE in a wide variety of set-

tings. These include several mines in

Australia in collaboration with glob-

al PV and wind suppliers, an Austra-

lian microgrid to power a small

town, multi-site rural electrication

projects in Africa, and many others.

247Solar is currently constructing its

rst commercial demonstration plant

at a company-owned site in Arizona,

USA.

As a scalable long-duration storage

solution that avoids the complexity

and environmental drawbacks of

electrochemical batteries, the market

potential for HeatStorE is enormous.

When added to PV or wind, it can

provide the operational exibility

and resilience to make high-penetra-

tion renewable energy solutions via-

ble for mines, community mi-

crogrids, off-grid villages or islands.

With up to 20 hours duration, it al-

lows for substantial grid-support and

load shifting, enabling users to har-

ness all the available renewable ener-

gy they can while the sun is shining

or the wind is blowing, and to store it

for use whenever it is needed.

Mark von Keszycki is Director of

Marketing and Communications at

247Solar.

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Technology Focus

US-based 247Solar

has developed an

innovative thermal

battery that looks set

to facilitate 24/7 wind

and solar energy.

As a scalable long-

duration storage

solution that avoids

the complexity

and environmental

drawbacks of

electrochemical

batteries, the

market potential is

enormous.

Mark von Keszycki

An imaginative approach

to long duration storage

Cost comparison: 247Solar microgrid with HeatStorE battery vs conventional microgrid

247Solar microgrid with Capex Operating Capex/yr Fuel Annual O&M O&M Total

HeatStoreE battery ($) life (yr) ($) cost ($/l) fuel cost ($) ($/kWh) ($/yr) annual cost ($)

HeatStorE battery, 1 MW/14 MWh 3 072 000 20 153 600 153 600

PV, 4 MW 3 200 000 20 160 000 160 000

Li-ion battery, 0.5 MWh 300 000 10 30 000 30 000

O&M 0.010 17 520 17 520

Fuel, 1752 hr/yr 1.00 470 00 470 000

Total annual cost of ownership 831 120

----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Conventional microgrid: Capex Operating Capex/yr Fuel Annual O&M O&M Total

Diesel + PV + Li-ion ($) life (yr) ($) cost ($/l) fuel cost ($) ($/kWh) ($/yr) annual cost ($)

Gensets, 1MW 350 000 10 35 000 35 000

PV, 1 MW 800 000 20 40 000 40 000

Li-ion battery, 1MWh 600 00 10 60 000 60 000

O&M 0.025 219 000 219 000

Fuel, 7000 hr/yr 1.00 1 880 000 1 880 000

Total annual cost of ownership 2 234 000

Notes: assumes 1 MW load, 24/7. $=USD

THE ENERGY INDUSTRY TIMES - SEPTEMBER 2021

Final Word

t seems the discussion around

hydrogen has moved on from

whether it is just hype or the next

rising rap or rock star, to what colour

outt it should wear on stage. In

some things, colour appears to be all-

important.

With the UK preparing to host the

COP26 climate summit in November,

the country has naturally garnered the

attention of the energy sector and

those that have a major role to play

in tackling climate change. Last

month, Britain’s Prime Minister Boris

Johnson released the UK’s Hydrogen

Strategy, viewed as a key part of the

government’s commitment to achiev-

ing net zero carbon emissions by

2050.

The government set out what it calls

a “twin track approach” supporting

both electrolytic ‘green’ and carbon

capture-enabled ‘blue’ hydrogen

production, alongside other potential

production routes, which will enable

the rapid growth of the sector while

bringing down costs. “We outline a

comprehensive roadmap for the

development of the wider hydrogen

economy over the 2020s to deliver

our 2030, 5 GW ambition,” it said.

But the twin track has split the in-

dustry. There are those that argue the

UK should only invest in green hy-

drogen, i.e. hydrogen produced by the

electrolysis of water using electricity

from zero carbon energy sources.

Others, however, note that this is

expensive – green hydrogen is about

2-3 times more expensive than blue

– and will take too long to become

cost competitive. They therefore see

a role, at least in the interim, for the

production of blue hydrogen, i.e.

hydrogen produced from steam re-

forming of natural gas combined with

carbon capture and storage (CCS) to

capture the carbon emissions from the

process.

Serious doubt, however, was re-

cently cast on even this interim role.

Ahead of the launch of the UK

strategy, researchers at Cornell Uni-

versity and Stanford University

published a study, which claims that

blue hydrogen could be 20 per cent

worse for the climate than burning

natural gas. The report concluded

“there really is no role for blue hy-

drogen in a carbon-free future”.

Robert Howarth, co-author of the

study and Professor of Ecology and

Environmental Biology at Cornell

University, said the report is “a warn-

ing signal” to governments that “the

only ‘clean’ hydrogen they should

invest public funds in is truly net-

zero, green hydrogen made from

wind and solar energy”.

In his ‘Ten Point Plan’ for a green

industrial revolution issued earlier

this year, Johnson announced a £240

million fund for government co-in-

vestment in production capacity

through the Net Zero Hydrogen Fund

(NZHF) – a hydrogen business

model to bring through private sector

investment – and plans for a revenue

mechanism to provide funding for the

business model. It is also supporting

fuel switching to hydrogen in indus-

try through the £315 million Indus-

trial Energy Transformation Fund and

£20 million Industrial Fuel Switching

Competition.

Experts are concerned that much of

the money will go towards blue hy-

drogen, thereby locking the country

in to continued fossil fuel use.

Referencing the Cornell study just

ahead of the government’s strategy,

Juliet Phillips, Senior Policy Advisor

Clean Economy, E3G said: “A cli-

mate-safe future demands a rapid and

steep reduction in greenhouse gases,

but today’s new report warns that

fossil fuel derived blue hydrogen is

far from a truly zero emissions fuel.

There is no time left to waste in sec-

ond-rate solutions to the climate

emergency.

“Worryingly, the UK government

has so far allocated around 75 per cent

of public investments in hydrogen

towards this fossil-based fuel. We

encourage the UK government to

rethink its risky strategy of pursuing

a ‘twin track’ approach of supporting

both blue and green hydrogen, and

instead focus on becoming a global

leader in green hydrogen sourced

from renewables.”

No doubt the twin track approach

will be welcomed by the oil and gas

sector, as blue hydrogen is a natural

t for their operations and helps se-

cure a demand that is likely to falter

as pressure to decarbonise deepens.

Earlier this year Al Cook, Executive

Vice President for development and

production at Norway-based Equinor,

notably said: “Green is the destina-

tion, but we’ll get there on a blue

highway. At some point, green hydro-

gen might well be lower cost than

blue, but that will likely not be for at

least a decade.”

Such thinking, on the face of it, is

not without merit. It would help

governments ramp-up hydrogen in-

frastructure and projects, and inject

real momentum to this edgling, but

growing, industry.

As Victoria Judd, Counsel at Pills-

bury, put it: “By pursuing a ‘twin

track’ approach for its hydrogen

strategy and promoting the produc-

tion of both blue and green hydrogen,

the UK government could well re-

solve the chicken-and-egg scenario

that threatens to potentially hobble

the UK’s nascent hydrogen industry.

Currently, the supply of hydrogen is

unlikely to rise until there is sufcient

demand for the gas, but equally de-

mand will remain low until supply

rises. Stuck between a rock and a hard

place, promoting the more abundant

blue hydrogen alongside green will

ensure the sector has the much

needed scale to attract vital invest-

ment. The twin track sets us on the

right path.

“Some may criticise the strong

support for blue hydrogen as part of

the hydrogen strategy. But, if hydro-

gen supply rises, and brings up de-

mand, markets will be far more at-

tractive to developers considering the

green approach. We can consider this

a run-up before our green hydrogen

ambitions take ight.”

This was essentially echoed by

global engineering, architecture and

consultancy company, Ramboll, al-

though with caution. UK Energy

Market Director John Mullen, com-

mented: “What this strategy will -

nally deliver, and what is really

needed, is the business assurance that

investment in hydrogen infrastructure

and technology is a good bet. There

are also still distinct challenges to

overcome and the ‘twin track’ ap-

proach will need to be closely moni-

tored as blue hydrogen and carbon

capture are incredibly inefcient

processes at present and the only

justication for their use is to allow

for the transition to a green hydrogen

world. Blue hydrogen could be used

to support business cases to imple-

ment new hydrogen infrastructure,

however the government needs to put

a cap on the greenhouse gases pro-

duced and place a deadline for the end

of all blue hydrogen production in the

next 10 to 15 years.”

Yet BloombergNEF estimates that

already by 2030 green hydrogen is

likely to be cheaper than blue hydro-

gen in all geographies. CCS technol-

ogy is also a problem for blue hydro-

gen. Although around for decades, it

remains expensive and challenging to

operate, resulting in just 26 projects

operational globally as of December

last year.

Whether to focus on green hydrogen

only – an approach that will take time

and greater expense but is ultimately

where we need to be – or stick with

the twin track approach, which will

move hydrogen along more quickly

at lower cost but locks-in fossil fuel

dependence, is a tough call.

But with the recent IPCC report

highlighting that human-induced cli-

mate change is already causing many

weather and climate extremes in every

region across the globe, the choice

should be clear. It is time to spare no

expense or effort into taking the zero

carbon pathway, where that alternative

exists. In the same way that costs of

solar, wind and batteries have fallen,

and continue to do so, there is ample

reason to believe the same can happen

with green hydrogen.

In response to a previous column I

wrote on hydrogen, a colleague said

hydrogen was neither rap star nor rock

star but “more like the talented pub

band that has always demanded high

fees, now enlarging its paying audi-

ence in a world of music lovers”. Well

that pub band just got bigger and more

expensive – especially when dressed

in green – but in the end the show will

be worth it.

Rock stars wear green

Junior Isles

Cartoon: jemsoar.com