Global Voice of Gas - Issue 3, Volume 3

Global Voice of Gas B Y T H E I N T E R N AT I O N A L G A S U N I O N ISSUE 3 | VOL 03

EXPLORING DECARBONISATION

The case for CCUS in decarbonising LNG

Veritas: a consistent approach to measuring methane

What is e-methane?

Policy is key for supporting LNG supply: MidOcean Energy CEO

Message from the President Dear readers, welcome to the third quarterly issue of the Global Voice of Gas magazine in 2023.

This issue’s release follows the International Gas Union’s Annual Member Council meeting in Perth, Australia, on October 19, excellently hosted by our valued Charter Member, the Australian Gas Industry Trust working together with support of the Government of Western Australia. I am very happy to have had the opportunity to meet with the representatives of the entire IGU global gas community face to face in such a key location for the global gas market, to reflect on the year, discuss future priorities and to shape a stronger global voice of gas together for 2024.

This was a timely meeting, given the great uncertainty that the global gas industry must navigate in the coming years. The massive disparity across international energy outlooks and scenarios for gas is challenging the investments necessary for the market to come to a stable balance. That is why the 2023 Global Gas Report was dedicated to examining this uncertainty in depth and to explore pathways for gas in the energy transition. Upon close examination of various degree scenarios assumptions, it is very clear that a policy re-think is needed, and the level of investment in new gas projects today is insufficient to reach an affordable, secure, and sustainable energy system in 2030 and beyond.

It is also clear that natural gas will continue playing a key role in the energy transition, while the gas sector will also continue to decarbonise, and I urge an aggressive acceleration of deployments in carbon capture and low-carbon and renewable gases to make that possible. That will require collaboration across the gas industry and, importantly, appropriate policy tools and frameworks, including pricing emissions and removing barriers to deployment and access to finance. With COP 28 just around the corner, this message is as important as ever.

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The second half of 2023 has brought relief to the gas markets with reduced prices, and the European storage at nearly full level ahead of schedule. Yet, the energy crisis has not ended, the gas markets remain in an unstable equilibrium, as the price reductions came at a high cost of demand destruction and the supply in the market remains very constrained. In this regard, we have seen positive shifts in focus toward security of supply, and I commend the excellent efforts by governments, industry, and customers. However, knowing that security must work in balance with affordability and sustainability for a successful energy transition, further rebalancing is still necessary.

The IGU firmly believes in the need to cooperate, as we strive to do across the gas value chain and across the globe, and in the need to do so better across the whole energy value chain.

We have only one planet and the global energy networks are connecting energy industries and the energy consumers, who want secure, sustainable, and affordable energy. I am convinced that decarbonisation of the vast global energy systems is not going to be possible without productive dialogue, cooperation, and sophisticated planning based on achievable targets.

Gas is and will continue to be an essential part of the global energy ecosystem, and that doesn’t make us need less renewables and other low-carbon energy technologies, and it doesn’t mean that we should not continue to look for ways to reduce our consumption of energy as a society. However, by working together we can achieve much more much faster.

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Contents FEATURES

17

The case for CCUS in decarbonising LNG

30

21

LNG: going all-electric is a site-specific option

37

27

Veritas: a consistent approach to measuring methane

From the President..... 2 Editor’s Note.............4 Events .....................6

40

What is e-methane?

44

A global gas market that performs

Policy is key for supporting LNG supply: MidOcean Energy CEO

Natural gas has delivered for Israel

Regional Update Africa................................................ 10 North Asia & Australasia........................ 12 Europe...............................................14

The opinions and views expressed by the authors in this magazine are not necessarily those of IGU, its members or the publisher. While every care has been taken in the preparation of this magazine, they are not responsible for the authors’ opinions or for any inaccuracies in the articles.

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Editors’ Note Welcome to the 13th issue of the Global Voice of Gas magazine, an International Gas Union publication, produced in collaboration with Natural Gas World (NGW). The release of this issue comes just weeks ahead of the key energy transition milestone, the UN COP28 climate summit taking place in the United Arab Emirates through the start of December, where world leaders will convene to measure progress that has been made in realising the goals of the Paris Agreement. The world is already aware that the stocktake may come back less than perfect for progressing the energy transition, particularly as emissions continued to rise in 2022 and the energy crisis forced many nations to resort to more coal and oil burning, as they looked for alternatives to mitigate the surging prices of natural gas. However, what will matter most are the conclusions drawn from that and the decisions made on how to coursecorrect, while the emissions reduction targets are still within reach. Optimally, these decisions will be inclusive, pragmatic, technology-neutral, taking into account the fundamentals of global energy, capital, and capacity endowments, to set the world up for an achievable success.

It is clear that natural gas and the low-carbon gaseous energy at large must be recognised in these policies for their critical role in the global energy transition. As the world looks to reduce emissions in power, buildings, industry, and the transport sectors, while drastically scaling intermittent renewable generation, the reliability, flexibility, efficiency, and cost- effectiveness of gas make it an unmatched resource for a sustained and sustainable transition.

Gas remains the most cost-effective available resource for grid resiliency, heavy industrial activity, and, in many regions, for energy in buildings.

But this issue of GVG focuses on how the environmental value can be further enhanced, by addressing methane emissions more aggressively, deploying low-carbon technologies such as carbon capture utilisation and storage (CCUS) and electrification, and supporting the development of low-carbon gases such as hydrogen, e-methane and biomethane.

We begin the issue by looking into a new report for the Global Gas Innovation Roundtable, established this year with support from the Canadian Gas Association (CGA), which concludes that the

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G LO B A L VO I C E O F G A S

suitability of CCUS as a decarbonisation option varies greatly across the gas supply chain, and that it is important to consider geography, government policy, and local industrial context when planning and developing projects. The issue then moves on to the case for using all-electric drives as a means of reducing emissions at LNG plants, and how the emissions reductions that are achievable differ based on how clean a given country’s power grid is.

We are also proud to include an interview with Amanda Harmon, Senior Manager at GTI Energy, on the organisation’s Veritas initiative – a set of standardised, science-based, technology-neutral protocols for getting a true measurement of methane emissions associated with the natural gas industry.

In addition, we give our thanks to Koki Hayakawa, Secretary General and Senior Managing Director of the Japanese Gas Association, for sharing Japan’s experience in developing e-methane as a means of achieving a seamless transition to a decarbonised society, lowering emissions while supporting secure energy supply and making use of existing gas infrastructure.

De la Rey Venter, CEO of LNG player MidOcean Energy, also joined us for an interview, in which he elaborated on the role of policy in restoring the balance in the global LNG market and bringing more supply to keep up with demand, while driving reductions in emissions. Furthermore, Yossi Rosen, Chairman of the Israeli Institute of Energy and Environment, meanwhile takes us through the transformational impact that natural gas has had on Israel since development began a decade ago.

We also provide a summary of the main findings of the International Gas Union’s Wholesale Gas Price Survey 2023, which tracks the changes in gas pricing over the years, while demonstrating the criticality of a well-functioning global gas market at work.

Tatiana Khanberg, Strategic Communications and Membership Director, IGU

Joseph Murphy, Editor, Natural Gas World

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-

EVENTS

Time to come together and collaborate on the solutions and innovations that gases deliver

RODNEY COX Director of Events, International Gas Union

The two occasions when conferences are at their most powerful are when an industry has challenges or opportunities. Today our industry faces both and IGU’s Flagship Events are at the forefront of delivering the knowledge and wisdom needed to secure our future.

MAY 13-16, 2024 | WWW.IGRC2024.COM

First up is IGRC2024, IGU’s International Gas Research Conference – IGRC2024, to be held in

PRESENTED BY

HOSTED BY

Canada in May 2024. With so many of the solutions and innovations required coming from research, development and innovation, the timing could not be better for IGRC2024 and I encourage you to check out the benefits for your company from you attending to collaborate and learn alongside your peers from around the world.

Looking ahead, we are about to open the Call for Abstracts for WGC2025 Beijing. With the Call for Abstracts opening in November now is the time to start discussions with your colleagues and your company on submitting an abstract. For more details, and to ensure you are kept up to date, email the WGC2025 team.

Finally, we take a moment to look back on LNG2023 in Vancouver in July. Quite simply the most effective event all year for the global LNG industry. As Michael Stoppard from S&P Global Commodity Insights observed, “LNG2023 separated the signal from the noise.” This is what IGU’s flagship events do best.

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IGRC2024 – Early bird registration now open!

Save on registration before November 15, 2023 International Gas Research Conference 2024, IGU’s flagship event, is being held from May 13-16, 2024 at the Fairmont Banff Springs, Canada. Join us in the heart of the majestic Canadian Rockies, a UNESCO World Heritage Site, for a dynamic global conference bringing together the latest research, leading practices and transformative insights that fuel innovation within the natural gas and gaseous energy industry. All of this while you enjoy an exceptional delegate experience.

Innovation is critical to keep natural gas a reliable, affordable, and low-emission source of energy.

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EVENTS

IGRC2024 is expanding its focus on technical research

contact us at igrc2024@cga.ca. IGU members can also

to include gas clean-tech, technology start-ups, and

contact Simon Polledri at the IGU Secretariat on simon.

social innovation – all to showcase global examples of

polledri@igu.org

innovation and its positive impact on both the sector and societies.

IGRC2024 offers a unique opportunity for professionals in the global gas and gaseous energy sectors to connect, collaborate and delve into the critical role of gas and its infrastructure in addressing complex energy challenges worldwide.

Early Bird Registration is now open, until November 15, 2023. By registering today, you will: •

Save on registration: register before November 15, 2023, and unlock savings of $250 USD.

•

Access the full programme: you will have exclusive access to a comprehensive programme that includes high-calibre technical sessions, strategic and thought-provoking plenaries, leadership dialogues

Presented By

Host Partner:

etc.

•

Attend keynote speaker sessions: Gain invaluable insights from our keynote speakers, who are globally renowned experts. Their enlightening sessions will highlight the pivotal role gas innovation has on societies and industries.

•

Discover cutting-edge research: Dive into groundbreaking research presented during our technical sessions and poster presentations. You’ll explore leading industry practices and discover transformative insights that are driving innovation within the gas industry.

•

Meet innovative exhibitors: be at the forefront of the gas industry’s innovation, by witnessing leading technology displayed by our exhibitors.

•

Experience Canada: immerse yourself in Canadian culture during our three networking receptions, where connections and collaborations will thrive.

Register today and be part of this essential dialogue.

Early Bird Registration closes on November 15, 2023.

Join us at IGRC2024: Connect. Collaborate. Innovate.

Find out more!

Scan the QR code to access the IGRC2024 Registration page. There you will find all Early Bird Registration details. If you require additional assistance, please

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WGC2025 – Call for Abstracts opens soon IGU’s World Gas Conference, WGC2025 Beijing, provides a unique opportunity to contribute your experience, knowledge and wisdom, and collaborate with your peers from around the world. The Call for Abstracts for WGC2025 opens in November 2023, to provide ample time for you to explore your options and discuss within your company.

The range of themes will ensure that there is an opportunity for every industry professional to submit.

From developing and deploying new technologies (from E&P to utilisation), through supply, demand, pricing and marketing, the new momentum for LNG, to transformation (whether digital technologies or the adoption of new gases), there is an opportunity for you to lead the discussion and make your contribution to a sustainable future for our industry.

For enquiries regarding WGC2025 Call for Abstracts submissions and to ensure you receive regularly updated information email the WGC2025 team.

G LO B A L VO I C E O F G A S

7

It was in this context that the core theme of LNG2023—Fuelling a Secure Energy Future—was decided. The conference’s sub-themes of fuelling a more stable, cleaner, and more prosperous future for all recognised that energy security, environmental sustainability, and affordability must all be balanced to achieve smooth energy transition. As one conference speaker noted, if we lean too hard in one direction, we

LNG2023 – fuelling a secure energy future

risk a collapse of the others.

In July, thousands of delegates from 80 countries

representatives, technical experts, and key

gathered in Vancouver, Canada, for LNG2023, the 20th

stakeholders. The daily discussions were rich, lively,

edition of the world’s largest triennial LNG conference

pragmatic, and, above all, optimistic. The LNG sector

and exhibition.

is well versed in innovation, and LNG2023 attendees

LNG2023 continued the long history of bringing together senior industry leaders, government

Much had transpired since LNG2019 Shanghai,

expressed great confidence that the industry will

China. From COVID-19 through faltering supply chains,

continue to use its strengths in creating solutions.

and rising inflation to the cutting of pipeline gas to

Check out some of the key outcomes from the Closing

Europe – countries grappled with energy security and

Plenary.

supply issues.

We now look ahead to LNG2026 in Doha, Qatar.

LNG2023 continued the long history of bringing together senior industry leaders, government representatives, technical experts, and key stakeholders.

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G LO B A L VO I C E O F G A S

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Sempra Infrastructure is not the same company as the California utilities, San Diego Gas & Electric company (SDG&E) or Southern California Gas Company (SoCalGas), and Sempra Infrastructure is not regulated by the California Public Utilities Commission. ©2023 Sempra Infrastructure. All copyright and trademark rights reserved.

R E G I O N A L U P D AT E

Africa’s natural gas production and consumption (bcm)

Africa

300

KHALED ABUBAKR

250

Chairman, Egyptian Gas Association.

259

168.5

200

Executive Chairman, TAQA Arabia and IGU Regional Coordinator

249

150

162.5

100

North Africa: Italy is counting on the region to replace lost Russian supply, while Morocco is resorting to LNG imports and Israel is preparing to ramp up supplies to Egypt.

50

» Eni expects North Africa – namely Algeria, Egypt and Libya

Africa’s natural gas trade (bcm)

0 2021 PRODUCTION

– to be Italy’s main gas supplier for the next few years, helping it replace lost Russian volumes. The Italian energy group intends to invest $3.5bn over four years in exploration and development in Egypt.

60

58

2022 CONSUMPTION

53.9

40

» Morocco is meanwhile turning to LNG imports after losing its pipeline deliveries from neighbouring Algeria, which

20

sought to use those deliveries as leverage in the dispute over the Western Sahara region. Its power and water utility ONEE signed in July a deal with Shell to secure 0.5 bcma of

9.6

0

2021

regasified LNG for 12 years. The country’s plans to develop more renewables are moving ahead slowly, suggesting gas will play a key role in its intended phase-out of coal.

» Israel is working to expand natural gas production at the offshore Tamar field and increase export to Egypt. Those exports are set to rise by 38.7 bcm over 11 years, while Tamar’s output is expected to grow 60% or 6 bcm annually from 2026. Egypt needs the extra gas, faced with growing demand from its population of 105mn and a 9% year-on-year decline in production in January-May this year, or 12% versus the same period of 2021. The country has grappled with power shortages as heat waves have driven up demand for cooling.

East Africa: Eni is eyeing a second FLNG project off Mozambique, and Kenya is set to build a gas pipe to Tanzania.

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LNG EXPORTS

9.4

2022

LNG IMPORTS FOR TOTAL MIDDLE EAST & AFRICA

» Eni is looking to build a second floating LNG (FLNG) plant in Mozambique to tap the abundant gas reserves in the Rovuma basin. The Italian major, working with ExxonMobil, Galp Energia, China National Petroleum Corp. and Korea Gas, operates the Coral Sul FLNG project off Mozambique that came online in 2022. It believes a second FLNG unit could replicate Coral Sul’s success. Coral Sul FLNG is expected to produce 450 bcm of gas in total, liquefying 3.4 MTPA for export.

» Kenya has completed a deal to revamp the defunct stateowned Kenya Petroleum Refineries Ltd (KPRL), paving the way for a gas pipeline to be built from Mombasa to Dar es Salaam, in Tanzania. In May 2021, Tanzanian President Samia Hassan

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R E G I O N A L U P D AT E

Morocco is meanwhile turning to LNG imports after losing its pipeline deliveries from neighbouring Algeria, which sought to use those deliveries as leverage in the dispute over the Western Sahara region.

and her then-Kenyan counterpart Uhuru Kenyatta signed

transport nearly 3 bcfd of gas per day along the West

off on a preliminary agreement covering the transport of

African coast to Morocco and Europe, running over

gas from Tanzania for use in power generation, cooking,

7,000 km, benefitting over 400mn people in West Africa.

and heating.

» Eni has begun oil and gas production at the giant

West Africa: More countries are signing up to the Nigeria-Morocco gas pipeline project, Eni has started production at the Baleine field off the Ivory Coast and Nigeria’s NNPC has signed a preliminary agreement on the UTM FLNG project.

Baleine field in deep waters offshore Ivory Coast. The first phase of development involves using a production storage and offloading vessel capable of handling up to 15,000 barrels per day of oil and 24 mcfd of gas. The second phase, on track to start by the end of 2024, will increase output to 50,000 bp of oil and 70 mcfd of gas, followed by a third that will raise it to 150,000 bpd and 200 mcfd respectively.

» Four more African countries – Côte d’Ivoire, Liberia, Guinea, and Benin – have signed memoranda of

» Nigerian National Petroleum Corp. (NNPC) has signed

understanding with Morocco and Nigeria to take part

a head of agreement with UTM Offshore Ltd. for the

in the flagship Nigeria-Morocco gas pipeline project,

UTM FLNG project. The planned FLNG vessel will

bringing the total number of countries participating

produce 176 mcfd of gas from the offshore Yoho Field.

to 12. Besides Morocco and Nigeria, the others are

NNPC will have a 20% equity stake in the project. The

Mauritania, Senegal, Gambia, Guinea-Bissau, Sierra

FLNG, due to be completed by 2026, will comprise

Leone and Ghana. The pipeline is expected to increase

a turret mooring system, gas pretreatment modules,

access to energy, improve living conditions and support

LNG production modules, living quarters, and power

the integration of regional economies. It is designed to

generation and utilities alongside storage and offloading.

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R E G I O N A L U P D AT E

North Asia & Australasia SATOSHI YOSHIDA Senior Adviser, Japan Gas Association, and IGU Regional Coordinator.

High LNG demand in Europe continues to impact Asia.

» When the possible strikes at three Australian LNG plants were reported on August 9, the JKM price temporarily exceeded $12 per mmBtu, but it is currently in the $11 per mmBtu range. This is because global LNG supply capacity is strained because of a lack of investment and Russian cuts in gas flow to Europe.

» On the other hand, JKM has returned to its typical premium to TTF – currently close to $2 per mmBtu, due to Europe’s abundance of gas in underground storage.

While Chinese LNG demand remains sluggish, the country is expanding its import portfolio to cover long-term demand. » China’s domestic gas production in January-May was 97.3 bcm (71.5 MT), up 5.3% year on year, while LNG imports

» Asia’s LNG supplies are largely influenced by the demand

came to 27.5 MT, up 4.0% year on year. Pipeline gas imports

for natural gas in Europe. In recent years, Asian countries have

totaled 18.8 MT, up 2.3% year on year. LNG imports in 2023

been unable to procure LNG at a lower price due to Europe’s

are expected to reach 69 MT, which is 5 MT more than in

sharply rising demand to replace natural gas lost from Russia

2022, thanks to new long-term supply contracts kicking in.

and delays in new LNG projects.

» JKM may be declining, but pipeline gas is still cheaper and » In some parts of Asia, high LNG prices have led to a

domestic gas and coal production is rising strongly. China’s

clear return to coal, which is affordable, abundant and

economy is still recovering from the impact of COVID-19 and

available, and this has become a major obstacle to achieving

does not need to purchase large volumes of spot LNG at this

decarbonisation through a shift from coal-fired to gas-fired

time.

power generation.

» On the other hand, China is steadily expanding its long-term » Nevertheless, new markets in Asia are opening themselves

LNG import portfolio to cover future demand. In November

up to LNG, and pioneering companies in Japan and Korea

2022, Sinopec signed a 4MTPA, 27-year sales and purchase

are contributing their accumulated knowledge, experience

agreement (SPA) with Qatar, and in April 2023, it acquired a

and expertise to support the diffusion of natural gas and LNG

1.25% stake in the North Field East (NFE) expansion project.

in the region – fuels that are indispensable to underpin the

In June, CNPC also signed a SPA under the same regime and

introduction of more renewable energy.

acquired an interest.

Despite decline in the last year, LNG prices remain high versus historical levels, and volatile.

» In May, PetroChina and BP each acquired 2 bcma of receiving capacity for 20 years from October 2026, following the expansion of the Gate LNG receiving terminal in the Netherlands. China is gaining a firm foothold in the global LNG

» JKM LNG prices remain highly dependent on TTF prices.

trade.

With the increasing build-up of inventories in Europe since early on in the year, both JKM and TTF are much lower

» Also in May, the Hong Kong LNG project was launched. The

than they were last year, but still high compared with historic

gas will be delivered from an FSRU moored at an offshore

norms. JKM is double the level of previous years

berth to two onshore power plants. CLP Power, which is

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R E G I O N A L U P D AT E

leading the project, has already signed a long-term LNG

South Korea are expected to decline in the future due to

purchase agreement with Shell for 1.2 MTPA of lNG for

the gas price hike in May.

10 years starting in 2020, with commercial operations scheduled to start in July.

» LNG imports are forecast to decline slightly in 2023, by 1 MT, due to the commissioning of the 1.4-GW Shin

» Including the Tangshan LNG receiving terminal, which

Hanul-1 and 1.4-GW Shin Hanul-2 nuclear reactors in

started operations at the end of June, the number of

December 2022 and September 2023 respectively.

LNG receiving terminals in China has reached 25, with a receiving capacity of 120 MTPA. However, imports have not increased as expected in recent years and capacity utilisation is expected to remain low.

Japanese LNG imports are falling fast, and the restart of more nuclear plants will further dampen demand. » LNG demand was sluggish in the first half of 2023 due to continued high inventories from the summer of 2022, mild weather, a strong recovery in nuclear power output

Australian government rolls out key policies, including targeted emissions reductions at gas facilities. » Under the new government, important policies have been announced, including a wholesale gas price cap and gas security guidelines.

» In July 2023, the Australian Safeguard Mechanism will come into effect, requiring 215 facilities, including gas

and subdued gas demand.

production facilities, that emit more than 100,000 T of

» On an annual basis, LNG imports are estimated to

If the target is not met, operators must use Australian

decline significantly to 64 MTPA in 2023, from 73 MTPA

Carbon Credit Units (ACCUs) to fill the gap.

CO2 per year to reduce CO2 emissions by 4.9% annually.

in 2022. A further decrease to 55 MTPA is envisaged by 2030, according to the Sixth Strategic Energy Plan (2021). Half of the estimated decline was achieved in a single year.

» In July, the Takahama 826-MW nuclear reactors no.

1 and 2 resumed operation for the first time in 12 years after Fukushima. Takahama was built in 1974. After Fukushima, new regulations restricted the operation of nuclear power plants over 40 years old. However, by meeting certain criteria, these nuclear power plants over 40 years old can extend operation up to 60 years.

Takahama is the second nuclear power plant to operate for more than 40 years. The restart of these nuclear power plants will further dampen the demand for LNG for power generation.

Higher prices and increased nuclear also weigh down on South Korean gas consumption. » Gas sales to residential and industrial customers in

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R E G I O N A L U P D AT E

» Nevertheless, the uncertainties regarding Russian pipe

Europe

gas and LNG flow and the consciousness that the security of natural gas supply to Europe isn’t guaranteed if the winter is cold, have meant that volatility on the European market and therefore the global LNG market remains high. For instance,

DIDIER HOLLEAUX President Eurogas, Executive Vice President Engie and IGU Regional Coordinator.

the threat of a strike on some LNG facilities in Australia in September had a significant impact on the short term gas prices in Europe.

» Globally the short-term prices in Europe have hovered in the past months in the €30-40 per MWh range, far below the

Despite high levels of gas in storage, the risks of a potentially cold winter and a further cut in Russian gas supply mean that market volatility remains high. » As part of the fallout from the Russia-Ukraine conflict, gas supply to Europe remains severely constrained, with Russian pipe gas deliveries to the EU being restricted to 25 bcma currently, versus 140 bcma in 2021. This gas is flowing through Ukraine and Turkstream, and there is growing speculation

peaks of above €300 per MWh seen in 2022, but still about twice the usual level seen in 2010-2020. The projected price for 2024 of around €50 per MWh still shows that market players consider a high risk of an unbalance.

Consumption remains low, dented by last year’s high prices. There are fewer long-term LNG supply contracts being signed this year, and there are indications that the impact of the European Commission’s joint purchasing mechanism has been only modest..

about what will happen when Gazprom and Ukraine’s transit contract ends in December 2024.

» High prices and the low level of economic activity in many countries in Europe, some of which are suffering recessions,

» The drop in Russian flow has to a large extent been

mean that gas consumption remains 10-25% below the

compensated by extra LNG imports – around 50 bcma more

average of 2017-2021. This drop is the result of greater energy

than in 2021. That includes more LNG from Russia – some 15-

efficiency, voluntary reductions by customers looking to cut

20 bcma. Neither Russia nor its European customers seem to

their energy bills and avoid supply disruptions, and demand

be considering a cut in this supply, as LNG is a global market

destruction, in the form of some industrial plants closing down

and the redirection of Russian LNG to the Asian markets would

in 2022.

have a limited global impact (including on prices). On the other hand, it remains to be seen if Novatek can start Arctic-2 LNG

» After a wave of long-term LNG contracts dedicated to

plant as early as 2024/2025 and if such is the case, where

Europe were signed in 2022 and early 2023, the last six

these cargoes will go.

months have been quieter on this front, and it is clear that only a small share of the missing Russian supply has been replaced

» Due to a mild 2022/2023 winter in Europe and relatively low

with long-term LNG supply. More contracts may be signed in

demand in Asia, the LNG market in 2023 is not as tight as it

the coming month, but this slowdown in contractual activity

was in the previous year. LNG imports to Europe in July and

seems to signal a clear and deliberate choice by some utilities

August this year, for instance, were below the 2022 level.

to stick with supplies on a short-term basis. This choice can be explained by fears they have of having too much gas supply

» Europe has been able to refill its gas storage facilities to

after 2040, when EU gas consumption will probably decrease

very close to its maximum capacity, reaching 94% by mid-

sharply. European buyers are essentially accepting the price

September, surpassing the 90% by November 1 EU deadline.

risk over the volume risk.

European traders have also been storing some gas in the western Ukrainian underground storages.

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G LO B A L VO I C E O F G A S

» The so-called “joint purchasing mechanism” launched by the

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High prices and the low level of economic activity in many countries in Europe, some of which are suffering recessions...

European Commission was finally reduced to a “demand

of the players in this area anticipate that the EU 35 bcma

aggregation tool” (a kind of dating platform between

objective for production by 2030 should be overachieved.

buyers and sellers). It has been a success in terms of matching up buyers and new potential suppliers. But in terms of how many contracts were actually signed, its success appears modest, to say the least. The impact on prices or gas import volumes is imperceptible.

The expansion of gas infrastructure has practically eliminated physical constraints on LNG imports, while the outlook for biogas and biomethane production looks promising. » Enough FSRUs have been put in place in 2022 and early 2023 to practically eliminate any restriction to LNG imports into the EU. Nevertheless, some infrastructure (both pipeline and regasification) which were decided last year are still under construction, including some fixed onshore terminals in Germany to permanently replace the FSRUs. Some of these terminals will also be designed to import e-fuels, such as hydrogen, e-ammonia, e-LNG and e-methanol. This construction programme demonstrates that most European players consider that there will be no return to the statu quo ante of the pre-war gas market. However the conflict is resolved, the European gas industry needs to adjust to very limited gas flow from Russia and later significant imports of green gas from the

There remains intense legislative and regulatory activity affecting the European energy market. » The legislative and regulatory activity in Europe remains very intensive, with most of the texts of the “Fit for 55” and the gas and hydrogen packages of legislation coming to the final stage of decision-making. Electricity market reform is also still a hot topic for discussion.

» Regarding methane emissions regulation, the European gas industry is insisting that Europe alone cannot define rules for the whole world. We need to find a way for all importers to coordinate their efforts towards their suppliers to improve their performance. We also need an appropriate governance structure regarding methane monitoring, reporting and verification to avoid fragmentation of the market. In that regard, the initiative by the US Department of Energy to consult with European stakeholders on this topic is welcome.

» Finally, the proposal by the European Commission to transform a number of the emergency measures, adopted last year to face the energy crisis, into permanent tools

rest of the world.

has met a lukewarm reception by the industry, who

» Inside the EU, the construction of production plants

considers that emergency measures should be used only

for biogas and biomethane remains very dynamic. Most

in emergency situations.

O C TO B E R 2 0 2 3

G LO B A L VO I C E O F G A S

15

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The case for CCUS in decarbonising LNG A new report prepared for the Global Gas Innovation Roundtable concludes the suitability of CCUS as a decarbonisation option varies greatly across the supply chain, and greatly depends on geography, government policy and local industrial context. But it should be strongly considered as a potential solution.

JOSEPH MURPHY There is no one-size-fits-all option to decarbonising

There has been a rapid rise in development since then,

the LNG supply chain, but carbon capture storage and

however, with 30 commercial facilities up and running by

utilisation (CCUS) should be strongly considered as

September 2022 and nearly 90 pilot and demonstration

part of a suite of solutions, a report prepared by the

facilities completed. The report attributes this increased

Canada West Foundation for the Global Gas Innovation

momentum to technological advances, private and public

Roundtable, released in June, found.

sector climate commitments and favourable government

CCUS is widely recognised as critical to reaching a low-emissions future, including by the Intergovernmental

policy.

Today, CCUS is a technology that “has been

Panel on Climate Change (IPCC), the International Energy

demonstrated to be safe, effective and scalable,” the report

Agency (IEA), the UN Frame Convention on Climate

concludes. But it cautions that “substantial challenges exist

Change (UNFCCC) and the World Resources Institute

– both technical and financial.”

(WRI). And the technology is not new – since the 1920s

“As a result, the suitability of CCUS compared to

CO2 has been removed as waste from raw natural gas

other decarbonisation options (such as electrification or

when it is processed, and since the 1970s, captured CO2

fuel switching) depends greatly on specific circumstances

has been injected into oil reservoirs to boost recovery.

that are shaped by geography, government policy and

This said, only 10 commercial CCUS facilities were in

local industrial context,” it states. “The LNG industry

operation by 2010, with a combined capacity of only 13

faces immense pressure to reduce emissions quickly and

MT of CO2.

massively. As a proven technology that can be easily

O C TO B E R 2 0 2 3

G LO B A L VO I C E O F G A S

17

Figure 1

Source: CCUS as a Tool for LNG Innovation, prepared for the Global Gas Innovation Roundtable

integrated into LNG processes, producers should

therefore be cut through either pre- or post-combustion

strongly consider CCUS as part of a suite of solutions to

technologies.

achieve decarbonisation goals.”

Varied suitability

LNG shipping, which is technically feasibility but still at a very early stage of development, according to the report,

The suitability of CCUS as a decarbonisation solution

which cites a feasibility study and a pilot project carried

varies greatly across from the LNG supply chain, the

out by the Oil & Gas Climate Initiative (OGCI) on a Stena

report stresses.

bulk medium range tanker. The early conclusions from

The technology is particularly well-suited for natural

that research are that capital and operating expenses

gas processing, as CO2 has to be removed from gas

are a significant challenge, and so other decarbonisation

before it is liquefied at this stage anyway, and so there

options such as fuel switching or using sails to limit fuel

is little to no added cost. The only added cost relates to

needs are likely to be more suitable.

sequestering, which is why CCUS is already deployed

Even less suitable is transportation of gas, typically

or due to be deployed at many processing facilities

via pipeline, and at receiving, storage and regasification

globally.

infrastructure. Emissions from transportation usually

“There is a very strong value proposition for using

occur at small facilities like compressor stations that

CCUS for natural gas processing,” the report argues.

are spaced out across the transport route. As such, the

CCUS is also a good candidate for liquefaction,

report concludes that CCUS here is impractical. The IEA

because emissions at these plants are high and concentrated in a single location. The technology can

indicates that electrification is a better option.

Emissions from regasification are relatively low,

reduce emissions associated with liquefaction by as

making the case for CCUS weak. Furthermore, the

much as 90%, according to 2021 research by Edinburgh-

process is typically beyond the zone of control of LNG

based Wood Mackenzie. It can be deployed successfully

proponents, the report notes.

at a number of liquefaction plants globally, including at

The least applicable part of the supply chain for

Ras Laffan in Qatar, Snovhit in Norway and Gorgon in

CCUS is upstream gas production – where CO2 is emitted

Australia.

CO2 can be captured at liquefaction plants either

18

Then there are less than good fits for CCUS, such as

from dispersed well sites.

The report also emphasises that three quarters of

from the flue gas from gas turbines used to generate

emissions along the LNG lifecycle are associated with

power, or from emissions released from power

the end-use combustion of the gas, meaning this is

generation for the rest of the facilities. Emissions can

an “excellent fit” for CCUS, depending on geological

G LO B A L VO I C E O F G A S

O C TO B E R 2 0 2 3

conditions in the area. But these emissions are usually

providing direct or indirect support through different

outside the control of the LNG producer.

methods. The US for example primarily uses a tax credit, while EU support hinges mostly on grants and loans.

Government action

Indirect support can also come in the form of carbon

While the value of CCUS is clear, the report cautions

offset markets and support for the production of blue

that projects are still complex and expensive to realise.

hydrogen. Another option is the restriction or pricing of

The 5-MTPA Northern Lights/Longship development

emissions, as emitters will be willing to bear CCUS costs

in Norway that is set to begin operations next year, for

if they are lower than the tax or penalties they will avoid

example, will cost $1.6bn. This said, costs are falling

by adopting the technology.

On the legal front, governments can also support

thanks to the knowledge obtained from frontrunner projects such as Quest CCS in Alberta, Canada, whose

CCUS by developing frameworks to simplify the complex

developers estimate would have 30% less were it

questions over property rights and who owns or may

developed again. Recent studies demonstrate that the

access the spaces between rock particles under the

technology will be even cheaper and more efficient in

surface where CO2 can be sequestered.

the future, adding that further cost-savings will come

“The take-away message is that governments can use

from the use of shared infrastructure models that creates

a range of direct and indirect policy approaches to help

economies of scale, the report notes.

CCUS adoption,” the report said. “Given that CCUS is

Fortunately, governments recognise the high cost of initial technology deployment, and many are now

expensive, this support will likely be needed in almost all cases to make CCUS viable for LNG projects.”

The LNG industry faces immense pressure to reduce emissions quickly and massively. As a proven technology that can be easily integrated into LNG processes, producers should strongly consider CCUS as part of a suite of solutions to achieve decarbonisation goals.

About the Global Gas Innovation Roundtable O C TO B E R 2 0 2 3

The Global Gas Innovation Roundtable, established this year with support from the Canadian Gas Association (CGA), states that its mission is “to ensure that governments, policymakers, multilateral institutions and energy thought leaders have a greater understanding of the technology and innovation underway that will improve the performance – environmental and otherwise – of the gas sector.”

“It will raise the profile of gas technology and innovation through a variety of live and digital touchpoints, including the sharing of leading practices, highlighting emerging technology research and innovation, and profiling the array of events underway at any time around the world,” it says.

G LO B A L VO I C E O F G A S

19

LNG: going all-electric is a site-specific option All-electric drives are a key means of reducing LNG’s carbon footprint, but choosing the option depends on multiple factors, not least the availability of low carbon power to gain its full greenhouse gas (GHG) benefits.

ROSS MCCRACKEN

The Melkøya LNG plant in Norway was the first to install all-electric drive trains, which may surprise some

the incentive to reduce it to an absolute minimum.

Although the picture is muddied by sanctions, the

readers following the current debate over the plant’s

importance of reliability and reduced maintenance in

electrification. It already is electric.

remote locations will also have been a factor in Russian

Melkøya’s three electric drive trains have a total

LNG producer Novatek’s decision to transition to electric

installed capacity of 180 MW. Two drives for refrigeration

drives for the second and third lines of its Arctic-2 LNG

have 2 x 65 MW + 32 MW, while one drive has 16 MW for

project – despite the additional cost of having to build

nitrogen removal.

gas-fired plant to power them.

The decision by the Norwegian government in August to support the plant’s connection to the grid concerns the

Reliability benefits

source and carbon footprint of the electricity consumed

A typical gas turbine has a minor maintenance period

by the plant.

of about 4,000 hours and a major maintenance cycle

The reasoning behind the decision to go all-electric

of 20,000 hours, while an electric drive has minor and

was based on the higher efficiency, flexibility and

major maintenance periods of 25,000 and 100,000

reliability of electric drives, compared with directly-

hours respectively. In addition, the minor maintenance

coupled heavy-duty gas turbines. Melkøya island is in the

downtime for gas turbines is typically 6-10 days versus

far north of Norway 480 km above the Arctic Circle close

1-2 days for electric.

to the source of its gas feedstock in the Barents Sea. The

Gas-powered drives also lose efficiency as

remote location means that both planned and unplanned

temperatures increase, whereas electric drives do not. In

maintenance is difficult and time consuming, increasing

Qatar’s megatrains, Siemens ROBICON Perfect Harmony

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G LO B A L VO I C E O F G A S

21

Figure 2: Electricity generation in Australia, 2022 (TWh)

Figure 1: Electricity generation in Norway, 2022 (TWh)

0.3 0.3

3.8

5 17.1

14.8

Hydro

46.3

Solar

Hydro

38.8

Solar Wind

Wind

Other RES

31.7

Other RES

Coal

Conventional Sources

130.9

127.6

Oil

45-MW variable frequency drives are used to moderate

plant, including carbon capture and storage (CCS), but

the performance of the gas turbines, adding additional

eventually found that because of the cost of integrating a

power in hot summer temperatures and returning excess

new CCS unit, additional electrification provided the best

power generation in winter to the grid.

emissions reduction pathway. The reasoning is important

Throw in the higher efficiency of electric motors

because new LNG plants can be designed in which

over a wide range of operations, and the utility of

CCS is an integral part of the engineering, reducing the

vertical shaft drives in quickly fine tuning operations to

complexities of retrofitting.

requirements, and the advantages of being all-electric start to mount up.

Carbon footprint However, how the electric drives are powered is critical when carbon emissions are concerned.

Open cycle gas turbines (OCGTs), which might be

As a result, Equinor is backing a solution in which the gas-fired power plant which currently supplies power to the plant is shut down and electricity is sourced from the grid.

Low carbon grid power This highlights another location-specific condition.

the preferred option in terms of capital cost and speed

Norwegian grid electricity is very low carbon because

of deployment, typically produce about 0.52 tonnes of

of the dominance of hydro power (see figure 1). In 2022,

CO2/MWh of electricity generated. Opting for combined-

hydropower provided 87% of the country’s electricity

MWh, a considerable reduction in emissions.

Norway generally has surplus power, exporting 25.8

cycle gas turbines reduces this to around 0.34 t of CO2/

Putting it another way, German engineering company Siemens estimates that the use of industrial OCGTs can result in CO2 emissions as high as 250 kg/t of LNG

produced. This can be reduced to a range of 6-190 kg/t of LNG, if conventional power facilities are coupled with

with a further 10% accounted for by wind. In addition, TWh in 2021, although last year it had to consider suspending exports because of low reservoir levels.

These near-optimal conditions in terms of low carbon grid electricity supply are not prevalent everywhere.

The abundance of hydro power in British Columbia

renewable energy and battery storage systems. The

was also a clear factor in LNG Canada’s decision to

latter provides instantaneous response in the event of a

employ electric drives and grid electricity, as it is for the

deviation in power supply to provide the reliable power

smaller 2.1mn t/yr Canadian Woodfibre project. LNG

required by an LNG plant.

Canada phase one is under construction and hopes to

At Melkøya, operator Equinor evaluated a number of options to reduce emissions and extend the life of the

22

Gas

3.2

G LO B A L VO I C E O F G A S

start shipping LNG within two years, while construction on Woodfibre officially began in August. The use of

O C TO B E R 2 0 2 3

electric drives supplied by renewable power will mean

propane refrigeration compressor’s rotation speed can be

low carbon LNG production for both projects.

adjusted without affecting the compressors since they are

Although it will require upgrades, Woodfibre has

not coupled to the same driver.

an electricity connection already in place as it is using

The use of grid power means that Freeport LNG’s

a repurposed industrial site for its LNG plant. However,

carbon footprint is tied to that of the US grid. It also

while LNG Canada has secured power for the first phase

means outsourcing the reliability of electricity supply to

of its project, a second phase expansion has thrown up

US utilities and transmission system operators, an option

new issues.

which might cause concern in countries with low grid

Utility BC Hydro does not have sufficient transmission capacity to supply the expansion. Moreover, LNG Canada

reliability.

is not the only industrial project in the Canadian northwest

Grid carbon intensities

keen to source renewable energy to keep its activities as

The US Energy Information Administration (EIA) has

environmentally friendly as possible.

highlighted the huge GHG emissions benefits which

The dilemma over the availability of renewable power

have resulted from the US power sector’s coal-to-gas

highlights the interconnectedness of the energy transition.

switching. Further reductions in the carbon intensity of US

For LNG plants to produce low carbon LNG, more

grid power seem certain as coal-fired generation declines

renewable power is needed and in the right place, which

and the amount of renewable energy capacity increases.

can often mean new power transmission infrastructure.

In May, the EIA presented its Annual Energy Outlook

BC Hydro has opened consultations with stakeholders on

2023, which posited three scenarios in which coal-fired

its North Coast Electrification plans and LNG Canada has described conversations with government and the utility as encouraging.

Low carbon power provision Power availability was one reason why Freeport LNG in the US opted for all-electric drives to build what is the world’s largest such LNG facility, while at the same time meeting strict local environmental rules, including GHG emissions standards. GE Power Conversion was selected to provide the all-electric drives for the plant’s three LNG trains refrigerant compressors. The plant has a total installed electrical capacity of 675 MW. Each of the nine systems provided by GE Power Conversion has a 75 MW 2-pole synchronous motor, the largest ever supplied to an LNG plant, a 96 MVA step down transformer and an ‘e-house’ with ancillary electrical equipment. GE Power Conversions estimates that the electric drives resulted in a reduction in site combustion emissions of 90%, as well as a net increase in production of 6.5%, as the use of electricity allows all of the gas entering the site to be used for LNG. It also estimates that because of the higher reliability of operation and reduced maintenance requirements, the LNG plant can produce the equivalent of an extra 1015 days a year, compared with the use of conventional industrial gas turbines.

The design employed separates control of the two refrigeration loop compressors from each other, and the

O C TO B E R 2 0 2 3

Power availability was one reason why Freeport LNG in the US opted for all-electric drives to build what is the world’s largest such LNG facility, while at the same time meeting strict local environmental rules, including GHG emissions standards.

G LO B A L VO I C E O F G A S

23

There is no onesize-fits-all option for decarbonising LNG production, but electrification is among an array of possibilities that operators can consider.

generating capacity falls by between 52% and 88% by 2050. Renewable power capacity increases hugely, the

In addition, almost 50% of power in Australia is still

overall result being significant declines in the carbon

generated from coal (see figure 2). Hydro and other

intensity of US grid power, which will feed through into

renewables make up a third of power generation,

the carbon footprint of grid connected all-electric US

although wind and solar generation are expanding.

LNG plants.

Grid power is and will continue to become less carbon

However, this possibility is by no means universal.

intensive, but doesn’t currently offer the emissions

Australia has some of the world’s highest emission LNG

reductions which will benefit LNG Canada, WoodFibre

plants. This reflects, for some projects, the high CO2

and Melkøya.

in transmission, which requires energy-intensive

the emissions gains depend heavily on location and the

compression.

specifics of each LNG plant, as well as the availability of

content of the gas supply and the distances involved

As it stands, going all-electric is a good option, but

For new projects, the adoption of electric drives

reliable, low carbon grid power. As is always the case,

would cut emissions, but not solve the problem of high

there is no one-size-fits-all option for decarbonising

CO2 content gas. The latter might better be dealt with by

LNG production, but electrification is among an array of

a single carbon storage option for both feedstock stream

24

CO2 and combustion-related emissions.

G LO B A L VO I C E O F G A S

possibilities that operators can consider.

O C TO B E R 2 0 2 3

Decarbonization Solutions for the Full Supply Chain

chartindustries.com howden.com

Veritas: a consistent approach to measuring methane GTI Energy and its par tners are honing a set of standardised, science-based, technology-neutral protocols for the natural gas industry to get a true measurement of methane emissions.

JOSEPH MURPHY For the last two years, US not-for-profit GTI Energy has been collaborating with dozens of operators across the natural gas supply chain along with other stakeholders – from academics and environmental NGOs to investors, policymakers and technology providers – to develop a consistent approach to measuring and verifying methane emissions.

The result of this labour was the release of the Veritas protocols in February this year. These standardised, science-based, technology-neutral and measurement protocols are designed to assemble methane emissions inventories that are verified by direct field measurements, in turn helping the industry address those emissions. By the end of this year, GTI Energy aims to publish a version 2.0 of the protocols, informed by increased testing and analysis, which Amanda Harmon, GTI Energy’s senior manager that is directing the initiative, expects will be close to the final version.

“Veritas provides a means of getting a measurementinformed methane emissions intensity for segments across the natural gas supply chain,” Harmon tells Global Voice of Gas. “The goal is to provide a transparent operational tool for companies along that chain, a means for

O C TO B E R 2 0 2 3

developing a methane emission intensity value based on their measured methane emissions detected by available tools and technologies that are out there.”

The protocols cover six segments of the supply chain: production, gathering and processing, transmission and storage, LNG and distribution.

The first protocol, is Measurement, describes how to take measurements to inform emission inventories by segment. Methane Intensity defines what methane intensities should look like for each segment of the natural gas supply chain. Reconciliation reconciles emission-factor or bottom-up inventories – namely those available under the US Environmental Protection Agency (EPA)’s Greenhouse Gas Reporting Programme – with actual measurements by segment. The fourth, Supply Chain Summation, brings together estimates from multiple segments to calculate an overall emissions intensity for the supply chain. The fifth and final protocol is Assurance, which provides guidance for verifying an emissions inventory, company documentation requirements and third-party auditing.

Veritas is designed to support companies in using various reporting and emission reduction frameworks,

G LO B A L VO I C E O F G A S

27

Production

Processing Gathering & Boosting LNG

Collaboration with the gas industry and other stakeholders has been critical for establishing the Veritas protocols.

Transmission Storage

such as the Oil and Gas Methane Partnership (OGMP) 2.0 initiatives, and differentiating their gas supply based on its emission intensity, so that they may market their gas as responsibly-sourced.

“The missing piece of the puzzle for OMGP 2.0 is how you can create standardised, measurement-based information for source-level emissions,” Harmon explains, and filling this gap is a current Veritas workstream.

The technology-neutral approach of the protocols is key, she says.

“We wanted to keep an open mind on which measurement technologies are best to use for each segment and support new technologies coming to the market,” she says.

The protocols ensure that the methane emission intensity estimate is informed by requiring that at least half of the methane emissions are measured directly, and having a technology-neutral approach is necessary to achieve this.

Collaboration is key

Collaboration with key players in natural gas and other stakeholders has been critical for establishing the Veritas protocols.

“There’s such a wealth of knowledge across the industry in this space, from the operators to other external stakeholders, whether it be academics, consultants, or others,” Harmon says. “Those perspectives were incredibly important to developing the protocols; we did not want to create Veritas in a vacuum that would only be suitable for one type of operator or one type of segment. The need and impact should be

28

G LO B A L VO I C E O F G A S

Distribution

much larger than that, so that the protocols can be used not just by operators but also external stakeholders, whether it be an environmental NGO or a regulator or an investor.”

The natural gas industry has been “incredibly supportive” in developing the protocols, she says.

“They recognise there are a lot of tools and technologies out there, and how they can best operationalise them is something the industry is very willing to put the effort into, in terms of their time and resources.”

Veritas currently has 37 partners, representing the entire natural gas value chain, and external stakeholders.

Besides GTI Energy, Highwood Emissions Management and SLR International are also leading the initiative. A handful of companies have already implemented the protocols, but Harmon hopes that momentum will build in 2024 after Veritas 2.0 is published this December.

“We’re aiming for Veritas to live through these different other initiatives, whether they are single-company corporate reporting of emissions, an international government-aligned methane measurement verification framework or an emission reduction, corporate reporting framework like OGMP 2.0,” she says. “That’s our aim and we anticipate that that will take only a couple more years, given the momentum in this space.”

“In this rapidly evolving space of methane emissions measurement, it’s important to be transparent and to provide the ‘how to use’ for these technologies to create a measurement-informed methane intensity estimate.

The data is coming through these technologies and the Veritas protocols really help us move towards what our understanding of methane emissions are.”

O C TO B E R 2 0 2 3

Successfully Producing LNG for Over a Half-Century From Kenai first producing and importing LNG to Japan in 1969 to starting up 17 new large-scale LNG trains on-time in Australia and the U.S. Gulf Coast over the past eight years, the Optimized Cascade® process provides more than 110 million metric tons per year of the world’s LNG supply capacity and is licensed in 27 trains around the world.

The Optimized Cascade® process: Proud past, bright future We Deliver: • Industry-leading performance, efficiency, and operational flexibility • Predictable execution, startup and operation • Scalable train design from 1.5 to 7 MTPA • Wide feed gas composition capability

The Optimized Cascade® process now provides more EPC Contractor choices for our clients To learn more, visit lnglicensing.conocophillips.com.

Optimized Cascade® is a registered trademark of ConocoPhillips Company in the United States and certain other countries.

23-0569 © 2023. ConocoPhillips Company. All rights reserved.

Liquefied Natural Gas

What is e-methane? e-methane is one of the ways Japan can achieve a seamless transition to a decarbonised society, lowering emissions while supporting stable energy supply and making use of existing gas infrastructure.

The Japan Gas Association (JGA) announced in November 2020 its “Carbon Neutral Challenge 2050”, to take on the challenge of decarbonising Japan’s city gas by 2050, followed by the release of its “Carbon Neutral Challenge 2050 Action Plan” in June 2021.

In the “Action Plan,” the JGA has established a roadmap for achieving carbon neutrality by 2050 through a thorough transition to natural gas and advanced use of natural gas in the transition period, as well as the development of decarbonisation technologies, the introduction of “e-methane” through methanation, and the use of biogas and hydrogen.

This article describes what e-methane is, how it works, and the challenges involved.

What is e-methane?

The synthesis of methane by adding captured carbon dioxide to hydrogen is called “methanation.”

In other words, “methanation” is a form of hydrogen utilisation technology and an important means of decarbonising gas. Methane produced by methanation

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G LO B A L VO I C E O F G A S

KOKI HAYAKAWA, SECRETARY GENERAL AND SENIOR MANAGING DIRECTOR OF THE JAPAN GAS ASSOCIATION

is generally referred to as “synthetic methane,” which is called “e-methane.”

How does e-methane work?

The feedstock CO2 is captured from flue gas of fuel combustion site, biogas mix, or atmosphere and used for producing e-methane. Therefore, even if CO2 is emitted

during combustion, the amount of CO2 in the atmosphere is not increased, contributing to carbon neutrality.

Why is e-methane one of the most practical pathways to decarbonised gas supply?

In Japan, heat energy accounts for about 60% of energy consumption in residential, commercial and industrial sectors. The range of heat that can be produced with gas is very wide, and can reach much higher temperatures than can be produced by heat pumps. Conversely, the decarbonisation of such heat energy is very important to achieve carbon neutrality in the future.

O C TO B E R 2 0 2 3

In addition, since the main component of natural gas is methane (CH4), e-methane can make use of existing LNG shipping facilities and other equipment as same as natural gas. And, gas users can continue to use gas appliances without additional investment.

In addition, Japan is prone to earthquakes and other natural disasters such as typhoons and floods, “safety” is a prerequisite, and past experiences of earthquakes and other natural disasters have proven that the existing gas infrastructure is highly resilient. By using the technology, we can help improve resiliency and contribute to stable energy supply by producing e-methane using recycled carbon and renewable energy such as green hydrogen.

Based on these benefits, the JGA has set 2030 and 2050 targets for the gas industry as a long-term roadmap for e-methane utilisation: more than 1% of e-methane injection into city gas pipelines in 2030 and 90% in 2050.

Why is Japan interested in this technology?

During the transition period leading to the creation of a decarbonised society in 2050, it is important to promote

O C TO B E R 2 0 2 3

a thorough low-carbon transition, reducing carbon emissions without disrupting energy supply.

Therefore, we believe that we can contribute to a seamless decarbonisation process by promoting societal adoption of e-methane and gradually switching from natural gas to e-methane, while working on the effective use of natural gas and the development and expansion of high-efficiency, high-value-added gas systems.

Is there another way besides e-methane?

To achieve carbon neutral gas supply, we consider various options, not limited to e-methane, and the direct use of hydrogen is among them.

The direct supply of hydrogen in areas such as coastal industrial complexes is assumed mainly through the construction of new social infrastructure such as hydrogen pipelines.

As for hydrogen, in addition to infrastructure cost issues, there are also handling difficulties, especially when transporting liquefied hydrogen from overseas to Japan in the form of liquid hydrogen, which requires a lot of energy to liquefy it once to a temperature below

G LO B A L VO I C E O F G A S

31

In Japan, which is prone to earthquakes and other natural disasters, “safety” is a prerequisite, but past earthquakes and other natural disasters have proven that the existing gas infrastructure is highly resilient.

-250°C and a more highly rigid storage tank compared to those used for LNG. To address these issues, we believe that Japanese gas companies can take advantage of the technology and know-how they have accumulated by handling LNG. In addition, biogas emits CO2 when it is combusted,

but it is a clean energy source because it absorbs CO2 while the origin of biogas grows up, and we believe that the supply of city gas using excess biogas generated from waste and sewage treatment plants and food factories is an important option.

What are the challenges for the social implementation of e-methane?

For the social adoption of e-methane, it is necessary to increase the capacity of plants and develop technologies that contribute to the reduction of production costs, and various efforts are currently underway.

In Japan, INPEX Corporation has successfully demonstrated the production of 8 Nm3/h of e-methane from 2017 to 2021. Currently, INPEX Corporation and Osaka Gas Company are collaborating to prepare for a methanation demonstration at a scaled-up plant from FY2025. The production capacity of the methanation plant to be developed under the project is planned to be approximately 400 Nm3/h. Design studies for 10,000 Nm3/h and 60,000 Nm3/h plants will be conducted in parallel.

In March 2022, Tokyo Gas launched a demonstration project in cooperation with the city of Yokohama to utilise CO2 from incineration plants and biogas from sewage treatment plants.

In addition, the research and development of innovative methanation technology, which is expected to further improve efficiency and reduce costs, is being conducted mainly by major gas utilities with the financial support of government.

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G LO B A L VO I C E O F G A S

There are three other non-technical issues that need to be resolved: (i) the development of CO2 counting rules, (ii) the establishment of an environmental value trading mechanism, and (iii) the establishment of financial support measures based on cost differences (introducing a mechanism to compensate for cost differences based on purchase price differences between e-methane and LNG).

Regarding “(i) the development of CO2 counting rules”, e-methane does not increase CO2 emissions because it only circulates CO2 in the atmosphere, but there are no accounting rules of the emitted and captured CO2.

Clear rules need to be established to promote the use of e-methane.

Also, the rules for counting CO2 when e-methane produced with CO2 capture in one country is consumed in another country have not been finalised at this time, so internationally harmonized rules will need to be developed in the future.

Regarding “(ii) Environmental value trading mechanism”, a certification system is needed to identify e-methane when it is blended with natural gas for supply.

Regarding “(iii) Support measures based on cost differences”, it is considered necessary to introduce compensation mechanism for cost differences, as there will be a price difference between e-methane and LNG to encourage first mover at the beginning stage.

Japan’s city gas industry is working with the public and private sectors, domestic and international initiatives, to address these issues by promoting technology development through demonstration projects, establishing CO2 counting rules and environmental value trading mechanisms, and building appropriate support systems, and will continue to accelerate these efforts.

Regarding these issues, the declaration of intergovernmental cooperation to promote e-fuels and e-methane in the G7 Climate, Energy and Environment Ministers’ Communiqué at Sapporo (Japan) in April 2023 is one of the significant steps forward.

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Decarbonisation of LNG Figure 1: LNG versus fossil fuels Natural gas and LNG are among the cleanest fossil fuels, even when accounting for precombutistion emissions

Emissions factor by fuel, gCO2e/MJ1

Emissions factor by fuel, gCO2e/MJ1

230.8

~130.0

100.8 79.3

76.5

56.8

89.6 ~10.0

~20.8

NG/LNG Combustion

Fuel Oil

Coal

NG/LNG

Fuel Oil

Coal

Precombustion

Source: McKinsey

The energy transition is the shift in the operations and processes in the global energy sector from fossil-based, high carbon emission systems of energy production and consumption — including oil, natural gas, and coal — to renewable, minimal or “net zero” emission energy sources such as wind and solar, complemented by energy storage, such as lithium-ion batteries. The world is increasingly committed to a 1.5-degree pathway, which refers to mitigating climate change through decarbonisation to limit warming to 1.5°C by 2050 , and to keep temperature

changes “well below” 2.0°C above pre-industrial times.

Among traditional fossil fuels, natural gas as liquefied natural gas (LNG) is the lowest carbon fuel currently available to shipping at scale today, reducing greenhouse gas (GHG) emissions by up to 23% (well-to-wake) compared to Very Low Sulphur Fuel Oil. This is illustrated in Figure 1.

The carbon footprint of LNG (Liquefied Natural Gas) is a measure of the greenhouse gas emissions associated with its production, transportation, and use. Carbon

1 Governments had previously agreed to act to avoid global temperature rise going above 1.5 C. As of 2023 the world has already warmed by 1.1C and now experts say that it is likely to breach 1.5C in the 2030s. The focus now will be on coming back down as quickly as possible after overshooting the 1.5 degree C mark.

This article is brought to you by The National Gas Company of Trinidad and Tobago Limited (NGC).

The opinions and views expressed in this article do not necessarily reflect those of the IGU or the publisher.

emissions are released through the combustion of gas to drive the liquefaction process and any carbon dioxide removed before entering the plant is often vented into the atmosphere. As a result, global efforts are underway to reduce the overall carbon impact of LNG use as it is a transition fuel and will be part of the global energy mix for decades to come. However, with transition and the demand for cleaner fuels, the demand for cleaner LNG will only grow, with the carbon footprint of LNG cargoes set to potentially become a differentiator for buyers and sellers. In fact, these are early days for ‘carbon-neutral’ or so-called ‘green’ LNG, as seven such cargoes have been delivered or agreed, all to buyers in Asia, with more understood to be under discussion.

That said, ‘carbon neutral’ does not mean that the LNG cargo creates zero emissions. Instead, what it means is that the carbon emissions associated with the upstream production, liquefaction, transportation and, if required, combustion of the gas, is then measured, certified, and offset through the purchase and use of carbon credits, which support reforestation, afforestation or other renewable projects. Switching to natural gas has already helped to limit the rise in global emissions since 2010, alongside the deployment of renewables, improvements in energy efficiency, and the relooking of existing technologies such as nuclear energy.

Pragmatically, the main opportunity to reduce liquefaction emissions in LNG is with feed gas, as roughly 8% to 12% of feed gas is used for electricity in the LNG

plant and for fuel in the liquefaction process. As such, higher efficiency plant designs or using renewable energy to replace feed gas can help to reduce emissions and decarbonise the LNG coming out of plants at an individual level. In the upstream, the largest opportunity for decarbonisation is in reducing CO2 venting. This creates a potential opportunity for carbon capture and storage, which could cut emissions by as much as 25%. Globally, several LNG projects — including Snohvit in Norway, Gorgon in Australia, and Qatar’s North Field projects — are exploring this option, although it remains expensive.

Longer term solutions that involve decarbonisation are via technology through solutions such as carbon-neutral biogases and carbon-neutral synthetic gas, carbon capture, use and storage and the incorporation of hydrogen.

Within Trinidad and Tobago, efforts have been focused on reducing methane emissions and reducing the wastage of gas molecules via reducing flaring upstream and minimising emissions in the upstream, maximising the efficiency of throughput from the LNG trains, and greater emphasis on asset integrity management and risk mitigation at LNG production installations. As LNG demand continues to grow in the medium term, future contracts may likely require that all LNG cargoes come with detailed information about the emissions associated with their production and delivery, along with evidence of supplier carbon credentials.

This article is brought to you by The National Gas Company of Trinidad and Tobago Limited (NGC).

The opinions and views expressed in this article do not necessarily reflect those of the IGU or the publisher.

PACHITEA SUB-BASIN The Shira Mountains divide the southern part of Ucayali basin into a larger eastern por�on that is depicted in Figure 1, and a western por�on that includes the Oxapampa/Ene fold and thrust belt and the Pachitea sub-basin. The eastward leading edge of the Oxapampa/Ene segment is defined by the San Ma�as Fault, which trend roughly NNW. This sub-basin in turn terminates into an older basement cored upli� trending North, the Shira Mountains, where the thrust belt collides with the Shira Mountains, south of the Oxapampa wells.

Related to the petroleum system, in the Sub-Andean Basins of Peru, based on TOC and Rock-Eval data, numerous forma�ons from Ordovician age to the Ter�ary can be iden�fied as poten�al source rocks in the sub-Andean Basins of Peru. However, in the Pachitea Sub Basin could be as follows:

PALEOZOIC • • •

Figure 1.

Regional map showing the Pachitea Sub Basin and the main oil and gas evidences of the petroleum system in the area. Regional cross sec�on in blue.

Late Permian Ene Forma�on is an important contributor in the Madre de Dios Basin and Bolivia further to the south.

Ambo/Tarma-Copacabana Forma�ons with marine shales and carbonates in the southern por�on of the Ucayali Basin. The Ambo has sourced the giant gas/condensate fields of the Camisea Area.

Ordovician Contaya and Devonian Cabanillas Forma�ons have extreme maturity and moderate present-day TOC values in the SE Marañon, and like the Permian source are important contributors in the Madre de Dios Basin and Bolivia.

TRIASSIC/JURASSIC •

Pucará Group is a bituminous carbonate with interbedded organic rich shale sec�ons;

THE PROVEN RESERVOIRS IN THE AREA • • •

Ene Forma�on (Lower Permian) Cushabatay Forma�on (Lower Cretaceous) Vivian Forma�on (Upper Cretaceous)

Figure 2.

A) Regional Structural cross sec�on in the Pachitea Sub Basin across the San Ma�as and Shira Mountains. (see loca�on in Figure 1) B) 2D petroleum system model from the previous sec�on (Modified from PERUPETRO, 2019)

The most attractive area in Ucayali Basin is within the fold and thrust belt along its entirety but particularly, in the area of the Oxapampa wells where a considerable gas column has already been discovered in one of the wells as it presented in Figure 2. In the foreland, there are still a large number of undrilled structures. The final point to emphasize is that this area has multiple, mature source rocks and there apparently has been large quantities of oil and gas migrating through the system as evidenced by the numerous shows in most of the wells drilled in the area.

Policy is key for supporting LNG supply: MidOcean Energy CEO Policy is critical for encouraging more investment in global LNG supply to keep up with demand, while also driving reductions in greenhouse gas emissions, De la Rey Venter, CEO of LNG player MidOcean Energy, tells GVG.

DE L A REY VENTER, CEO, MIDOCEAN ENERGY

JOSEPH MURPHY

Investment in global LNG supply has accelerated postpandemic and the industry now finds itself in an “optimum weather pattern,” De la Rey Venter, CEO of LNG player MidOcean Energy, tells Global Voice of Gas. But he warns that a supply gap is set to reemerge around the end of the decade, urging policymakers and other stakeholders to do more to keep the investment flowing.

Demand has recovered and high prices are making supply projects more attractive, and there is also more political support for LNG than in a long time, he says.

“This has unleashed a primarily US and Qatari supply side response at a very large scale,” he says. “What that means is that over the medium term we will likely be quite reasonably supplied. But when you look out to the end of the decade, the supply gap opens up again and it becomes quite a yawning gap as we go towards the mid-2030s. We are fast moving out of the current optimal weather system.”

There is not much to look at in terms of sanctioned new supply projects outside North America and Qatar, he notes, citing permitting issues, political risks and

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challenges with execution. The window of time to avoid the looming supply gap by greenlighting new projects is closing, he says.

“If a project has not reached FID by 2025, it’s not going to be on stream by 2030.”

Importantly, new supply projects are not only needed to keep up with demand growth but also make up for falling production at existing fields, he notes. And this will become an even bigger issue going into the 2030s. There is enough gas in the ground to fuel demand for decades to come, he says, but development must happen faster.

MidOcean, owned and managed by US investment firm EIG partners, is working to build up its own portfolio of LNG projects – it is currently in the process of acquiring interests in four Australian developments. This strategy got an important vote of confidence in late September, when Saudi Aramco struck a deal to acquire a minority stake in MidOcean for $500mn. Aramco has an option to expand that interest in the future, under the agreement.

Generally, it is getting increasingly hard for the LNG industry to secure financing, and that financing it can

G LO B A L VO I C E O F G A S

37

obtain is getting more expensive, according to Venter.

What can policymakers do? Their role is critical for unlocking more investment, he says.

“Policymakers are very much key to this question.

Investment in gas supply is stimulated by pragmatic policies – policies that acknowledge the long-term role of gas as an enabler of the energy transition, that signal the expectation of sustained gas demand over time at reasonable prices.”

On the other hand, when policymakers shun the value of gas, arguing that it will only be needed for another decade or so as the world moves on with its decarbonisation efforts, that feeds into buyers’ decisions.

They become less confident about committing to supply on a long-term basis, and this in turn means less capital is available for supply, Venter explains. This is what was seen in the late 2010s, he says, resulting in the global energy crisis we have today.

“These were well-intended but ultimately poorly considered messages from some policymakers. I am a big believer that in this whole equation between policy, money and the industry, it is policy that is the critical one.

It needs to be at the very least pragmatic, and not hostile to gas.”

All this is vital for achieving an orderly and affordable energy transition, he says, and not one that is “chaotic, painful and costly.” While policy has become more pragmatic in response to the energy crisis, this is only a “half-step – in the right direction but not enough to be a catalyst for long-term energy supply at the scale required.”

Targeting emissions

The other important role of policy is encouraging reductions in greenhouse gas (GHG) emissions associated with LNG supply. This should involve addressing GHG intensity at both new and existing LNG plants, using a “carrot and stick” approach, he says.

“Critically, policy should also incentivise the development of a whole array of gases such as hydrogen and ammonia that today are substantially lower carbon than conventional energy,” he says. “It is only policy that can play this catalyst role.”

He laments that in recent years some financial institutions have responded to environmental social governance (ESG) pressure by scaling back funding for LNG. On the other hand, he praises other financiers that “understand the bigger picture” – that gas is needed as a reliable baseload energy supply to underpin the energy transition. Those financiers have responded to ESG pressure by becoming more selective of which projects they invest in, based on how well they are addressing their

38

G LO B A L VO I C E O F G A S

But when you look out to the end of the decade, the supply gap opens up again and it becomes quite a yawning gap as we go towards the mid2030s. We are fast moving out of the current optimal weather system.

DE L A REY VENTER, CEO, MIDOCEAN ENERGY

environmental footprint.

Customers are another critical part of the equation, he says. They should focus on working with suppliers that effectively and transparently quantify their emissions and have those estimates verified.

“Customers should become a whole lot more discerning about the greenhouse gas intensity of the LNG they buy than they are today,” he says. “We’re in a world where, because of the supply shocks, the price or security of supply is sometimes all that matters. But in time it must be supplemented with customers positively discriminating between different sources of energy based on their greenhouse gas intensity. That also means of course a willingness to reward those suppliers that do their best.”

The LNG industry has come a long way in addressing its emissions over the years, Venter says, but there has been a failure to come up with one agreed standard for measuring, reporting and verifying emissions. There are over two dozen emissions initiatives and coalitions around the world, “but what we need is one, unified approach,” he says.

The good news is that LNG suppliers now enjoy a wide array of options for decarbonising their operations.

Electrification has come down in cost, and retrofitting plants to run on renewable power is becoming increasingly viable, he says. Carbon capture and storage (CCS) is an option worth considering, depending on local conditions.

In other words, a lack of options is no longer the prime constraint, he says. He calls for a higher and predictable carbon price to drive the adoption of these decarbonisation options. But once more, it also falls on customers to demand lower-carbon LNG. When it comes to lower-carbon gases, Venter does not see much synergy in terms of infrastructure and supply chains between LNG and hydrogen and ammonia. On the other hand, synthetic LNG represents “perfect compatibility with existing infrastructure, from liquefaction to final use.”

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Natural gas has delivered for Israel Israel is now marking a decade since its natural gas revolution. Gas development over that time has generated significant economic value, while reducing emissions through the substitution of coal and other polluting fuels and shielding the country from the havoc wreaked by the global energy crisis.

YOSSI ROSEN, CHAIRMAN OF THE BOARD OF THE ISRAEL INSTITUTE OF ENERGY AND ENVIRONMENT

The global energy market endured the biggest shocks in a generation in 2022. Global natural gas prices soared to unprecedented heights, leading to a dramatic spike in electricity prices. Most countries felt the shock, but Israel was one of the few countries to weather this storm virtually unscathed, exhibiting remarkable resiliency in the face of this global upheaval. This was a direct outcome of Israel’s natural gas revolution, which produced unprecedented accomplishments – in terms of the economy, welfare, the environment, and geostrategy.

The dramatic energy crises that beset the global energy market these past years have proven that global reductions in greenhouse gas emissions are only possible if they occur along with the strengthening of the local and global energy security landscape.

Achieving this, while 83% of the world’s population lives in non-OECD countries, is a daunting challenge. Percapita energy consumption in these countries is one-third

40

G LO B A L VO I C E O F G A S

that of OECD countries. The number of people living in energy-starved poverty worldwide far exceeds the entire population in the OECD. Rich industrialised countries are able to endure, albeit at a heavy economic cost, the energy supply chain issues.

However, it is the citizens of the non-OECD countries that have been bearing the brunt of the cost of this crisis. They are unable to pay the surging energy bills, they suffer from severe shortfalls in energy and electricity supply, and are even resorting to severely-polluting energy sources such as coal.

Natural gas has the advantages of enabling a greenhouse gas reduction process while at the same time strengthening local and global energy security – first through expanding the global natural gas supply infrastructure, and then by using this infrastructure for the purpose of CO2-free gases.

Israel is now marking a decade since its natural gas

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Natural gas reduces cost-of-living

145

A reduction of 85% in the intensity of SO2 emission intensity and 76% in the intensity of nitrogen oxide emissions*.

EU -27 +40-% 100ag/kwh

135

0.016

125 115 105 95

Israel -11% 57ag/kwh

85 75 2013

2014

2015

EU

2016

2017

2018

2019

2020

2021

2022

Israel

S02 Emissions /KWh

Rate of Change of Household Electricity Prices Base year 2013

In the past decade the price of electricity for Israeli households has dropped by 11%, compared with a 40% increase in Europe.

The economy saved NIS190bn ($47.2bn) as a result of dramatic reduction in pollutant emissions intensity

85% emission intensity reduction of NIS71.2 billion in pollution

0.014 0.012 0.010 0.008 0.006 0.004

Contribution of renewables

0.002 0 2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

The rate of chance of electricity prices in Europe is based on BDO analysis and Eurostat data; the rate of change of electricity prices in Israel is based on IEC data.

The prices include taxes and subsidies. Prices in local currency. Average prices (2013 to mid-2022). The increase in electricity prices in Israel over the past two years derives from the increase in price of imported coal.

*Not including savings from emissions intensity Source: BDO analysis of electricity economy reports by the Electricity Authority and the Ministry of Environmental Protection “Green Book”.

revolution, which began with the sizable production and use of natural gas in 2013. A special report from the economic consultancy BDO, written jointly with the Association of Oil and Gas Exploration Industries in Israel, A Decade of Israel’s Natural Gas Revolution, has recently been published and has gained considerable attention. The report reviews Israel’s natural gas revolution this past decade in terms of the benefit and value aspect over several critical areas critical to any country.

bcm in 2023. Israel’s natural gas production during the same period grew from 2 bcm to 22 bcm. Israel has developed an annual gas production capacity of 30 bcm within less than a decade thanks to the development of three separate offshore gas production and gas delivery systems, independent from one another – from the Tamar, leviathan and Karish gas fields – in 2013, 2019 and 2022 respectively.

Israel’s power generation sector has been dramatically overhauled to become the consumer of the bulk of Israel’s natural gas. In 2012, natural gas constituted a mere 17% of the fuel mix in electricity generation. The remaining 83% was based on coal, Diesel fuel and oil.

The about-face was completed in 2022, when some 68% of Israel’s electricity was generated by locally-sourced natural gas, while 10% came from renewables and 22% came from imported coal.

Such massive infrastructure development requires, besides the fundamental economic imperatives, a holistic enabling policy regarding development of the gas fields.

In Israel’s case, within a few short years gas discoveries were made totaling 1,000 bcm. These finds came as a surprise to local industry, the government and regulatory agencies and to the general public.

Several government committees were set up in succession during those first years. Their mandate was to set up the overall regulation of the sector and in addition, they dealt with a range of issues such as fiscal policy, outlining the issue of gas exports and competition, etc.

The guiding principles according to which the regulatory decisions were made were based on the links

Record savings

The report states that thanks to the production of natural gas in Israel, the economy has, over the past ten years, saved over $90bn. This amount, calculated from public records released by the Ministry of Energy, the Ministry of Environmental Protection and other bodies over the years, divides the savings into two categories: energy cost savings due to the readily-available natural gas, estimated at $36bn and pollution reductions (externality costs) due to the substitution of coal and other polluting fuels with local natural gas, amounting to $54bn. The perhousehold savings thanks to the use of natural gas over the past decade have totalled approximately $35,000 (more than 60% of the 2022 per capita GDP)

Energy security

Within one short decade Israel has made a giant leap from 2.5 bcm of natural gas demand in 2012 to 13

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G LO B A L VO I C E O F G A S

41

The economy saved NIS190bn as a result of dramatic reduction in pollutant emissions intensity

A 32% reduction in greenhouse gas emissions intensity from the production of electricity

A reduction of 85% in the intensity of NOx emissions and 76% in the intensity of nitrogen oxide emissions*.

Thanks to the transition to natural gas, Israel is one of the leading OECD countries in reducing the emissions of greenhouse gases per capita*.

0.8

76% emission intensity reduction of NIS 94.9 billion in pollution costs

0.014 0.012 0.010 0.008 0.006 0.004

Contribution of renewables

0.002 0

32% emission intensity reduction of NIS 23.9 billion in pollution costs

0.75

0.70

0.60

0.55 Contribution of renewables

0.5

0.45 2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

*Not including savings from industry emissions intensity Source: BDO analysis of electricity economy reports by the Electricity Authority and the Ministry of Environmental Protection “Green Book”.

Source: BDO analysis of electricity economy reports by the Electricity Authority and the Ministry of Environmental Protection “Green Book”. *Based on Our World in Data.org, Israel is ranked 2nd in the OECD for reduction of CO2 emissions per capita over the past decade.

and interrelationships between the key aspects of the energy market: energy security, economic feasibility, local-versus-export markets, greenhouse gas emissions reduction, pollution reduction, taxation, etc. One of the decisions was that, in order to end the use of coal, three separate, independent production systems need to be built.

Despite the anticipated substantial growth in demand in the domestic market, Israel’s energy market was too small to create the levels of demand necessary for developing two additional deep-water gas fields.

Expanding the target markets and installing the policy for this became necessary to absorb the plentiful newly-discovered supply. In other words, substantial expansion of the target markets through exports of Israeli gas. This holistic solution led Israel into a process of unprecedented infrastructure development, which produced energy security which was hitherto something the country could only dream of.

$10.8 per mmBtu – in Europe. Thanks to this electricity prices in Israel have declined by approximately 11% this past decade while in Europe electricity prices have increased by some 40% on average. In the second half of 2022, consumer energy prices in Israel ($0.17 per kWh) were roughly half the average EU price. Thanks to this, Israel has emerged virtually unscathed from the global energy crisis, which has given it a competitive edge thanks to low energy costs.

Lowering power prices

The rapid, efficient development of the natural gas market in Israel through massive infrastructure development brought average gas prices to a level of $5.3 per mmBtu this past decade, as opposed to double that amount –

42

CO2 Emissions /KWh

NOx Emissions /KWh

0.016

G LO B A L VO I C E O F G A S

Natural gas and the environment

The rapid transition to natural gas-powered electricity generation, replacing polluting coal, has drastically reduced emissions in Israel. The intensity of NOx emissions has dropped by 76% over the past ten years, and the intensity of SO2 emissions has declined by 85%.

Within the same timeframe, total electricity generation has increased by over 20%. Additionally, CO2 emission intensity has also dropped considerably – 32% since the start of the natural gas revolution in Israel. Among OECD countries, Israel is second in its reduction of per capita greenhouse gas emissions this past decade.

The economic value of this reduction in air pollution intensity and greenhouse gas emissions totals approximately $90bn. There has never been a project

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The transition to energy independence: local natural gas pushed out imported polluting fuels

Potential undiscovered gas of 2,100 bcm – double the amount already discovered

As a result of the natural gas revolution – transition from dependence on imported energy to 80% local energy*.

2500

2003 0% Local energy

2022 78% Local energy

100% 90% 80%

BCM

2000

1500

1000

70% 60% 50%

500

40% 30%

0

20%

Undiscovered Potential

10%

End of 2022 Reserves

0% 2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

Tamar Local Natural Gas

Imported Fuels: Coal, Oil, LNG

Source: BDO analysis of Electricity Authority and Noga Data *On the electricty market.

in Israel that has yielded such a dramatic environmental dividend as the natural gas project.

Israel’s natural gas fields are deep in Israeli waters, tens of kilometres from the coast. Despite these being complicated, expensive projects, the methane emissions from them are among the world’s lowest. This accomplishment is due to the fact that these are modern projects, built under present-day regulations with strict adherence on the part of the owners. Israel’s natural gas industry today delivers 40% of the country’s energy needs. Production is equivalent to three-quarters of its needs, while at the same time methane emissions from this entire effort are, according to conservative estimates, a mere 0.3% of Israel’s total methane emissions.

A multicultural environmental economic bridgehead

The sizable gas discoveries in Israel’s economic waters have generated momentum in the search for natural gas across the region and, besides the rapid local development, regional export infrastructure has also been built. The benefits that these industries enable are of unprecedented economic and environmental benefits – not only for Israel, but also for other countries in the region, which enjoy clean, stable energy supplies. Thus,

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Thetis Sea

Leviathan

Karish, Tanin & Olympus

Renewables

*Undiscovered potential - based on Ministry of Energy 2018 (Dr.Michael Gardush, Levant Basin Hydrocarbon potential and future development); End of 2022 reserves BDO. Analysis: based on estimates by independent assessors on behalf of the gas companies, as publishes in their financial statements. The data includes categories 2C, 2P and the Energean discoveries - Karish North and discoveries in the Olympus region included non-audited 29 BCM.

Israel is now marking a decade since its natural gas revolution, which began with the sizable production and use of natural gas in 2013. natural gas has become a multicultural environmental and economic bridgehead benefitting all of the region’s inhabitants.

The large scale of the gas reserves discovered in Israel so far, relative to its domestic market, alongside geological potential for discovering an additional 2,000 bcm inside Israel’s economic waters and, moreover, throughout the entire Eastern Mediterranean basin, provide Israel and the other countries in the region the means of becoming significant players in solving the world’s energy shortages. Through natural gas exports, our region contributes, and will continue to contribute, toward bolstering global energy security and reduction of global use of polluting coal.

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43

A global gas market that performs The IGU’s Wholesale Gas Price Survey 2023 tracks the rise of gas-on-gas pricing and LNG spot trading over the years, the decline of oil price escalation and the recent widening of global gas price variation.

JOSEPH MURPHY

The International Gas Union (IGU) released its fifteenth

The rise of GOG, the demise of OPE

annual Wholesale Gas Price Survey in September,

The survey showed how wholesale gas price formations

tracking the evolution of global wholesale price formation

have transformed significantly between 2005 and 2022.

mechanisms. The survey’s findings are supported by

The share of gas-on-gas (GOG) competition pricing –

responses from 85 out of the 113 gas markets, covering

where the price is determined by the interplay of direct

91% of total global gas consumption.

gas supply and demand – almost doubled over the period

As IGU President Li Yalan remarked in a foreword, the survey “continues to show the criticality of a well-

the share of oil price escalation (OPE) – where the price is

functioning global gas market at work, as the gas markets

linked to competing fuels, typically crude oil, gas oil and/

have been experiencing the most turbulent period in

or fuel oil – fell from 24% to 17.5%.

their history amidst a severe global energy crisis and an ongoing war between Russia and Ukraine.”

This well-functioning market helped Europe keep its

44

from 31.5% to 50%. This largely came at the expense of

The rise in GOG and decline in OPE between 2005 and 2017 was mostly the result of changes in pipeline imports by Europe, with OPE almost vanishing in

lights on by attracting unprecedented additional LNG

northwest Europe and central Europe on the back of

volumes to replace lost Russian pipeline volumes, she

European energy market reform and liberalisation. OPE

said, effectively redrawing the global gas trade map

persists in Europe in Turkey, the continent’s southeast

without interrupting supply.

and the Baltic countries, however – markets that were

G LO B A L VO I C E O F G A S

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Figure 1: Wholesale price formation mechanisms map

Source: IGU

in that period heavily reliant on Russia. It also remains

increase in spot LNG imports in South Korea and Chinese

present in Spain and Portugal, which chiefly import

Taipei, and rising demand in Russia also spurred a growth

Algerian pipeline gas and LNG.

in GOG’s share.

There was a shift up until 2016 from regulated pricing

These various factors more than offset a drop in GOG

mechanisms to market-based pricing such as GOG and

use in Asia overall, as a result of China and Pakistan

OPE, but that trend has since paused. The driving force

scaling back spot LNG imports. While global gas imports

behind GOG’s rise and OPE’s demise since 2016 was the

fell in volume, on the back of a steep drop in Russian

former’s increased use in the LNG space, in particular via

pipeline exports to Europe, the relative shares of OPE and

spot market trading. Within the regulated pricing area,

GOG were not altered much, as the fall in Russian GOG-

the biggest changes were seen between 2005 and 2012,

priced supplies was offset by OPE-to-GOG switching in

as subsided pricing or regulated below cost (RBC) pricing

other markets and increased spot LNG flow to Europe.

gave ground to higher, but still regulated prices.

Over 2022, the share of GOG grew by a further 1.5

As noted, GOG now heavily dominates the European gas market (see figure 1), accounting for 82% of total

percentage points, primarily at the expense of OPE.

volumes, including almost all domestic consumption,

GOG’s share of gas import volumes touched a new high

82% of pipeline imports and 76% of LNG imports. This is

of 56%. The growth was particularly pronounced in

a marked contrast from in 2005, when only the UK had

Europe, due to a sharp increase in spot LNG imports, as

significant GOG use on the continent. GOG now exceeds

well as a switch in some of Turkey’s supply contracts for

OPE even in Spain. Turkey is still primarily OPE, but it

gas from Russia from oil indexation to hub pricing. The

now only just exceeds GOG in share as a result of pricing

pricing of gas supplies from Algeria into Tunisia was also

adjustments in Russian contracts.

adjusted to GOG from OPE. In Asia, there was also an

O C TO B E R 2 0 2 3

In comparison, OPE is still the main mechanism in

G LO B A L VO I C E O F G A S

45

Figure 2: World price formation 2005-2022 - LNG imports 40%

100% 80%

30%

60% 20% 40% 10%

20% 0%

% Spot LNG

“[The survey] continues to show the criticality of a well-functioning global gas market at work.”

0% 2005

2007

2009

OPE

2011

2012

2013

2014

GOG Traded

2015

2016

2017

GOG Spot

2018

2019

2020

2021

2022

% Spot LNG

IGU PRESIDENT LI YAL AN

most Asian countries, while in the Former Soviet Union, the Middle East and North Africa, prices remain largely

Figure 3: Wholesale price levels 2005-2022 by region

regulated.

More GOG and spot trading in LNG

35 30

imports took off in 2017, doubling its share between 2016 and 2022 to 47% (see figure 2). This trend was driven by rising spot LNG imports, and later a rush of LNG flow to Europe’s traded markets. More Henry Hub-priced gas entering those markets in 2021 also played a role.

The share of spot trading in the LNG market grew substantially in 2005-2022, from under 5% at the start to 35% at the end of the period. Growth prior to 2010 was mainly in the Asia-Pacific region, and it began catching on in Asia after that year. Spot LNG volumes in Europe

$/MMBTU

Zeroing in on the LNG market, GOG pricing of LNG

25 20 15 10 5 0 2005

2007

2009

2011

2012

2013

2014

2015

2016

2017

North America

Europe

Asia

Asia Pacific

Latin America

FSU

Africa

Middle East

World

2018

2019

2020

2021

2022

remained relatively low until 2018, but took off after that, with a sharp jump seen in 2022 as LNG replaced

rising through to 2015 due to a shift away from subsidised

lost Russian pipeline volumes. Since 2016, the driver of

pricing, after which point they levelled off.

increased spot volumes was the surge in LNG exports

tracked each other since 2015 but the link was severed

spot LNG volumes going into the markets of India, China,

in 2019, after a significant drop in spot prices that mainly

Japan and South Korea.

benefitted the European market. The difference between

In the five year period ending 2022 alone, spot LNG volumes nearly tripled to 171 bcm.

Rising prices, greater variation

European and Asian/Asian Pacific prices widened in 2020 after the pandemic triggered a collapse in spot prices.

But in 2021, the post-coronavirus economic recovery led European prices to overtake Asian/Asian Pacific prices

Global wholesale gas prices were generally rising between

(see figure 3), given that the latter regions use more OPE

2005 and 2014, although the North American market was

pricing, which was more stable. The difference became

an exception, where the shale gas revolution saw supply

even greater in 2022.

soar. Global prices hit records in 2022, as a result of Russian supply cuts and the broader energy crisis.

Regions dominated by regulated prices – Africa, the Middle East and the Former Soviet Union – saw prices

46

Asian, Asian Pacific and Europe prices have generally

from the US. From that year there have also been growing

G LO B A L VO I C E O F G A S

The variation in global gas price levels widened significantly in 2021 and even more in 2020, in contrast to the trend of price convergence seen between 2005 and 2015.

O C TO B E R 2 0 2 3

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