Global Voice of Gas #3 Vol.4

Global Voice of Gas

BY

THE INTERNATIONAL GAS UNION

ENERGISING THE WORLD

A DELICATE BALANCE OF DEMAND, SUPPLY AND SUSTAINABILITY

A lasting legacy: An interview with IGU President Li Yalan

Uncertainty in Europe as end to Ukraine transit deal looms Indian gas demand to triple, but how soon?

Guyana’s emerging gas sector

Message from the President

Dear readers,

Welcome to our printed September 2024 edition of Global Voice of Gas. I hope most of you had an enjoyable summer holiday in the northern hemisphere, and that many of you are getting ready to join me and many of the global gas industry’s leaders next year in Beijing, at IGU’s 29th World Gas Conference!

The Call for Abstracts will be open until the 30th of September 2024, and all of us at IGU are looking forward to welcoming your delegates to China in May 2025, where they will be joined by more than 3,500 delegates from 70 countries, with an exhibition covering an area of 50,000 square meters, over 300 exhibitors and an estimated 30,000 trade visitors.

There will be nearly 100 sessions where the best and brightest minds across our entire gas value chain will discuss, and certainly shape, what matters to us all: our future as an industry! All the details related to the world’s largest oil and gas conference can be found at www.wgc2025.com.

It is the first time in the IGU history that the World Gas Conference is being held in China, the world’s largest single energy market. And Beijing will be where you can help your organisation, IGU, and the global gas industry make history. The conference will present insights, innovation, best practices, series of inspiring debates, dialogues between experts of the industry and government representatives and the global voice of gas, covering topics ranging from the Global Energy Landscape to Energy Security, from Energy Transition to the Future of Global LNG, and from Digital and Technological Innovation to Renewable gases and Methane Emission Mitigation. Your organisation will meet with key stakeholders at the conference and can discuss with peers industry insights, technology and innovation. Your contributions could shape the dialogue at WGC2025, offering valuable and in-depth perspectives into the challenges and opportunities facing the global gas and energy industry.

I am delighted to see our 2024 Global Gas Report, launched at ONS in Norway at the end of August, gaining so much international traction and interest, and its findings being hailed by a variety of energy stakeholders worldwide.

We all need to be clear that rising energy demand across all regions, record-breaking carbon emissions, and extreme weather conditions demand an urgent need for more policy clarity and consistency on the global energy market, climate action, trade and finance, to ensure supply security and tackle climate change. In 2023, natural gas accounted for 23.8% of the world’s energy consumption. While coal still accounted for 35.5% of the primary energy consumption in non-OECD countries, the ratio in OECD countries was only 12.4%. Carbon emission from energy in the non-OECD countries are over two times those of the OECD countries. Energy choices and technologies outside the OECD countries will decide the future global carbon budget. Globally, replacing coal with natural gas could cut emissions by 50% immediately. Abundant in supply, clean and versatile, gas has a pivotal role to play to enable energy supply security, reduce emissions, and enable the wide deployment of renewable energies. This would not happen without investment across the natural gas value chain, coupled with accelerated investment in decarbonising gas technologies, including Carbon Capture, Utilisation and Storage and low-carbon hydrogen. While global gas markets have calmed down from their record volatility in 2022, they remain fragile as energy security concerns persist. The current actions have been reported to be, likely, insufficient to attain the 2030 climate targets. This insufficiency could be attributed to three key reasons – increasing energy demand, the lack of clarity of climate and energy policies, and the role of gas in the energy transition.

As we launch this print edition of the Global Voice of Gas, IGU continues its efforts to enable the understanding of the critical role that gas play in the world’s sustainable energy future.

Editors’ Note

Welcome to the 17th issue of the Global Voice of Gas magazine, an International Gas Union (IGU) publication produced in collaboration with Natural Gas World (NGW).

In this issue, we present a wide range of features and contributions with a common theme: the supply and demand of natural gas and the fuel’s ability to contribute to global sustainability goals.

The role of natural gas will be front and centre next May when the IGU presents its 29th flagship triennial conference, the World Gas Conference (WGC) in Beijing.

With the theme Energising a Sustainable Future, WGC2025, which will be hosted by Beijing Gas, will showcase the role natural gas can play in future energy systems, including those that target net-zero by 2050 – or earlier. An opening feature in this edition of GVG sets out some of the themes on the agenda at WGC2025.

In this issue we also present a wide-ranging discussion with Madame Li Yalan, who has led the International Gas Union as president since 2022 and who will step down at the close of WGC2025, to be replaced by Italy’s Andrea Stegher. Through one of the most turbulent periods in the IGU’s 93-year history, Madame Li has led the IGU to become one of the most influential organisations in the global natural gas sector.

In the aftermath of Russia’s invasion of Ukraine in 2022, European gas markets were upended as consumers in both Europe and Asia scrambled to find alternate supplies to replace Russian piped gas.

That volatility continues, with the possibility that the Russia-Ukraine gas transit deal will not be renewed at the end of this year, potentially disrupting supplies yet again – this time in the dead of winter. In this issue, we examine the transit agreement, the potential that it will be allowed to lapse and possible scenarios moving forward.

Meanwhile, Azerbaijan has been touted as a possible source for gas to replace lost Russian molecules, but a host of barriers stand in the way of Europeans accessing that supply. As we explain in this edition of GVG, long-term commitments from buyers are needed to support field and infrastructure development, but that is unlikely to happen without environmental approvals and international financing agreements, which are becoming more difficult to obtain.

In the Middle East, increased natural gas use has supported oil exports and met growth in power demand. Now, the UAE, Saudia Arabia and Qatar, among others, are re-

positioning natural gas to meet the energy and decarbonisation goals of coal-dependent Asia even as they boost intra-regional gas trade.

The future of the natural gas industry – and for consumers of natural gas – in New Zealand was thrown into disarray in 2018 when the government of the day enacted a blanket ban on new oil and gas exploration. Fast forward six years, and John Carnegie, executive director of Energy Resources

Aotearoa, New Zealand’s oil and gas industry association, reports that a new government in Wellington understands the importance of oil and gas and has taken steps to reverse the ban and help the sector rebuild.

In Africa, the continent’s vast natural gas reserves have either been flared or exported as LNG. Now, as Mickael Vogel, director and head of research at Hawilti, a pan-African investment research firm, tells GVG readers this issue, a variety of strategies are being studied to build domestic natural gas use and assist decarbonisation efforts.

Much the same is happening in Guyana, where that South American country is looking to leverage a sharp jump in oil production – from zero in 2019 to more than 600,000 barrels/ day today – to kick-start natural gas production.

Even as the supply future for natural gas around the world appears rosy, demand for the fuel – especially in the US, the world’s largest natural gas producer – is decidedly less certain.

Robert Kachmar of RBAC, which provides global and regional gas and LNG market simulations, reports that a long list of uncertainties, ranging from the impact of data centres to the outcome of this November’s US elections, are making for a very uncertain demand outlook for natural gas.

Elsewhere, India expects its demand for natural gas will triple by 2030, but while the sub-continent’s network of City Gas Distribution (CGD) systems is impressive, broader penetration of natural gas outside the CGD systems is a hit and miss affair, and weak electricity prices appear to render gas-for-power schemes uneconomic, even as the government desperately tries to reduce coal-fired power generation.

Finally, our regional updates section brings you up to speed on the latest natural gas developments in Europe, Asia and Africa.

We hope you enjoy this issue.

Dale Lunan Editor,

Global Voice of Gas

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A word from the Secretary General

It is with great honour, privilege and pride that on the 1st of July this year, I accepted the offer to serve the International Gas Union (IGU) as its Secretary General.

I have had a long, challenging and rewarding engagement with the IGU for many years. Of the many highlights, three that stood out and were instrumental to my personal growth were when (1) serving under the Malaysian Presidency, I chaired the Task Force on Geopolitics and Natural Gas; (2) as a member of the USA Presidency leadership serving as the Chair of the Coordination Committee; (3) and as the Director of Public Affairs for the IGU from 2016 to 2020.

I have assumed this role during great uncertainty about the future of energy. Wars, regional conflicts, geopolitics, struggling economies with inflationary pressures, the rising cost of capital, energy policy, public perception and acceptance of energy and country elections have all contributed to massive global implications that affect energy but reach far beyond it. The consequences of some of these challenges led to the most significant energy crisis since the oil embargo crisis in the early 70’s. The loss of Russian pipeline gas to Europe triggered a massive reconfiguration of global gas flows, causing energy price volatility that significantly impacted energy affordability, the heat-intensive European industries and the fuel mix of many South Asian countries. And despite energy prices cooling off, we are still not out of the woods for at least the next two years.

Yet, in the mix of this uncertainty, demand for global energy continues to rise. Energy efficiency and renewable energy additions fall short of the energy demand increases, leaving it to fossil fuels to fill the gap. At the same time, we still have three billion people who need access to clean energy.

History has taught us that past energy “transitions” were about energy “additions.” As new technologies matured and became cost-competitive, they were added to the fuel mix but were not enough to offset the increasing energy demand.

As the World Energy Council notes in the World Energy Trilemma Report, 2024, “Energy transition is not a straightforward swap of old for new technologies; it is a socially messy and transformational change process.

A successfully managed global energy transition is unprecedented and cannot be completed all in one go nor by any single region, country, company or city working alone.

There is no one-size-fits-all net-zero pathway. Situations, starting points, and outlooks differ.”

If energy system planning and decisions about supply investments across energy sources and infrastructure are based on scenarios that underestimate the actual energy demand growth, we are heading for a significant global energy crisis.

In the 2024 Global Gas Report, we compared energy demand assumed by the IEA Stated Policies Scenario (STEPS) (which reflects current government commitments) and the

If energy system planning and decisions about supply investments across energy sources and infrastructure are based on scenarios that underestimate the actual energy demand growth, we are heading for a significant global energy crisis.

energy demand trends observed in the last 4 and 10 years, and a startling difference emerged. The 4-year historical trend exceeds STEPS’ projection by an amount nearly equal to Europe’s entire energy consumption in 2023. When compared to the IEA’s Net-Zero Emissions by 2050 Scenario, this gap widens to about one and a half times the energy used by North America in 2023 and more than twice Europe’s annual consumption.

This is the scale of uncertainty we face in the next five years, highlighting the critical importance of taking stock of what is actually happening and how it stacks against all our aspirations as an industry and as energy consumers.

Supply investments must be planned well ahead of time based on expected demand so the resource is available when needed. There will be severe energy shortages if plans are made for an understated demand level. This is a scenario when temperatures in India climb to 50 degrees Celsius, as they have this summer, and the resources aren’t there to allow for cooling.

We need to ensure that policymakers worldwide understand the reality on the ground and take the necessary measures to align their national energy consumption patterns to their actual energy resource availability and, more important than ever, affordability.

Energy systems can’t be designed on scenarios alone because scenario assumptions always risk diverging from

reality, even if the outcome they aim to achieve is the most desirable one. Both scenarios and current trends are needed to plan energy investments and assure near and medium-term security of supply.

Scenarios make significant assumptions about policy’s ability to impact energy consumption patterns, behavioural changes, and technology adoption rates. There is an inherent level of uncertainty included in these, but, irrespective of this “uncertainty”, all assumptions made so far regarding global energy demand and use have been fundamentally off track. The gas industry must continue its extensive efforts to decarbonize and reduce methane emissions. Adopting a zeroemissions culture will be critical to maximizing these efforts. I remain very optimistic that human ingenuity, commitment, and hard work will lead to an orderly, sustainable energy pathway to the future. To this end, as the Secretary General of the International Gas Union, my pledge to all our members is to strongly advocate for the role of natural gas and its evolving technologies while being fully committed to the enhanced value delivery of the traditional services provided by the IGU.

Menelaos (Mel) Ydreos Secretary General, IGU

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Events

Your Call for Abstracts Submission has Never Been More Important

Perhaps your technical or commercial innovation holds the key to the future success of our industry? Certainly your contribution, alongside your peers, is fundamental in determining how we respond to the challenges and opportunities we face.

Conferences are at their most interesting (and enjoyable) when we have both reason and purpose to come together, and the IGU’s World Gas Conference uniquely delivers that once every three years, including face-to-face collaboration, knowledge and networking opportunities for you and your company.

Set to take place in Beijing, China from May 19-23, 2025, WGC2025 is the world’s premier conference and exhibition showcasing innovation, dialogue, and strategic collaboration and is shaping up to be an unmissable event for gas and energy professionals from around the world. There is something for everyone in our range of themes across the entire value chain.

The conference is inviting submissions for abstracts to be presented in the highly anticipated Industry Insights and Technology and Innovation Centre sessions. This is an unique opportunity to share your expertise and insights on one of the seven critical themes:

RODNEY COX Director of Events, International Gas Union

Submitting your abstract is easy, so don’t hesitate to make your voice heard and make your impact on the gas and energy sector. Scan the QR code below or visit https://www.wgc2025. com/eng/call-for-abstracts to make your submission and secure your chance to influence the global gas and energy conversation. But remember, the deadline is September 30, 2024, so act fast!

By contributing your insights, you’ll help shape the future of the gas and energy industry while also entering to win a prestigious accolade: the IGU Global Gas Award, the WGC2025 Regional Gas Award, and the WGC2025 Industry Award.

In addition to speaking, make sure to secure your Early Bird Delegate Pass to take full advantage of the conference’s incredible offerings. The WGC2025 programme is packed with insightful Plenary Sessions, Current Debates, and unparalleled networking opportunities with decision-makers and industry leaders. You’ll also gain valuable insights into the Chinese energy sector, making this a truly global event.

Join us in Beijing for WGC2025 and play a pivotal role in transforming the gas and energy landscape, shaping the global energy conversation, and driving meaningful change in the industry.

Learn all there is to know about WGC2025 at www.wgc2025.com and we’ll see you in Beijing next spring!

7.

Europe

DIDIER HOLLEAUX

Executive Vice President Engie and IGU Regional Coordinator.

Global trends

During the 7 first months of 2024, the European market appeared relatively balanced, with prices (month ahead) stabilising mostly in the range of €25-35/MWh, and most of the countries experiencing no real supply difficulties, particularly due to a mild winter.

Nevertheless, this level of prices, which is around 4 to 6 times higher than in the USA, is still putting European gas customers (large industrial as well as SMEs and domestic customers) in a difficult situation.

The Russian crisis is still there.

A lot of events show that the crisis resulting from the invasion of Ukraine by Russia is far from over.

Gas supply coming from Russia to EU 27 were roughly in line with 2023: in the order of magnitude of 50 bcm, coming half by LNG, half by pipe (through Ukraine and Türkiye), which represent less than one third of the quantities delivered in 2021.

A controversy occurred about the amount of Russian LNG received in Europe (as it appeared to be higher than in 2021, despite the strong reduction in global Russian gas quantities).

Following this controversy, the EU took on June 24 the paradoxical decision to prohibit transshipment in European ports as of March 2025. The real impact of this decision on the global LNG market remains to be seen, but most observers think it will be minimal, and may de facto increase the European imports of Russian LNG.

Moreover, the uncertainty about the transport of Russian gas through Ukraine is also an important question for European supply: this uncertainty has two main causes: 1) the Ukrainian government said clearly that it does not intend to renew or extend the contract with Gazprom to transport gas from Russia to the West after December 31, 2024 and 2) a European court said that some of Gazprom’s Austrian customers may have to pay the amounts due to Gazprom to another party. These problems may lead to an interruption of the gas flows through Ukraine, with probable consequences on the supply to countries like Moldova, Slovakia and Austria.

In one of the first arbitration decisions taken on the interruption of Gazprom long term contracts to western Europe, an arbitration panel settled in June the case between Uniper and Gazprom by saying that the contracts were terminated, and that Gazprom was to pay around €13 billion in penalties and interest to Uniper. A number of other arbitration cases are being pursued and should come to decisions in the months to come.

These many uncertainties have kept the prices of gas in Europe both relatively high (mostly above €30/MWh) and volatile (very sensitive to any piece of news);

Other supplies

In the short term, mild winter and the resulting high level of

gas storage has led Europe to reduce its import of LNG and as a consequence, LNG terminals are less busy than during the previous years.

Nevertheless, Europe still needs to replace the missing Russian gas and therefore the “pause” in permitting of new LNG exports in the USA was considered as a bad signal by the European gas industry. European players are also looking closely at the arbitration opposing Venture Global and its European customers. These two separate issues, combined with some technical problems at some liquefaction installations in production or construction, raise the question of the reliability of US LNG as an important supply source for Europe, giving some support to the opinion that we shouldn’t replace an overdependency (on Russian gas) by another one (on US LNG).

The global expansion of LNG production which is currently being anticipated (around 150 additional bcm coming on stream between 2026 and 2028) gives confidence to European buyers that they will find alternative supply if they need additional LNG.

A number of announcements were done around additional exports from Azerbaijan to Europe. Most experts question the capacity of Azerbaijan to produce and export more gas.

Infrastructure

The effort of many European countries to increase their LNG import capacities were continued : a number of FSRUs are operational, and the works started on one of the German onshore regasification terminal.

In southeast Europe the “vertical corridor” going from Greece to Moldova and Ukraine, but also to Hungary

and Slovakia, starts in June 2024 its operational capacity allocation activity and announces new possible investments. It will be able to send to the north and northwest gas coming from Türkiye (either through TANAP, or through the Turkish LNG terminals), or LNG regasified at Alexandroupolis (Greece) where the FSRU was commissioned in February 2024.

After some controversy the “gas storage neutrality charge” created by Germany and which impacted transborder gas trade has been set to zero. There are still some ongoing discussions between Germany and its neighbors on capacity allocations at the borders.

Demand

After a reduction in gas demand above 30% between 2022 and 2023, the first half of 2024 still shows a reduction of more than 5% year-on-year.

A mild winter, a high level of gas in storage (above 2023 level, which were already very high), and a significant reduction of gas-to power consumption (minus 2 bcm) do explain this decrease.

The only good news was a slight increase (plus 1 bcm) in industrial gas use, which may indicate that the worst of the industrial gas demand destruction could be over.

Conclusion

Everything, and specially the high price volatility, shows that the European market hasn’t yet found a new stable equilibrium following the Russian crisis, and remains oversensitive to any worrying piece of news.

North Asia & Australasia

SATOSHI YOSHIDA

Senior Adviser, Japan Gas Association, and IGU Regional Coordinator.

The Future Gas Strategy is a plan for gas production and consumption in Australia. It stresses that even in net zero scenarios, Australia will need gas at lower levels through to 2050 and beyond while managing the emissions from gas, ensuring affordability and reliability of energy as we undergo the energy transition.

In 2021-22, gas provided 27% of Australia’s energy needs and accounted for 24% of Australia’s total GHG emissions.

Its guiding principles state that Australia will continue to be a reliable trading partner for energy, including liquefied natural gas (LNG) and low emission gases.

The world’s three largest LNG importing countries in the region, Japan, China and Korea are dependent on LNG from Australia 39%, 28% and 15% respectively.

Japan

Overcoming COVID, the world’s energy demand increased by 2% in 2023. Energy demand is expected to increase also in 2024.

Renewable energy is increasing and the share of fossil fuels on the primary energy base is slightly decreasing. But the pace of the world’s energy demand exceeds the added renewable capacity of renewables, and the consumption of fossil fuels is increasing. As of today, fossil fuel share still exceeds 80%.

Gas price hikes associated with Russia’s invasion of Ukraine eased in 2023 thanks to warm weather in Europe, enough storage and energy saving measures. But from an historical perspective, the price in Asia remains high.

The natural gas market could be very tight in 2025 largely depending on Europe’s winter weather and LNG ship passages through the Panama and Red Sea canals.

In the mid- to long-term, the gas market could be very tight after 2035, resulting from lack of investment.

Many LNG buyers in Asia, once seeking to diversify contracts dominated by long term contracts to short term contracts and spot market procurement are reverting to long term to secure enough LNG for the region in the long term.

Australia

Australia shipped 81.7 MT of LNG in FY2023-24, compared with 81.9 MT in the previous year.

Export revenue fell 25% in FY2023-24 due to softer LNG prices.

Department of Industry, Science and Resources published its Future Gas Strategy in May (updated in June).

Japan was one of the first to import natural gas in the form of LNG beginning in 1969. Ever since, Japan has increased its LNG imports. The share of natural gas in the primary energy mix was around 13-14% before 2011 but has increased to around 22-24%, reaching the average of OECD countries to compensate for the power lost from nuclear power generation.

But due to energy saving efforts and a prolonged downturn in the economy, along with nuclear plants restarting and renewable energies gaining momentum, LNG imports are gradually declining over the years.

Imports were 87.5 MT in 2014 but fell to 66.2 MT in 2023, down 25% in 10 years.

In 2020, the Ministry of Economic, Trade and Industry (METI) announced its plan that Japan will manage 100 MT of LNG by 2030, while domestic needs are 60 MT.

Japan is developing its own trading capability and creating an Asia region gas market that increases energy security and at the same time hedges risks of an LNG surplus.

Many of Japan’s LNG powerhouses are planning to invest in natural gas infrastructure in the region to boost regional LNG markets, LNG power plants in Vietnam and Indonesia, and LNG regasification terminals in the Philippines and are said to be participating in more than 30 gas related projects. Japan is aiming to transform from an LNG importer to an LNG dealer.

China

China’s natural gas demand has a significant impact on the gas market and prices in the region. The world’s largest natural

gas consumer increased its demand by 7.5% (392 bcm) in 2023.

Total gas imports increased by 9.9% (165 bcm or 120 MT).

China natural gas imports were 41% by pipeline and 59% by LNG. LNG imports increased by 12.6% (98 bcm or 7.5 MT).

All sectors, city gas, industrial use, and power generation, increased with the lifting of the zero COVID policy. Especially demand for power generation and transportation sector (LNG truck) showed prominent increase.

In the industrial sector, demand for producing lithium-ion batteries, new energy vehicles and PVs increased.

Natural gas power generators added capacity in Guangdong, Shanghai, Chekiang and Jiangsu and new natural gas power generators are built in new areas, Shandong and Anhui, to support increasing renewable generation.

New Zealand

In June, Resources Minister Shane Jones announced that the Crown Minerals Act, which has banned offshore oil and gas exploration since 2018, will be amended allowing new gas exploration to address energy security challenges posed by rapidly declining natural gas reserves.

In his statement he said, “Natural gas is critical to keeping our lights on and our economy running, especially during peak electricity demand and when generation dips because of more intermittent sources like wind, solar, and hydro.”

South Korea

While South Korea plans to generate 70% of its electric power from carbon-free energy sources such as renewables and nuclear power by 2038, up from less than 40% in 2023, South Korea is securing long-term LNG.

In February, South Korea’s state-run Korea Gas Corp (KOGAS) signed a long-term LNG supply agreement with Woodside. Woodside will supply approximately 0.5 MTPA of LNG over a period of 10.5 years, starting in 2026.

In April, KOGAS also entered into a long-term contract with BP importing 9.8 MT of LNG over 11 years.

France’s Total Energies announced on June 4 that it had signed LNG contracts with Korea’s Korea South-East Power.

Total Energies signed a heads of agreement with Korea South-East Power for the delivery of up to 0.5 MTPA of LNG

for five years starting from 2027.

Chinese Taipei

Chinese Taipei declared in April 2021 it would be carbon neutral by 2050 and would phase out nuclear power and reduce coal dependency by 2025.

Chinese Taipei depends 90% of primary energy and 80% of power on imported fossil fuels and imported 20 MT of LNG, 5% of all the global traded LNG in 2022 It has plans to increase natural gas power generation up to 50% by 2025 and add another 9 GW from 2022 to 2029.

CPC is the sole importer of LNG and owner of LNG terminals, Yung’ an (7.4 MTPA) and Taichung (6 MTPA). It has plans to build new terminals in Gauteng and Zhouji to add extra capacity.

CPC’s contracts are mostly long term (19.3 MTPA). Short and mid-term contracts are supplementary to enhance energy security.

CPC also has investments in the upstream, RasGas II, Prelude LNG and Ichthys.

Africa

KHALED ABUBAKR Chairman, Egyptian Gas Association. Executive Chairman, TAQA Arabia and IGU Regional Coordinator

Central and South Africa: Kinetiko becomes the first company in South Africa to produce power from onshore gas, Congo delivers the 1st LNG cargo to Italy, and South Africa Taps Vopak Consortium for a new LNG terminal.

» Kinetiko Energy has successfully generated 1.2 GW of power from a trial at an onshore gas well in South Africa, marking a significant milestone in the country’s energy transition. The company plans to expand this achievement by developing the Korhaan project, aiming to produce 500 MW of power, using over 2 tcf of gas reserves. In partnership with FFS refiners, Kinetiko aims to expand the Korhaan cluster, which currently includes five wells, into an LNG production cluster with about 30 wells.

» Congo has joined the ranks of LNG exporters with the first cargo from its Marine XII project arriving in Italy. The project, centered around two FLNG units, including the Tango FLNG ship with a capacity to store over 180,000 cubic meters of LNG and 45,000 cubic meters of LPG, will produce 4.5 billion cubic meters per year (bcm/y) of LNG. Eni, as the project operator, will market the LNG, contributing to its growing energy portfolio.

» South Africa awarded the Vopak consortium to operate a new LNG terminal at the Port of Richards Bay. The Dutch

company will partner with Transnet Pipelines for a 25-year agreement, aiming to increase gas usage in the country’s economy. According to Transnet National Ports Authority (TNPA), the LNG terminal, situated along South Africa’ east coast, will initially import 2 MTPA of LNG by 2027 before ramping up to 5 MTPA. This move is part of South Africa’s shift towards gas and renewable energy to address its energy crisis and reduce dependence on coal.

East Africa: Mozambique is positioning itself as a regional key player, attracting significant foreign investment. This is exemplified by Turkey’s Karpowership developing a $1 billion gas-powered facility and ADNOC acquiring a stake in the Rovuma Basin gas projects. Zimbabwe is set to transform energy landscape with landmark gas discovery.

» Karpowership, a Turkish company specializing in sea-based electricity production, plans to invest $1 billion in a new floating power plant in Mozambique. The natural gas-powered facility will have a capacity of 470-500 megawatts (MW). The project aims to achieve sustainable energy solutions for five million Mozambicans, with potential for export to neighboring countries. The company already operates a similar plant in Nacala, producing over 120 MW of electricity since 2016.

» ADNOC acquired a 10% stake in the Area 4 concession of the Rovuma basin in Mozambique from Galp. This gives ADNOC access to LNG production in the concession, with a potential capacity of over 25 million tons per annum (MTPA). The Coral South development, currently operational, can produce up to 3.5 MTPA of LNG. The planned Coral North FLNG development, expected to reach a Final Investment Decision in 2024, will add another 3.5 MTPA of LNG. The Rovuma project holds a capacity of 18 MTPA and it features a modular, electric-drive design that significantly reduces carbon intensity. The Rovuma Basin is estimated to hold natural gas reserves, with around 85 trillion cubic feet (tcf) of recoverable gas.

» Australia-listed Invictus Energy advanced its Mukuyu natural gas field in Zimbabwe in the Cabora Bassa basin, raising AU$16.5 million for development. The Mukuyu field, the largest undrilled onshore prospect in Africa, holds an estimated 20 trillion cubic feet of gas and 845 million barrels of gas-condensate. Interpretation of new seismic data identified three drill-ready prospects. Additionally, an updated Memorandum of Understanding (MoU) with Mbuyu Energy outlines a 500 MW gas-to-power project, potentially expanding to 1000 MW, supporting the integration of renewables into the grid.

West Africa: TotalEnergies reaches FID for Ubeta Gas Field development, Nigeria’s Akpo West Field begins production, and GTA Phase 1 LNG FPSO Vessel Moored Offshore Mauritania and Senegal.

» TotalEnergies made a FID for the development of the Ubeta gas field that will supply gas to the Nigeria LNG liquefaction plant located on Bonny Island. This is part of an ongoing capacity expansion of the NLNG from 22 to 30 MTPA. The Ubeta gas field is set to commence production in 2027, targeting a plateau of 300 million cubic feet/day (mmcf/d). The field will be developed with a new six-well cluster connected to existing infrastructure via an 11 km pipeline. Moreover, The Nigeria LNG Ltd. (NLNG) made progress in its Train 7 gas project, reaching 67% completion.

» Nigeria’s Akpo West field started production with 14,000 barrels/day (bbl/d) of condensates and is expected to produce 4 million cubic meters per day (mmcm/d) of gas by 2028. The field is tied back to the existing Akpo Floating Production Storage and Offloading (FPSO) facility. Akpo West field is part of Nigeria’s PML 2 licenses in which TotalEnergies is the operator with a 24% interest.

» The Greater Tortue Ahmeyim (GTA) Phase 1 LNG project

achieved a major milestone with the arrival of the FPSO vessel. This deep-water facility, capable of processing over 500 mmcf/d of gas, will produce around 2.3 MTPA of LNG for over 20 years. The multi-billion-dollar project, located in waters up to 2,850 meters deep, represents a significant energy development for Mauritania and Senegal.

North Africa: Egypt is bolstering its gas production with a $222 million gas project, while Algeria secures its position as a key gas producer and supplier through deals with major companies, Libya joins the region’s growing energy potential with a new gas discovery, and both Nigeria and Morocco advance major pipeline projects.

» The Egyptian General Petroleum Corporation (EGPC), Shell, and Petronas signed an agreement to invest $222 million in the West Delta deep offshore region for the tenth phase of development. The project aims to boost natural gas production rates and reserves by drilling three new wells and establishing marine facilities. Production from these wells is expected to reach between 150 and 200 mmcf/d by the end 2024.

» Algeria’s state-owned energy giant, Sonatrach, awarded a major contract for the Hassi R’Mel gas field. The contract was awarded to a consortium between Baker Hughes and Tecnimont, part of technology and engineering group MAIRE. Both companies will supply Sonatrach with 20 compression trains that are expected to boost gas production at the field which currently accounts for approximately 25% of the country’s daily output.

» Sonatrach also signed a medium-term gas supply contract deal with VNG Handel & Vertrieb GmbH for providing Germany with natural gas for the first time. Besides natural gas from Algeria as an important commodity for energy security, VNG aims to establish a hydrogen partnership with Sonatrach and to import green hydrogen from Algeria to Germany in the future.

» Libya’s National Oil Corporation (NOC) made an important gas discovery through its subsidiary, Sirt Oil after drilling the exploratory well (W, W, 1-6) in a new geological formation in the contract area (M). N.6) Southeast of Al-Lahib Field. Tests showed that the well produced 16.8 mmcf/d of gas and 626 bbl/d of oil. This discovery is part of the NOC’s strategic

plan to increase oil and gas production and will contribute to supplying the coastal network with natural gas.

» The Trans-Saharan Gas Pipeline (TSGP) project shows some progress, with only 1,800 km of the planned 4,000 km route remaining to be completed. The TSGP project aims to transport Nigerian gas through Niger into Algeria, eventually connecting to the European energy market. It is intended to have an annual capacity of around 30 bcm of natural gas.

» Nigeria-Morocco gas pipeline project’s updates indicate that the final investment decision (FID) for the $25 billion project is expected to be made by December 2024, according to CEO of Nigerian National Petroleum Company Limited (NNPC) Mele Kyari. This pipeline aims to transport natural gas from Nigeria along the West African coast to Morocco and onward to Europe, connecting multiple countries along the route, including Benin, Togo, Ghana, and Ivory Coast. This strategic project will have a capacity of 30 bcm/year of natural gas.

Africa’s Natural Gas Production and Consumption (bcm)

Africa’s Natural Gas Trade (bcm)

South & Southeast Asia

ABDUL AZIZ OTHMAN President, Malaysian Gas Association and IGU Regional Coordinator

Natural Gas: Fueling Southeast Asia’s Energy Security

Natural gas has long been recognised as the cornerstone of the region’s energy mix, serving as a cleaner-burning alternative for Southeast and South Asia. Countries in these regions have accepted natural gas as a crucial energy source in their transition towards a low-carbon future. This region’s unique energy needs are driven by population increase, rapid economic growth, urbanisation and a commitment to sustainable development. Balancing the energy trilemma – ensuring energy security, affordability and sustainability – remains the top priority. Unlike developed regions, many countries in Southeast and South Asia are still grappling with connectivity to basic clean energy supply issues. Therefore, the energy transition here is seen through a different lens, with greater emphasis on energy accessibility and affordability and, to a certain extent, energy security in the more developed areas or countries within the region.

Recognising the imperative for a sustainable and equitable energy future, a proactive approach and action plans are being adopted; individually (as a country) as well as collaboratively (regionally and with global communities). The World Economic Forum in January 2024 facilitated the establishment of ASEAN Leaders for Just Energy Transition (ASEAN JET), a CEO-led community of companies from across the region and different sectors. The community developed a Shared Aspirations document to foster a cohesive view on enabling a just energy transition in their region. The document outlines the community’s shared aspiration to facilitate the energy

transition by addressing the challenges in ASEAN. It also serves as a call for collaboration and proactive action around several priority areas.1

ASEAN’s Progress Towards Net Zero Emissions

Collectively taking significant steps towards achieving Net Zero emissions by 2050, the countries in the region have made robust commitments through various sustainable initiatives.

» One significant development of the Association of Southeast Asian Nations (ASEAN) is the progress made to strengthen the Cross-Border Collaboration under the ASEAN Plan of Action for Energy Cooperation (APAEC) Phase II 2016-2025.

o Progressive efforts in building an ASEAN Power Grid by expanding multilateral electricity trading to provide affordable and resilient electricity supply, while accommodating higher shares of renewable energy towards the energy transition and a sustainable energy future. Recently, several ASEAN countries agreed on the export and import of renewable energy, paving the way to speed up electricity grid connection between member countries within the region.

o In the gas sector, ASEAN will pursue the development of a common gas market by implementing the recommendations of the 2018 Gas Advocacy White Paper (GAWP), which includes developing communication strategies to promote gas advocacy and strengthening regional cooperation to improve commercial and infrastructure readiness.2

» Four ASEAN countries including Malaysia, Indonesia, Brunei and the Philippines will form a sub-region focus group to boost existing interconnectivity for green energy sustainability to boost green energy interconnectivity. Cooperation can be done immediately in the context of increasing the sharing of resources such as plant-based biofuels amid ASEAN’s abundant biomass resource.3

Growing Gas Demand Requires Continuous Infrastructure Development and Investment

Southeast Asia continues to be a region marked by population growth, rapid economic expansion and increasing energy

1. https://www3.weforum.org/docs/WEF_ASEAN_Leaders_for_Just_Energy_Transition_2024.pdf 2. https://asean.org/wp-content/uploads/2023/04/ ASEAN-Plan-of-Action-for-Energy-Cooperation-APAEC-2016-2025-Phase-II-2021-2025.pdf. 3. https://www.mida.gov.my/mida-news/four-aseancountries-including-malaysia-to-boost-green-energy-interconnectivity/

demands. According to the International Energy Agency (IEA) World Energy Investment 2024 report, the region would need to increase investment to over US$130 billion to align with the Announced Pledges Scenario (APS) by the end of the decade. There would also need to be a shift in the allocation of investment towards cleaner technologies: clean power would be the largest share of investment – nearly 40%.4 While challenges persist, the region has made significant strides in developing its gas infrastructure, with several countries investing in new pipelines, regasification terminals and gas power plants to meet growing demand.

» Malaysia’s Government implemented a proactive initiative to secure natural gas, such as necessary infrastructure and commercial arrangements for import, including long-term agreements to stabilise gas imports. In April 2024, the robustness of gas supply in the context of energy transition and ensuring electricity supply security in Peninsular Malaysia were among the key topics discussed at the first National Energy Council meant to set the direction and strategic policies for the nation moving forward. This initiative is set to examine the progress of flagship projects and initiatives under the National Energy Transition Roadmap (NETR), which anticipated an increase of natural gas in the total primary energy mix from 43% in 2023 to 56% in 2050.

» In an effort to lower unabated emissions, countries such as Singapore, Indonesia, Thailand and Malaysia established their carbon markets. This effort has gradually created interest in the market, and carbon trading is progressing steadily.

» The development and expansion of LNG Regasification Terminals is crucial for enhancing energy security and meeting the growing demand for natural gas. Countries like Thailand, Malaysia and Indonesia are investing heavily in LNG infrastructure. For instance, Thailand planned for its 3rd LNG regasification Terminal in Rayong province, with a capacity of 10.8 MTPA expected to be completed in 2028 to ensure the country’s energy security.

» Indonesia’s gas demand is projected to increase

significantly, with the need for LNG imports to bridge the supply gap. In 2025, Indonesia will need to procure 106 to 120 LNG cargoes (6.5 to 7.7 MTPA) to avoid a potential gas shortage, as domestic consumption growth outpaces supply. This significant increase in the demand-supply gap is due to the depleting supply of piped gas from mature fields in the West Java and Sumatra regions, while domestic demand is expected to rise. New projects, including the giant Abadi Field in the Masela block, are expected to be operational only after 2027.

Strategic Policies and Sustainable Regulatory Landscape

Countries in the regions have progressed in their policies and regulations to invigorate the gas market, stimulate gas supply development, enhance gas infrastructures and attract investments.

» Malaysia’s National Energy Transition Roadmap (NETR) outlines the country’s commitment to achieving Net Zero Emissions. The roadmap includes policies to increase the role of natural gas in the energy mix, focusing on sustainability and affordability. Recent government announcements have highlighted several key initiatives including:

o Malaysia is well positioned as a promising regional hub for Carbon Capture, Utilisation and Storage (CCUS) and aims to establish three CCUS hubs by 2030, with a shared storage capacity of up to 15 MTPA, about 300,000 barrels per day. The CCUS bill, set to be tabled in Parliament this November, will specify policies and incentives to regulate the activity and attract more investors.6

o The Ministry of Natural Resources and Environmental Sustainability in Malaysia will be setting up a National Decarbonisation Committee to comprehensively address the issue of climate change by reducing greenhouse gas (GHG) emissions, strengthening the country’s resilience towards the effects of climate change and promoting a transition towards more sustainable development and low carbon emissions. The National Climate Change Action Council (MTPIN), chaired by Malaysia’s Prime

4. https://www.iea.org/reports/world-energy-investment-2024/southeast-asia 5. https://www.nst.com.my/news/nation/2024/04/1033601/govt-discusesgas-supply-assurance-electricity-security-energy-councils#google_vignette. 6. https://www.bernama.com/en/news.php?id=2317561#:~:text=Under%20 NETR%2C%20Malaysia%20aims%20to,barrels%20per%20day%20(bpd).

Minister, agreed to approve the National Climate Change Policy 2.0 which will complement other initiatives, including drafting the National Climate Change Bill, developing the National Adaptation Plan and the National Carbon Market Policy.7

» Indonesia is at a critical juncture in its energy transition, aiming for Net Zero emissions by 2060. The country implemented several policy measures, including the Just Energy Transition Plan (JETP) and regulations to accelerate renewable energy development. Indonesia’s regulations, such as the Specific Natural Gas Price (HGBT) policy, aim to make gas more affordable for key industries. This policy, which sets a gas price of US$6/mmBtu for seven specific industrial sectors, is crucial for maintaining industrial competitiveness and supporting economic growth.

» Thailand is actively working on several specific initiatives related to CCS/CCUS and methane emission reduction. The Thailand National Committee on Climate Change Policy approved the establishment of the Greenhouse Gas Reduction Steering Committee, which initiated the technology applications for the country’s first CCUS, implemented by the PTT Group. The committee’s mission is to accelerate the actions that can mitigate climate impacts by applying CCUS technology in the energy and industry sectors, leveraging the knowledge and experiences in the petroleum exploration and production industry.8

» The Ministry of Trade and Industry (MTI) Singapore recently announced the Introduction of Energy Transition Measures which will amend the Energy Market Authority of Singapore Act (“EMA Act”), Electricity Act and Gas Act. Power generation, which is primarily from natural gas in Singapore, accounts for about 40% of the carbon emissions. To achieve Singapore’s 2050 Net-Zero ambitions, the Bill aims to develop different decarbonisation pathways, including updating their regulatory regime, energy markets and developing the energy infrastructure to ensure energy security and cost competitiveness in the power sector.9

» Vietnam, approved its 8th Power Development Plan in 2024, which seeks to reshape its energy system, including

extensive development of renewable technologies as well as the use of low-emissions hydrogen and ammonia and a reduction of its reliance on unabated coal. By 2030, Vietnam aims to diversify its energy mix significantly. According to the approved roadmap, the country plans to bolster its capacities in thermal, LNG thermal and coal-fired thermal power plants to 14,930 MW, 22,400 MW, and 30,127 MW, respectively.10

» The Just Energy Transition Partnerships (JETPs) launched in 2021 in Indonesia and Vietnam provide a framework to mobilise capital for investments in clean energy and support the phasing out of coal-fired power generation. The release of the Indonesia Comprehensive Investment and Policy Plan in November 2023 was an important milestone for the JETP and is expected to mobilise US$97 billion in power sector investments in Indonesia. The Asia Zero Emission Community initiative by Japan provides financial support of up to US$8 billion to 2030 for energy projects in participating countries namely Indonesia, Philippines, Thailand and Vietnam.11

» In summary, Southeast Asia’s gas industry is at a pivotal juncture, characterised by both challenges and opportunities in progressing their energy transition journey. The region’s ability to harness the potential of regional indigenous natural gas while embracing low-carbon technologies will be crucial in ensuring a sustainable energy future. Continued collaboration among governments, industry players and regional organisations is essential to achieve this goal.

South Asia: Embracing Innovative Solutions for a Secure Energy Supply and Meeting Growing Demand

South Asia’s rapidly growing population and economy have placed its energy sector on a robust growth trajectory. Total primary energy demand in South Asia is expected to grow by 77%, reaching 2,235 Mtoe by 2050, with India contributing 80% to this growth as a powerhouse for the region. According to the Gas Exporting Country Forum (GECF), natural gas, the cleanest burning hydrocarbon, is projected to raise its share in South Asia’s energy mix to 13% by 2050 from 9% in 2022. As a result, South Asia is turning to LNG to reduce coal dependency and boost renewable energy. Currently, natural gas in the

7. https://www.thestar.com.my/news/nation/2024/06/15/government-to-establish-national-decarbonisation-committee-says-nik-nazmi

8. https://www. eria.org/publications/carbon-capture-storage-and-utilisation--ccus--development-in-thailand 9. https://www.ema.gov.sg/news-events/news/mediareleases/2024/introduction-of-energy-transition-measures-and-other-amendments- 10. https://www.vietnam-briefing.com/news/vietnams-nationalelectricity-development-plan-2021-2030-roadmap-approved.html/. 11. https://www.iea.org/reports/world-energy-investment-2024/southeast-asia

region is predominantly consumed in the power generation and industrial sectors.12

» In India, natural gas is largely used in industry, although its share in the country’s energy mix in 2022 accounted for just 5%. To lower its carbon footprint, India aspires to raise gas’ share in the primary energy mix to 15% by 2030. Natural gas demand is set to more than triple from 61 bcm in 2022 to around 215 bcm by 2050.13 To enhance the utilisation of gas, the country has been pressing forward with various supportive policy measures, including extensive gas infrastructure developments and changes in regulation. The development of the National Gas Grid is a crucial enabler to improve gas accessibility across the country. To remove existing infrastructure bottlenecks and to spur regasification at the country’s LNG terminals, a huge investment program to add over 10,000 km of transmission pipelines to the existing long-distance network is underway.14

» For Bangladesh, natural gas has emerged as the primary fuel, making up around 55% of the energy mix over the last five years and is a main source for electricity generation. By 2050, natural gas demand is projected to double, reaching 60 bcm. Power generation is set to lead the increase driven by a sharp rise in electricity needs and the development of new CCGT capacities. Additionally, the overall trend is also underpinned by higher gas use in industry and residential segments. Given the anticipated growth in gas demand, LNG imports will increase and more regasification capacities are required. In this regard, in March 2023, Petro Bangla announced plans to construct three LNG import terminals (with a total combined capacity ranging between 15.5 to 23 MTPA.15

» In Pakistan, natural gas plays a significant role in the energy matrix, averaging 32% in recent years with significant demand in the residential, commercial, industrial and power generation sectors. Natural gas demand is forecast to grow by 19 bcm, exceeding 61 bcm by 2050, driven by its higher use in industry, power generation as well as in residential segment and transportation. To offset the long-term decline in domestic gas production, the country is anticipated to rely more on LNG imports. Several cross-border pipelines

are being planned (e.g. Iran-Pakistan and TurkmenistanAfghanistan-Pakistan-India) however, due to political and funding issues, the projects are not progressing as expected. With that in mind, LNG supplies are expected to shoulder the strain of plugging the gas demand-supply gap. Over time, LNG demand is predicted to almost triple from 7 MTPA in 2022 to 19 MTPA in 2030 and up to 31 MTPA in 2050. Recently, Pakistan has raised power prices by an average of 20% to bolster its chances of securing a new loan from the International Monetary Fund. The Government implemented power tariffs cut for industries to help make exports competitive.16

» This region is still experiencing challenges in terms of energy accessibility and affordability. Its countries are characterised by limited, stagnating or declining domestic gas production, alongside high energy demand growth rates and gradual introduction of policies geared towards boosting the use of natural gas to replace higher emission fuels. The natural gas demand and supply gap in the region is expanding rapidly, resulting in an increasing reliance on LNG imports. One possible solution is to enhance the gas infrastructure, seek funding and technical assistance from regional and international organisations. The region has a substantial potential for gas demand growth, which calls for special attention to help the region collectively transition towards achieving Net Zero Emissions.

12. https://www.gecf.org/events/exploring-the-future-of-natural-gas-and-lng-demand-in-south-asia. 13. https://www.gecf.org/_resources/files/events/ exploring-the-future-of-natural-gas-and-lng-demand-in-south-asia/eefd-ec-2024-demand-and-trade-in-south-asia.pdf. 14. https://www.pngrb.gov.in/ data-bank/NGPL-21022024.pdf 15. https://www.gecf.org/_resources/files/events/exploring-the-future-of-natural-gas-and-lng-demand-in-south-asia/ eefd-ec-2024-demand-and-trade-in-south-asia.pdf. 16. https://www.gecf.org/_resources/files/events/exploring-the-future-of-natural-gas-and-lngdemand-in-south-asia/eefd-ec-2024-demand-and-trade-in-south-asia.pdf

A lasting legacy

Madame Li Yalan has led the International Gas Union since 2022, and as its first Chinese president, she has guided the Union through one of the most turbulent times in its 93-year history. As her term as president approaches a close following the 2025 World Gas Conference in Beijing, Madame Li discusses what her leadership has brought to the IGU, the global gas market and to China’s role in the ongoing energy transition.

Q1. You have been president of IGU through one of the most complex times in its history given the volatility of the global energy markets, change in demand, and a much louder call for a faster energy transition. How has the IGU helped the global gas market navigate through this complexity?

1. Challenges we Faced

Looking back over the past two years, the global gas industry has undergone one of its most complex periods in history. This complexity arose from the simultaneous challenges of supply security and climate change.

1.1. Supply Security Issue: Years before the RussiaUkraine conflict and the Covid pandemic, global investment in natural gas had declined, putting pressure on the demand and supply dymanics. The reduction of pipeline gas flows from Russia to Europe due to the Russia-Ukraine conflict triggered an unprecedented change to global gas flows that sparked the global energy crisis. Natural gas prices soared worldwide, especially in Europe, while global LNG resources were drawn to Europe, severely suppressing demand in regions like Asia-Pacific and Africa. The crisis prompted a profound adjustment in the global natural gas market,

fundamentally altering trade patterns. It took nearly two years for the market to achieve a basic level of “rebalancing” and begin to recover from the crisis.

In early 2024, the Biden administration in the United States announced a temporary pause on pending decisions on exports of Liquefied Natural Gas (LNG) to non-Free Trade Agreement (FTA) countries, once again unsettling the fragile global energy market.

The ongoing Russia-Ukraine conflict, a new round of Israel-Palestine clashes, and the US presidential election, amongst many others, are among the political factors that will continue to impact the global energy market, particularly the natural gas sector.

1.2. Climate Change Challenge: In recent years, extreme weather events have increased globally, and the global temperature rise has gradually diverged from the goals of the Paris Agreement. One of the core components of the EU’s REPowerEU policy is to reduce natural gas consumption. At COP28, the decision to “achieve an energy system transition in a just, orderly, and fair manner, progressively moving away from fossil fuels” was incorporated into the Paris Agreement’s first global stocktake. As a fossil fuel, natural gas faces unprecedented scrutiny.

2. IGU’s Initiatives

In response to the aforementioned challenges, IGU has actively undertaken several initiatives:

2.1. Efforts to Promote Gas Supply Security IGU has actively advocated for increased investment in gas exploration, development, and infrastructure to help the global market emerge from the tight supply-demand situation.

2.1.1. During the IGU Council meeting in Peru, IGU hosted a seminar where representatives from Latin American oil and gas resource countries shared their experiences of developing and utilising natural gas resources. This event served as an opportunity to call for increased global investment in exploration and development and to bolster confidence in the industry’s growth.

2.1.2. At the executive committee meeting in Belgium, IGU organised a workshop that included participation from Mr Frans Timmermans, Executive Vice President of the European Commission, and officials from the EU energy sector. The meeting reviewed the lessons learned from the European energy crisis and analysed Europe’s experience in overcoming it. IGU used this opportunity to emphasise the importance of natural gas in ensuring energy security and to urge countries to invest more in exploration, development, and infrastructure.

2.1.3. In response to the US LNG export ban, IGU issued a public statement highlighting that the US decision to halt the review of LNG export projects sent a troubling signal to the global energy market. Restoring global LNG supply balance and energy security requires addressing current and anticipated shortages.

I delivered a keynote on the analysis of this very policy from the US government in the Global LNG Conference and Exhibition this April. I also shared IGU’s perspective regarding this policy to officials from US Department of Energy and Embassy of US to China when they visited me in June and hoping the US government would adjust the policy as soon as possible. IGU Secretary General Mr. Menelaos (Mel) Ydreos and Regional Coordinator for Europe, also then Chairman of Eurogas, Didier Holleaux, also sent letters to US authorities calling for a measured approach to LNG export issues.

2.2. Efforts to Address Climate Change

COP conferences are crucial platforms for the IGU to participate and share the industry’s voice. Notably, at COP28, IGU changed its approach to the conference from listening and “being there” to proactively voicing the natural gas sector’s perspectives. As IGU President, I was invited to the COP28 Summit on Methane and Other Non-CO2 Greenhouse Gases jointly hosted by China, the US, and UAE, where I highlighted the sector’s proactive measures in methane abatement, showcasing the

industry’s commitment to responsible practices. IGU also co-hosted a side event with Tsinghua University and CNPC at the China Pavilion, where we invited prominent figures such as Mr Xie Zhenhua, China’s Special Envoy on Climate Change, Dr Fatih Birol, IEA Executive Director, and Mr Mark Brownstein Vice President of EDF. The discussion focused on China’s efforts, progress, and opportunities for methane emissions abatement, and it also discussed methane emissions abatement in the oil and gas sector.

Furthermore, IGU organized an official side event to discuss accelerating methane control actions through multi-stakeholder cooperation.

During the conference, I also engaged with international organisations such as the GECF, the Global CCS Institute, and the World Biogas Association. These discussions helped build consensus and promote the natural gas sector’s role in addressing climate change. At this year’s COP29, IGU will host several events to actively highlight the global natural gas industry’s contributions to combating climate change and to foster international cooperation.

2.3. Conveying IGU’s Position and Views through Flagship Events

2.3.1. At the LNG2023, we highlighted the role of natural gas in maintaining global energy security and addressing the energy trilemma. The theme of LNG2023 was “Fueling a Secure Energy Future.” During the conference, we organized a Diplomatic Forum, inviting government officials and oil and gas industry representatives to share views on energy security. 2.3.2. At the IGRC2024, we focused on topics related to the natural gas industry’s own carbon reduction efforts and the role of natural gas in promoting the development of renewable energy. The conference provided an indepth exploration of the environmental benefits of natural gas. A significant number of sessions dealt with the necessary and evolving innovations in green gases, CCS and CCU.

In summary, as IGU President, I believe that the current complex situation presents both challenges and opportunities for the global natural gas industry. Given its clean, low-carbon, flexible, well-established infrastructure, resource abundance, and strong accessibility, natural gas will play a crucial role in maintaining energy security, facilitating energy transition, and shaping future energy systems. There is still significant potential for the development of natural gas globally. Countries should continue to invest in the natural gas industry to enhance its role in promoting global sustainable development.

Over the past two years, amidst a challenging

landscape, IGU has conducted productive work. Internally, IGU has fostered industry consensus, shared development experiences, and built confidence. Externally, IGU has utilised flagship conferences and multi-tiered outreach efforts to communicate the industry’s voice, reshape the image of natural gas, and create opportunities for the industry’s growth.

In 2023, global natural gas consumption saw a 0.04% growth compared to 2022 and reached 4010.2 billion cubic meters, which accounts for 23% of global energy mix.

Q2. Your role as president of the IGU will end with the close of WGC2025 in Beijing, at which time you will pass on the role to Andrea Stegher of Italy for the IGU’s 2025-2028 triennium. How important is WGC2025 not only to the IGU and its role in the global gas market but also to China as the third largest gas consuming market in the world?

The WGC2025 will be held from May 19 to 23, 2025, at the National Convention Center in Beijing. WGC2025 holds great significance for both the global gas industry and the Chinese gas sector, with far-reaching impact.

1. WGC2025 Will Be the Most Attractive WGC

The theme of this conference is “Energising a Sustainable Future”, focusing on six key areas: Global Energy Landscape, Energy Transition, Energy and Finance, Digitalisation and Technological Innovation, Regional Gas Development, Future of Global LNG. Industry leaders, renowned experts, and scholars from the global gas sector will converge in Beijing to discuss the future of sustainable development in the gas industry. This includes CEOs from top global oil and gas companies, international organisation leaders, and prominent experts and scholars. The conference will feature over ten awards, including the Global Gas Award, Regional Awards, and Industry Awards, recognizing outstanding papers and contributions to the field.

2. WGC2025 Will Be an Unprecedentedly Large Industry Event

The conference is expected to attract over 3,000 delegates from more than 70 countries. It will feature nearly 100 forums with over 500 international and national speakers. The exhibition will cover over 50,000 square meters, with approximately 300 global companies showcasing their offerings. More than 30,000 attendees are anticipated to visit the exhibition.

The conference will be held at the newly built Phase II of the National Convention Center “the most anticipated exhibition venue globally.” During the event, social

activities such as the President’s Dinner and Italy Night will be organised, providing attendees with opportunities to network, enjoy fine dining and scenic views, and foster collaboration.

3. WGC2025 Will Be a Milestone for China’s Gas Industry

WGC2025 will be the first WGC to be held in China in over 90 years since the founding of IGU. Hosting the WGC is a long-held dream of China’s gas industry professionals and marks the most significant international event in the oil and gas sector in China since the 15th World Petroleum Congress in 1997. Gas industry practitioners across China are highly focused on this conference and are expected to actively participate and share their valuable insights.

All three of China’s major national oil companies and the national pipeline company will participate and exhibit. Leading companies in China’s downstream city gas sector will also be present. Numerous internationally renowned companies engaged in oil and gas exploration and development, as well as gas trading enterprises, will also participate and exhibit. The conference offers a unique platform for supply and demand sides to connect.

4. WGC2025 Will Significantly Promote the Development of China’s Gas Market

As the world’s third-largest natural gas consumer, largest natural gas importer, and largest LNG importer, China represents the market with the greatest potential for future global gas development. Currently, China’s natural gas consumption is approximately 400 billion cubic meters, accounting for approximately 10% of the global total. The proportion of natural gas in China’s primary energy consumption is only 8.5%, significantly below the world average. It is projected that by 2030, China’s total gas consumption will reach 500 billion cubic meters, and by around 2040, it will exceed 650 billion cubic meters. In the future, China will further increase its natural gas imports, especially LNG, and enhance the diversification of its import sources. This conference will provide a rare opportunity for international resource companies to expand into the Chinese market.

5. Ancient, modern and dynamic host city - Beijing Beijing, with its unique blend of ancient and modern charm, has a rich cultural heritage dating back 3,000 years. It is home to seven UNESCO World Heritage Sites, making it the city with the most World Heritage Sites globally. In addition to its rich historical and cultural background, Beijing is renowned as a gastronomic capital, ranked eighth in the world’s top food cities by Forbes. May in Beijing is particularly beautiful, with pleasant weather, lush greenery, and blooming flowers, making it one of the most picturesque times of the year.

6. WGC2025 Will Inject New Momentum into the Global Gas Industry

Firstly, holding WGC in China, the country with the greatest potential for gas growth, will boost confidence among global gas professionals. This confidence serves as a driving force for the growth of the global gas market, drawing the attention of industry stakeholders and garnering active support from the global gas community.

Secondly, the WGC platform will allow China to learn advanced technologies and management practices from developed countries. At the same time, China’s rapid development in the gas sector will serve as a model for other developing nations.

Thirdly, WGC2025 will have a profound impact on the global gas industry. The year 2025 will mark a milestone in the history of gas, with a more balanced supply and prices. Global gas professionals will face challenges with greater confidence. WGC2025 will leave a significant mark on IGU’s legacy.

Q3. The theme for WGC2025 is Energising a Sustainable Future. Could you talk about how the IGU is leading the movement of ensuring the sustainability of the global natural gas industry?

As the most authoritative international organisation in the gas industry, IGU’s mission is to “promote natural gas as a key component of future sustainable energy systems.”

To achieve this mission, IGU has focused on several key areas:

1. Revising IGU Position Papers

We have updated IGU’s position papers to guide the global gas industry in appropriately positioning natural gas under new circumstances, and to further clarify development strategies and directions.

Firstly, I would like to acknowledge my predecessor, President Joe M. Kang, who established the initial IGU position papers during his term. Building on his work and addressing the new challenges faced by the industry, I have led IGU in developing updated position papers. These documents serve as IGU’s global advocacy manual for the gas industry and hold significant importance for our organization.

Here are some key positions of IGU:

1.1. Natural gas is an essential global energy source, playing a crucial role in combating air pollution, improving quality of life, and reducing CO2 emissions.

1.2. Social, economic, and technological progress depends on access to reliable, affordable, and secure energy.

1.3. Due to its inherent advantages, natural gas is a crucial solution for addressing energy challenges and

combating climate change.

1.4. Natural gas is the ideal partner for renewable energy; together, they will drive the future energy transition.

2. IGU promotes sharing, communication, and mutual learning within the global gas industry through its meetings and events.

IGU holds its Executive Committee and Council meetings in different regions around the world each year. During these meetings, regional seminars are also organised, where IGU members share experiences, results, and best practices in areas such as industry policy, market development, technological innovation, and methane reduction.

During the Council Meeting in Australia, IGU members focused on discussing and sharing insights on new gas development strategies and case studies, methane control measures in the gas industry, and net-zero and decarbonisation strategies of major oil and gas companies. These exchanges and shared experiences provide valuable references for the sustainable development of IGU members.

3. IGU empowers a sustainable future by advancing industry research and technological progress.

IGU leverages its committees and working groups as key tools for driving sustainability. The organisation has 11 committees and three special task forces. The committees cover the entire industry chain, from exploration and development to end-use, while the task forces focus on carbon neutrality and digitalisation. Currently, nearly 600 industry experts from over 40 countries contribute to these committees and task forces, addressing the most pressing and significant issues in the industry. The committees periodically share their research reports and showcase their findings at the WGC.

The Carbon Neutrality Task Force, in collaboration with the Research and Development and Innovation Committee and the Sustainability Committee, has compiled a report on advanced low-carbon and renewable gas technologies both within and outside the industry, promoting the development of new technologies. The task force also conducts in-depth research on the impact of GHG Protocol on the gas industry.

4. IGU promotes industry sustainability and empowers a sustainable future by issuing calls and initiatives.

IGU advocates for companies within the industry to implement strict methane reduction measures, actively adopt methane reduction guidelines, and conduct greenhouse gas emission measurements. IGU also encourages its members to actively develop new gases such as renewable gas and hydrogen, continuously increasing the supply of low-carbon and zero-carbon

During the high-level dialogue sessions at LNG2023, I focused on cases of the coupling development between natural gas and renewable energy in China.

gases. Additionally, IGU promotes the active development of key technologies such as CCS and CCUS to reduce carbon footprints.

5. IGU calls for increased investment in the gas industry.

On one hand, the IGU President encourages and urges members to boost investment in the gas sector to ensure energy security. Additionally, IGU officials, including the President and Secretary General, use opportunities at major international conferences to advocate for greater support for the gas industry to promote its sustainable development.

On the other hand, IGU maintains communication and establishes cooperative relationships with international financial institutions such as the World Bank, AIIB, Asian Development Bank, and African Development Bank. The aim is to address and overcome biases against investing in the gas sector, supporting investment in natural gas projects.

Q4. The International Gas Research Conference 2024 in Banff highlighted the role of innovation in creating a sustainable future for natural gas and other gaseous fuels like hydrogen. What role do you see the IGU taking in the ongoing pursuit of innovation and increased sustainability for natural gas?

Innovation is a perennial theme in the gas industry, and IGU is committed to promoting innovative development, playing both a leading and supporting role.

1. IGU sets the direction for innovation.

IGU across the global gas markets and maximising the benefits of natural gas. Could you discuss three key successes you have observed flowing from TWP 20222025?

Considering the state of IGU and global trends in the gas industry and the expectations various stakeholders have, the Chinese Presidency developed a Triennial Work Programme for the 2022-2025 term. The theme is “Maximising Gas Benefits,” and it focuses on three pillars of work: Gas Industry: We are committed to maximising gas benefits. Organisation: We aim to bring the IGU to the new heights. Membership: We are dedicated to improve IGU membership experience.

and responsibilities of Secretariat staff, and enhance IGU’s policies and regulations. The Chinese chairmanship team worked closely with the Secretariat team to address a series of issues, ensuring that the Secretariat’s operations were fully on track.

3. Membership: the third success is the highlighting regional characteristics IGU encouraged members from Asia, Africa, and Latin America to actively participate in IGU activities to promote the development of the local gas industry.

2. IGU provides platforms for innovation. The organisation’s several committees and task forces cover the entire industry chain, serving as international innovation platforms. During my term as IGU President, we established the Digitalization Task Force and Carbon Neutrality Task Force to explore the intersection of gas and digital technologies, as well as innovations in the carbon neutrality field.

3. IGU encourages and shares innovation.

We organise a series of innovation forums at our flagship conferences to share transformational results and exchange experiences. At WGC2025, we will introduce the Global Gas Awards, Industry Awards, and Regional Awards to recognise and promote innovation. IGU also uses governance meetings to facilitate industry seminars, inviting member representatives to share best practices in industry innovation. For instance, at the IGU Council meeting in Perth, Premium Associate Member The Hong Kong and China Gas Company Limited shared its advancements in blending hydrogen with natural gas and the utilisation of hydrogen in Hong Kong, setting an example for densely populated cities. The Japan Gas Association shared progress on new models for synthetic methane production, transportation, and utilisation, showcasing innovative experiences in zero-carbon methane development.

Q5. The IGU’s Triennial Work Programme 2022-2025 was an ambitious undertaking aimed at enhancing the profile of the

In the face of global climate change and energy security challenges, IGU advocates for advancements in technologies combining natural gas with renewable energy, as well as innovations in low-carbon and zerocarbon gases, synthetic methane, carbon capture and storage (CCS), carbon capture, utilisation, and storage (CCUS), and methane reduction. IGU also promotes the integration of digital technologies with traditional industries and encourages innovation in business models and pricing mechanisms to boost industry vitality, reduce costs, enhance affordability, and improve the safety and reliability of gas.

1. Gas Industry: the first notable success is actively enhancing the influence of IGU and advocating for natural gas through multi-tiered external relations initiative.

During my tenure as IGU President, a strategic cooperation agreement was signed with GECF and we are currently in the early stages of collaboration with EMGF. We also maintained good cooperation with organisations such as the OGCI, IPIECA, the World LPG Association, SGMF, GEIDCO, and the World Nuclear Association. We have also established initial cooperation with the World Biogas Association, the Global CCS Institute, and SIGTTO.

Through interactions with these international organisations, we have built consensus on sustainable development, leveraging each other’s platforms and channels for collaborative growth. IGU has also been more actively present at COP conferences, engaging in high-level outreach to showcase the industry’s responsibility and commitment.

Additionally, IGU has used the release of flagship reports as an opportunity to invite stakeholders from both the political and business sectors to participate in discussions, highlighting the crucial role of natural gas in sustainable development and calling for a rational and objective approach to gas development, thereby expanding IGU’s influence.

2. Organisation: the second success is the transition of the IGU Secretariat’s operational model from a sponsored to a permanent secretariat during the Chinese Presidency.

Since IGU’s establishment back in 1931, the IGU Secretariat had been sponsored by various member organisations until the 2019 Council meeting decided to establish a permanent secretariat for modernisation. In 2022, IGU officially transitioned to an independently operating secretariat model.

During my tenure, IGU recruited a new Secretary General. I required the Secretary General to further clarify the Secretariat’s business responsibilities, adjust and improve its organisational structure, define the roles

The number of Regional Coordinators was increased from seven to eight, with the new position of Regional Coordinator for Africa being established. Africa, with its rich oil and gas resources and significant market potential, will benefit from having more African industry professionals voice their concerns within IGU, enabling greater participation from developing countries in Africa and providing IGU with a more balanced and comprehensive perspective.

Regional reports were published. In 2023, with the support of the Regional Coordinators for Latin America and the Caribbean, as well as for Africa, IGU released the white paper titled “Gas in Latin America and the Caribbean: Transitioning to a Low-Carbon Economy” and the “2023 Africa Gas Report”.

Q6. How has your role as IGU President enabled you the opportunity to show the world China’s ambitious climate targets?

In September 2020, President Xi Jinping announced China’s targets of reaching peak carbon emissions by 2030 and achieving carbon neutrality by 2060 during the 75th United Nations General Assembly.

China has not only set these ambitious climate goals but has also implemented a series of effective actions, including establishing the “1+N” policy system and aggressively developing renewable energy. China accounts for 47% of global photovoltaic power installations, 45% of wind power installations, and has a total of 20.41 million new energy vehicles, including 15.52 million electric vehicles. At the same time, natural gas plays a crucial role in China’s journey towards its dual carbon goals and continues to be a major focus for development.

As the first Chinese President in IGU’s history, I have the opportunity to inform the world about China’s efforts and progress through the IGU platform.

1. Utilising International Conferences to Present Relevant Information

For example, at the International Energy Week in London, I highlighted the crucial role of natural gas in China’s carbon reduction efforts, detailing the ambitious methane reduction targets set by Chinese oil and gas

companies, their concrete efforts, and the advanced methane reduction technologies in use.

At COP28, during the methane and non-CO2 summit hosted by China, the US, and the UAE, I used China’s methane reduction and greenhouse gas mitigation practices as case studies to demonstrate the country’s commitment to achieving its “dual carbon” targets.

2. Informing the World Through IGU’s Committees and Task Forces

Within IGU’s committees and task forces, 73 experts from renowned Chinese companies and research institutions, such as PetroChina, CNOOC, Peking University, and Towngas Energy, contribute to various research efforts. These experts share the latest research results on the development of China’s gas industry and its efforts toward achieving the “dual carbon” targets, offering valuable insights and contributions from China.

3. Presenting Information Through IGU’s Flagship Conferences

At WGC2022, as the then-IGU Vice President, I participated in the plenary discussions, presenting the future opportunities and targets for natural gas in China under the “dual carbon” goals. During the high-level dialogue sessions at LNG2023, I focused on cases of the coupling development between natural gas and renewable energy in China. At IGRC2024, several experts from China provided detailed introductions and engaged in discussions with international peers about advanced emission reduction technologies and operational models in the Chinese oil and gas sector.

At next year’s WGC2025, we will organise a series of forums on climate change and energy transition, inviting leading domestic and international enterprises and renowned research institutions to explore the pathways for energy transition and achieving dual carbon targets.

Q7. What do you see as your legacy contribution to the IGU and to the global natural gas market?

1. Contribution to IGU

During my term, I strengthened IGU’s internal governance, laying a foundation for its efficient and stable operation and for the union to fulfill its role more effectively.

Firstly, I led the revision of the AoA. Under my leadership, we established an AoA Revision Task Force, which extensively consulted with IGU members and, based on their feedback and the evolving external circumstances, revised the AoA. This enhancement allows IGU to better serve its members internally and to achieve its vision and promote sustainable development externally.

Secondly, I facilitated a smooth transition to the independent secretariat. At the beginning of the independent secretariat’s establishment, the IGU governance system and operation need to be adapted to the new model accordingly. After becoming president, I initiated and resolved a series of issues, including the recruitment of the Secretary General, membership surveys, and improving the Compensation Committee.

I also addressed issues related to the secretariat’s accounts and registration, successfully completing the transition to the new operational model. Additionally, I visited the London secretariat and engaged in face-toface discussions with staff and local members. Through these efforts, I ensured that the secretariat’s operations were standardized, more efficient, and better able to serve its members.

Thirdly, I created more value for members. We utilised the opportunities provided by the Executive Committee and Council meetings to actively organize workshops, inviting members to share their development experiences from different perspectives and encouraging Executive Committee members to review and forecast industry developments.

The governance meetings during the Chinese presidency offered participants fresh international perspectives and development experiences. The activity levels of various committees continued to rise, with nearly 600 industry experts from around the world actively participating in committee work.

Many committees even held offline meetings in China, facilitating exchanges between members and the Chinese gas industry. During the Chinese presidency, we focused on enhancing the quality and impact of flagship reports.

The global LNG report project managed by CNOOC received widespread recognition in the industry and also increased CNOOC’s international influence as an IGU member.

2. Contribution to Advancing the Global Gas Market

Firstly, I promoted the development of IGU’s position papers, which clarified the role of gas, outlined the future direction of the industry, eliminated external biases against natural gas, and helped shape a positive image for the gas sector, thereby instilling confidence in the industry’s development.

The IGU position papers represent a global consensus within the gas industry. They highlight the advantages of gas in addressing the energy trilemma, its significant role in replacing coal and advancing renewable energy development, and also emphasise the need for the gas industry to accelerate its own emission reduction efforts. In response to doubts and biases against the development of natural gas, I addressed these concerns directly and

objectively through IGU’s flagship events and participation in various international forums.

Notably, at COP28, I provided a comprehensive overview of the global gas industry’s achievements in methane reduction, which was recognised by the international community. This has been effective in dispelling biases, bridging differences, and bolstering confidence in the global gas industry.

Secondly, I enhanced the voice of developing countries in the gas industry.

Some developing countries are major producers or consumers of natural gas. These countries often lag behind developed economies like those in Europe and North America in terms of economic development, and their gas industries are relatively nascent and less advanced, resulting in weaker influence in the international market. During my tenure as President, I focused on creating more opportunities for representatives from these countries to share their perspectives on the gas industry, articulate their needs, and showcase their achievements. By providing them with more platforms for dialogue and interaction, I aimed to enhance their voice and influence in the international gas market.

Thirdly, I strengthened engagement with stakeholders through multiple levels and platforms.

Against the backdrop of energy transition, communication between the gas industry and sectors such as renewable energy, climate change, and finance has become increasingly important. During my tenure as President, I enhanced interactions with international

organisations, research institutions, and relevant enterprises in these fields. I participated in a series of meetings focused on topics like climate change, renewable energy development, gas power generation, and energy finance. Through these events, I promoted the advantages of gas in addressing climate change and energy transition, called for rational investment in the gas industry, and worked to dispel biases and misconceptions. This approach aimed to strengthen confidence among stakeholders, fostering deeper future cooperation across industries.

Fourthly, I am promoting international cooperation through the hosting of WGC2025.

WGC2025 is set to be one of the most significant events in the global energy sector in recent years. The conference will provide a rare opportunity for face-toface exchanges among gas-importing and gas-exporting countries, resource-rich and consuming nations, as well as developing and developed countries.

WGC2025 will showcase the latest technologies, development concepts, successful management experiences, and best practices across the entire gas industry value chain, potentially driving considerable progress for the sector. Although the conference has yet to take place, the current enthusiasm for participation and exhibition from the global gas industry is exceptionally high.

We are confident that WGC2025 will become a milestone in advancing international cooperation in the global gas and energy industries.

Madame Li and Robert Johnston, executive director of Columbia Center for Global Energy Policy at LNG2023 in Vancouver, Canada.

Energy markets are looking to gas to meet sustainability goals

The International Gas Union’s upcoming World Gas Conference in Beijing will showcase the sustainability attributes of natural gas

DALE LUNAN

The global energy landscape is evolving rapidly, with environmental and geo-political forces continuing to reshape global energy markets.

Emissions reductions are front of mind, but as events since Russia’s invasion of Ukraine more than two years ago demonstrate, energy security and energy affordability – the two legs of the energy trilemma stool apart from sustainability – are more important than environmental considerations in many regions of the world.

Natural gas can deliver on all three of those goals, even as jurisdictions world-wide push for increased electrification as a path to sustainability.

The International Gas Union’s flagship World Gas Conference 2025 (WGC2025) in Beijing next spring will showcase the role natural gas can play in future energy systems, including those targeting net-zero by 2030 or 2050.

“Whether through clean energy initiatives, emissions reduction projects, or community empowerment efforts, gas has the power to transform lives, build resilience, and create shared prosperity,” the IGU says on its WGC2025 website.

Other key themes on the agenda in Beijing include the role of natural gas in providing energy security, the future of the global LNG market, the integration of natural gas with renewables and the global diversity of natural gas exploration and production.

Natural gas in future energy systems

Ed Kallio, executive advisor at Canadian natural gas consultancy Incorrys, tells Global Voice of Gas (GVG) this “tension” in the global sustainability and emissions reduction framework, is at the heart of efforts to both reduce CO2 emissions and meet increasing energy demand as global energy systems evolve.

“Going forward, we cannot have secure and affordable energy to meet rising global demand without natural gas,” he says. “Notwithstanding aspirational global sustainable development goals (SDG’s), largely enacted in western economies via national legislation, there is no way for western economies to quickly replace natural gas in power generation and residential sectors, and meet rising demand, without causing energy poverty.

Derek Wissmiller, director strategic analytics at GTI Energy, in a June blog post, outlined GTI Energy’s thoughts on what future energy systems might look like and how natural gas will fit into those systems.

“Net-zero energy systems rely on electricity. Netzero energy systems rely on fuels. And net-zero energy systems rely on vast infrastructure networks to move and store those electrons and fuel molecules, delivering energy where it’s needed, when it’s needed,” he wrote.

In the US, Wissmiller wrote, some 82% of all end-use energy is supplied as a gaseous, liquid or solid fuel, with electricity accounting for the remaining 18%.

In GTI Energy’s study of potential net-zero energy systems, which incorporate more than 20 scenarios, the share of electricity grows substantially, to between 36% and 59% of final energy use, with increased adoption of electric vehicles, electric space heating and industrial electrification.

And fuels continue to play a critical role in supporting this expanded electricity demand, with fuel-based power generation providing firm capacity to balance the intermittency of renewables and demand fluctuations.

Across GTI Energy’s scenarios, end-use energy consumption underpinned by fuel ranges from 42% to 81%.

The Oxford Institute for Energy Studies (OIES), in a study of three energy transition scenarios and their impact on natural gas, found that global gas demand will not peak at less than 4,300 bcm/year or earlier than 2030. Under its most bullish Declared Policies Scenario, demand will peak around 2040 at 4,700 bcm/year, while under its NetZero with CCS (NZwithCCS) scenario, a peak of just over 4,300 bcm/year will be reached in 2030.

A third scenario, dubbed the Fragmented (FRAG) scenario, in which different jurisdictions move at various paces along the decarbonisation path, shows peak gas use at just under 4,000 bcm/year.

Under both the FRAG and NZwithCCS scenarios, the OIES says, substantial investments in carbon capture and storage (CCS) will be needed to keep natural gas relevant past 2040.

In the NZwithCCS scenario, abated gas, whether at the burner tip or through the incorporation of blue hydrogen or biomethane, is 85% by 2050, with significant abatement in North America, Russia, China and the Middle East.

In the FRAG scenario, 45% of gas is abated by 2050, with strength in the US and Europe but much less abatement in Africa, Asia (Japan, Korea and Taiwan),

Russia, the Caspian region and South Asia.

“The key conclusion is that if gas is to remain a significant fuel in a rapidly decarbonising world, then the industry needs to invest in an enormous amount of CCS,” the study concludes.

Even with those challenges, fuels continue to be “ubiquitous” in net-zero systems, Wissmiller notes, supplying roughly half of all end-use energy consumption. With fuels continuing to be used for transportation, building heating and heavy industrial processes, the share of energy delivered to end-use customers as fuel ranges from 41% to 64% across GTI Energy’s net-zero scenarios.

“Net-zero energy systems are “yes, and” energy systems,” he writes. “Yes, to the expanded role of electricity. Yes, to the enduring role of fuels. And yes, to the at-scale infrastructure needed to move and store electrons and fuel molecules in net-zero energy systems.”

Just where natural gas fits into those energy systems, says Cameron Gingrich, manager, markets and strategy at Incorrys, depends largely on whether the energy system serves a developed economy or a developing economy.

In developed economies, Gingrich notes, energy delivery systems are already highly reliable, and the role of gas in meeting environmental, sustainability and governance (ESG) goals of those systems is largely focused on meeting supply security and affordability imperatives.

Natural gas and renewables

This is a rapidly growing issue in the power generating sector, where utilities are becoming increasingly reliant on natural gas for baseload generation even as renewables continue to grow at a record pace.

Because of the volatility of renewables, power generators also need to incorporate natural gas into their systems for when renewables inevitably drop off the grid, wrote Gavin Maguire in a July commentary for Reuters.

“The ability of natural gas to speedily plug supply shortfalls from other sources means the fuel will remain a critical pillar of the US power system for years to come, despite continued rapid growth in renewable energy sources,” he wrote.

In the US Southeast, key utilities like Duke Energy and Georgia Power want fossil fuel generation to remain part of their energy mix in the face of anticipated recordbreaking power demand in the years ahead.

Duke wants regulatory approval for three new gasfired plants providing 4,000 MW of capacity, while Georgia Power is asking for approval to install 1,400 MW of gas-fired capacity by the winter of 2026-2027 alongside 200 MW of new solar paired with the same capacity of battery storage and 1,000 MW of stand-alone battery storage.

But renewable integration issues aren’t just a matter of concern in the power-hungry Southeast. The North American Electric Reliability Corp (NERC), in its Summer 2024 Reliability Assessment, says natural gas supply and infrastructure is “vitally important” to electric grid reliability, particularly as what it calls “variable energy resources” are increasingly used to meet demand.

“Fuel supply and delivery infrastructure must be capable of meeting the ramp rates of natural gas-fired generators as they balance the system when wind and solar generation output declines,” NERC says.

While utilities in developed economies struggle with integrating natural gas with renewables, developing economies, just want to give their citizens access to reliable and secure energy at an affordable cost, Gingrich says.

“In developing economies ESG principles are not primary as these nations source cheap and reliable energy to grow GDP and increase living standards,” he tells GVG. “Greener imported natural gas and renewable sources will continue to face competition from available and affordable higher emitting options such as coal and oil.”

The role of LNG

WGC2025 will also focus on the future of global LNG trade as the super-chilled gas emerges as a critical energy carrier in global markets. From technological improvements to regasification opportunities under evolving market dynamics, LNG is experiencing a new wave of momentum, the IGU says.

Shell, a global LNG leader, forecasts the market will grow by around 50% by 2040, from about 400 mtpa in 2023, as Asian economies grow and gas replaces coal in power generation.

Shell’s own LNG sales volumes are expected to climb by 20-30% by the end of this decade, to 87 mtpa from 67

“Net-zero energy systems are “yes, and” energy systems. Yes, to the expanded role of electricity. Yes, to the enduring role of fuels. And yes, to the at-scale infrastructure needed to move and store electrons and fuel molecules in net-zero energy systems.”

DEREK WISSMILLER, DIRECTOR STRATEGIC ANALYTICS, GTI ENERGY

Global gas developments

Natural gas markets, even in the context of an energy transition, remain vitally important at the country level, a reality that will be brought into sharp focus at WGC2025.

“Differences in resource endowments, economic development stages, and social challenges significantly influence the global energy development landscape,” the IGU says. “Based on these differences, the pathways to addressing energy transition issues vary.”

At a country level, the Republic of Congo is driving an ambitious gas monetisation agenda led its Minister of Hydrocarbon, Bruno Jean-Richard Itoua and Congo’s national oil company, La societe nationale des petroles du

Congo as a regional gas hub. With over 10 tcf of natural gas resources, the development of Congolese gas is critical to ensuring that the regional economy not only survives but thrives.

And in India, the Minister of Petroleum & Natural Gas, Hardeep Singh Puri, told a New Delhi even in July that exploration and production investment opportunities in the country could reach as high as $100bn by 2030.

India has 26 sedimentary basins, but the true potential of those have yet to be monetised, he said.

“Only 10% of our sedimentary basin area is under exploration today,” he said. “After the award of blocks under the forthcoming Open Acreage Licensing Policy

mtpa in 2023, with about half that coming from projects now under construction, including Qatar’s North Field expansion, the 14mn tonnes/year LNG Canada project, in which Shell holds a leading 25% interest, and Nigeria’s NLNG facilities.

The latest BP Energy Outlook, published in July and examining energy demand under both a Current Trajectory scenario – climate policies already in place –and a Net Zero scenario – tighter policies targeting Paris Agreement goals – sees LNG demand growing rapidly until 2030, by 40% under the Current Trajectory scenario and by 30% under the Net Zero scenario.

Under the Current Trajectory scenario, LNG demand continues to grow by more than 25% between 2030 and 2050, requiring 300 bcm of additional liquefaction capacity beyond 2030.

Under the Net Zero scenario, however, gains in LNG demand out to 2030 are reversed between 2030 and 2040, and by 2050 global LNG trade falls some 40% below 2022 levels, suggesting that additional capacity beyond what is already under construction is not required.

Uncertainty in Europe as the end to RussiaUkraine gas transit deal looms

A number of options have been raised to ensure that transit continues in the likely event that the contract is not renewed. Failure to achieve this would have major implications for a market still struggling with historically high energy prices.

The European energy market is bracing itself for yet another potential supply shock – the likely expiry of the Russia-Ukraine gas transit deal at the end of this year. Expectations that these deliveries will be disrupted in the middle of winter are already putting upward pressure on European gas prices. And if a solution is not found to avoid a complete cut-off, European buyers could be hit by an unwelcome price spike at a point in the year when ample gas supply will be needed most.

Despite the Russo-Ukrainian conflict, Russian gas transit via Ukraine has continued, albeit significantly below the pre-war level. Supplies through Ukraine to Europe and Moldova amounted to 13.7 bcm last year, down from 41.6 bcm in 2021. Yet given Russia’s drastic cuts in shipments over the last two years, this still amounts to around half of the country’s total pipeline gas supplies to Europe.

Russia transits gas through Ukraine under a five-year contract between Moscow and Kyiv that came into force

at the start of 2020. Even back then, in peacetime, this agreement was not easy to reach, as Russia was at the time scrambling to complete the now-unusable Nord Stream 2 pipeline to divert more gas directly to Germany.

A deal was struck at the eleventh hour on December 30, 2019, with no small amount of brokering by European authorities.

The situation now is, of course, radically different.

While Russia has said it is open to negotiations on continuing the gas transit beyond this year, Ukraine has ruled this out as an option. And the European Commission is far less inclined to encourage talks between the pair.

In February this year, EU Energy Commissioner Kadri Simson said that Brussels had “no interest” in extending the transit agreement, explaining that “based on our preliminary analyses, there are alternative solutions to supply these countries who still receive some gas through the Ukrainian route.”

Even so, not all stakeholders in Europe feel the same

way. In June this year, Bloomberg reported that European governments were engaging with Ukrainian counterparts on options to keep the gas flowing next year.

Options for continued transit

One option that has been raised is using Ukraine’s pipelines to flow gas to Europe from Azerbaijan. This would mean less direct interaction between Moscow and Kyiv, which would be preferable for reaching a solution. But the two sides would still need to reach a border interconnection agreement. And Azeri gas would still have to pass through Russia first before entering Ukraine, creating a security of supply risk and increasing the cost through transit fees to Russia. And this is assuming that Moscow would be open at all to letting a competitor use its territory to transit gas when it has ample spare supply of its own.

Alternatively, Azeri gas could be shipped through the 24-bcma South Caucasus Pipeline (SCP) and the 17.5-bcma Trans-Anatolian Pipeline (TANAP), and then northward through Bulgaria-Romania pipelines into Ukraine. But both SCP and TANAP are already running at full capacity and final investment decisions (FIDs) have not yet been taken on their expansion.

Most importantly, Azerbaijan lacks the spare gas supply in the short term to replace Russian volumes, as energy researchers Anne-Sophie Corbeau and Tatiana Mitrova noted in a blog post for Columbia University’s Center on Global Energy Policy in July 2024.

The Azeri government and the European Commission signed a memorandum in 2022 to boost Azeri gas supplies to Europe to 20 bcma by 2027. But speaking to The Financial Times in late July 2024, the head of Ukraine’s national gas company Naftogaz, Oleksiy Chernyshov, estimated that Azerbaijan would only be able to pipe 2 bcma of gas via the country’s territory – far less than the amount Russia currently sends.

Alternatively, Azerbaijan and Russia could arrange to virtually swap gas supplies. In this scenario, Russia would continue pumping gas to its border with Ukraine, at which point it would be titled as Azeri gas. In turn, Azerbaijan could deliver gas to another country, likely Turkey, with it becoming titled as Russian gas upon entry into the market.

An alternative idea that has been floated is European companies or countries taking responsibility for Russian gas at the Russia-Ukraine border as well as its transit through Ukraine. Energy expert Thierry Bros sees this as the most likely option to emerge, as it will involve fewer participants reaching an agreement, namely Russia, Ukraine and European gas purchasers, rather than also having to bring Azerbaijan and possibly Turkey into the mix. Existing contracts between Russia and its gas

customers in Europe could be maintained, and Russia and Ukraine would likewise avoid having any direct dealings, beyond reaching a border interconnection agreement.

No deal impact

While Europe is now far less reliant on Russian gas than it used to be, a sudden end to transit would still have a major impact on the market, as Russian supplies via Ukraine still cover 4-5% of total EU gas consumption. Europe has overcome the worst of the energy crisis, but wholesale gas and power prices are still two to three times higher than historical norms and global gas supply remains tight. This makes the market very vulnerable to supply shocks. This vulnerability has been demonstrated by several spikes in gas prices in recent months.

In June this year, an unplanned outage in Norway, now Europe’s top gas supplier, triggered a jump in prices. In July, shutdowns at the Ichthys LNG plant in Australia and the Freeport LNG terminal in the US also led to a price response. The market has also felt the reverberations from escalating tensions in the Middle East.

Gas has become all the more important as an insurer of stable energy supply as the EU relies increasingly, over time, on intermittent renewables, which generated close to 45% of the bloc’s electricity last year.

If there is a disruption in Russian gas transit via Ukraine, Rystad Energy notes that the countries most reliant on this supply are Austria, Moldova and Slovakia, which took 5.7 bcm, 2.0 bcm and 3.2 bcm of gas via the route last year. Slovenia and Croatia also take some Russian gas via this route.

Rystad estimates that these countries would need to tap an extra 7.2 bcma of LNG to replace Russian gas, assuming there is no Azerbaijan or another third party transiting the gas following a swap deal with Russian gas via Ukraine last year. These supplies could be forwarded from terminals in Poland, Germany, Lithuania and Italy.

Moldova has already agreed with Ukraine on continuous Russian gas flow until the end of 2025. This supply covers 74% of its consumption, with the rest of the sources coming from Romania and the south through reverse flows via the Trans-Balkans. After this deal’s expiry, Moldova would need to reroute this gas, possibly through Trans-Balkan reverse flow. Russian gas could enter Moldova via the Isaccea entry point between Romania and Ukraine, but a transit agreement for the 25-km distance through Ukraine would still be required, according to Rystad. Moldova could also tap Azeri gas via the Southern Gas Corridor and LNG from Turkish and Greek import terminals via the south.

As for other countries, the only alternative to Russian supply routes would be the Balkan Stream and the Horgos

JOSEPH MURPHY

entry point between Serbia and Hungary, Rystad notes.

Without Russian gas, Slovakia would need about 4 bcm of gas delivered through the Lanzhot entry point from Czechia. With extra regasification capacity in Poland only available in 2025, it may need to reverse flow gas from Austria in the event of zero Russian gas flow through Ukraine.

Austria, the biggest receiver of Russian gas in Europe last year, would have to ramp up imports from Germany via the Oberkappel entry point, set to operate at a maximum of 8 bcma. Rystad estimates, using 2023 as a baseline, that Oberkappel’s import capacity will not be enough to close the 8.53 bcm import gap. Without shortterm capacity adjustments, gas transits to Hungary would drop, and outflows to Italy would be halted. If Russian gas flow via Ukraine completely ceases, Austria would need to import up to 2.5 bcm from Italy via the ArnoldsteinTarvisio crossing point.

Italy is largely free from relying on Ukrainian gas transit already, but it would have to source around 3.75 bcm for Slovakia and Austria, which it could do from the 5-bcma Ravenna floating storage and regasification unit (FSRU), due online in 2025, and 1.23 bcm in pipe gas from Tunisia.

Hungary would face significant challenges in the event of Russian gas flow via Ukraine halting, according to Rystad. If Moldova is supplied via the south, capacity via the Trans-Balkan pipeline from Romania would be fully allocated, halting inflow from Romania. Moreover, Austria would not be able to forward gas to Hungary, while Croatia will not have extra regasification capacity

Azerbaijan needs long-term contracts to ramp up European gas supply

Azerbaijan has the resources to deliver more gas supply to Europe, but in order to make the necessary investments in fields and pipelines, long-term commitments from European buyers, international financing and clear statements from Brussels that gas is a transition fuel are needed.

JOSEPH MURPHY

Azerbaijan is bullish on the potential to expand its natural gas exports to the EU, helping the bloc shore up its energy security and wean itself off Russian gas supplies. But its government insists that long-term contracts and financing are needed to support the necessary investment in supply and the infrastructure to carry it.

The government in Baku signed a memorandum with the European Commission in 2022 on doubling Azeri gas shipments via the Southern Gas Corridor (SGC) to 20 bcma by 2027, supporting the EU’s push to eliminate Russian gas imports fully by that year. Experts have cast doubt on whether this goal will be reached so quickly, but shipments are nevertheless growing, with 12 bcm delivered via SGC last year, up 45% from their level two years earlier.

Supporting future growth is a raft of new upstream projects in Azerbaijan. These include the Absheron field, the first phase of which was launched by national oil company SOCAR and France’s TotalEnergies last year.

The phase will produce 1.5 bcma of gas at peak, and a second phase is set for launch in 2028, contributing 4 bcma. A third phase slated for commissioning in the early 2030s would bring output to 7 bcma.

There are seven projects in total that are due to be approved or commissioned by the end of the decade, according to Rystad Energy, the biggest of which are the Umud, Babek and Shafag-Asiman developments. The Norwegian consultancy projects that Azeri national output will rise from 36.3 bcm in 2024 to 39.5 bcm in 2026, and above 40 bcm by 2029.

Lack of European support

Azerbaijan currently delivers gas to seven European markets – Bulgaria, Greece, Hungary, Italy, Romania, Serbia and Slovenia – and it plans to expand its reach to more countries in southeast Europe over the coming years. All this was possible thanks to the development of the SGC, a 3,500-km network of pipelines, the final leg of

which, the Trans-Adriatic Pipeline (TAP), started flowing gas at the end of 2020. SGC was completed with the help of significant EU political and financial support, including various loans and grants, and backed by long-term supply contracts with buyers.

That same kind of support does not appear to be now forthcoming, and EU authorities and financiers are more reluctant to invest in further expansion of SGC and the fields that would feed it with gas because of the perception that further investments in gas are at odds with climate objectives. As it has been seen in LNG contracting, this thinking has trickled down to European gas buyers, who have favoured shorter-term contracts, partly because of expectations that European gas demand will drop rapidly over the coming years, as envisaged in the European Commission’s REPowerEU plan. When recommending that the EU adopt a target to cut GHG emissions by 90% by 2040, the Commission said this would require demand for oil, gas and coal to shrink by 80% versus their levels in 2021.

However, financing and long-term contracts are critical for Azerbaijan to deliver on the 20-bcma export target, Azeri President Ilham Aliyev stressed at a forum in April 2024. The European Investment Bank (EIB) has stopped financing oil and gas projects while the European Bank for Reconstruction and Development (EBRD) only supports a small share of such developments, he said. Companies typically fund only 30% of gas production and infrastructure on the projects and rely on loans to cover the remainder, according to the president.

The EIB and the EBRD both gave key support to the development of SGC and associated projects in the past.

Long-term guarantees are needed as “Azerbaijan cannot invest billions only for 5-10 years and not be able

to recover the costs,” Aliyev said.

He added that the country was still paying back loans it received for SGC and the Shah Deniz Stage 2 project that provided its gas.

Azerbaijan’s ambassador to the EU, Vaqif Sadiqov, likewise warned in an interview with The Financial Times in July this year that the EU could not treat the country as a “firefighter” by only agreeing to short-term gas deals.

“We cannot be a firefighter just sending gas for three to six months,” he explained. “We need the contracts so that we can go to banks for financing for drilling deep into the Caspian Sea.”

Not on track

Azerbaijan wants to double TAP’s capacity to 20 bcma, and increase capacity at SGC’s other two sections, the Trans-Anatolian Pipeline (TANAP) and South Caucasus Pipeline (SCP), from 16 to 31 bcma and 24 to 31 bcma, respectively. Rystad’s vice president for upstream research, Swapnil Babele, warns that this appears to be “a far-fetched goal,” as the first stage of TAP’s expansion, due for completion by the end of 2025, will only add 1.2 bcma.

“Achieving the goal hinges on securing long-term commitments and commercial agreements from European buyers, as these pipeline extensions are expensive and will require significant investments,” he told Global Voice of Gas.

The plan to grow gas exports to Europe is “not nearly on schedule,” Matthew Bryza, managing director of Straife and former US Ambassador to Azerbaijan, added.

“Potential investors worry if they’re going to be able to raise enough financing if there isn’t clear long-term demand for offtake by European consumers for the next

“Achieving the goal hinges on securing longterm commitments and commercial agreements from European buyers, as these pipeline extensions are expensive and will require significant investments.”

25 years, or whatever the lifetime of the project is,” he said. “Not only does there need to be a burst of financing, but also clear statements by the European Commission and member states that gas is a necessary transition fuel.”

Even though gas demand is set for decline in Europe, Thierry Bros, professor at Sciences Po Paris, notes that extra supply will be needed to eliminate Russian gas imports by 2027, as the EU plans. If Europe does not agree to long-term contracts with Azerbaijan for this gas, Turkey may step in and reach agreements, and then sell the gas at a premium to European buyers under shorterterm contracts and spot deals, he said. Turkey is looking to expand gas supplies to neighbouring Bulgaria and aspires to establish itself as a regional hub for gas trade.

Sustainability

The EU has recognised gas as a sustainable investment in its updated taxonomy, and embraced the need for greater energy security in light of the Russia-Ukraine conflict. Failure to support investments in Azeri gas supply would go against this positioning, Bryza said.

The Southern Gas Corridor company is drawing up an investment plan with potential support from the EBRD, but the bank has said it can only finance an expansion in the pipeline’s capacity if the project aligns with the

goals of the 2015 Paris climate accord. This could be demonstrated through the potential for Azeri gas to displace coal in power systems in southeast Europe, where use of the fuel is still present. The case could also be supported through ongoing improvements in tackling methane emissions associated with upstream operations. Furthermore, SGC’s expansion could be regarded as a future-proof investment in the energy transition if the pipelines are one day used to flow clean hydrogen from Azerbaijan. Azeri authorities have raised this prospect, noting that the pipeline system could one day pipe large amounts of green hydrogen to Europe, produced using offshore wind farms. The case for blue hydrogen is less viable in the country, because of a lack of available CO2 storage space.

The Azeri government is planning a significant build-out of renewables over the coming years, having inaugurated its first 240 MW solar plant last year. It aims to break ground on a further 1.3 GW of wind and solar projects this year, and to generate 30% of its power needs with renewables by the end of the decade. Some of this capacity could be used for hydrogen production but, in the nearer term, a greener grid in Azerbaijan would also free up more gas currently used domestically for export to Europe.

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SWAPNIL BABELE, VICE PRESIDENT FOR UPSTREAM RESEARCH AT RYSTAD ENERGY

The role of Middle Eastern gas in the energy transition

Increased natural gas use in the Middle East has supported oil exports and met burgeoning power demand. Now, the expansion of clean energy can support LNG exports to coal-dependent Asia, diminishing carbon emissions both at home and abroad.

If there is one stand out trend across the Middle East over the last decade, it is the increase in domestic gas use, primarily for power generation. Intra-regional gas trade has also grown, with LNG imports and exports providing flexibility amid a still limited set of regional pipelines. This has provided energy security for those countries unable to meet rising gas demand from their own resources.

Gas inputs for electricity (Figure 1) in the Middle East jumped from 567 TWh in 2013 to 1,028 TWh in 2023, while oil use for power dropped by about 19%. Prior to that, oil use in power generation was on a strong upward trajectory, with 2013 marking the high point.

Middle Eastern electricity consumption has risen at a rate of 3.8%/yr over the last decade, second only to Asia, and substantially higher than the world average of 2.5%/yr. While absolute emissions have increased, as economies have grown, more gas use and a growing share of non-fossil fuel alternatives have reduced the overall carbon intensity per kWh generated.

Why? Because natural gas has displaced oil.

Reducing coal use is the primary objective in Asia, which last year consumed near on 6.9bn tons of the carbon heavy fuel. However, in the Middle East, which consumes negligible quantities of coal, the challenge is still oil. Burning crude, fuel oil and diesel provided 308.9 TWh of power for the region in 2023.

The recognition of gas’ value as a domestic fuel meant it has been used with ever more efficiency. Now it is natural gas’ turn to become the principal export, facilitated by the growth of domestic clean energy.

Repositioning Middle Eastern natural gas

The United Arab Emirates (UAE) appears to be ahead of the curve. Marking an individual reversal of the regional trend, the country has seen a reduction in gas inputs for power generation each year since 2020, owing to its investments in nuclear power and renewables.

The UAE has brought four South Korean-built nuclear

reactors online since 2020, providing it with 5,348 MW of baseload generating capacity. The last of the four units became operational in March this year. As a consequence, nuclear generation rose to 32.2 TWh last year and will jump higher this year and next as Unit 4 ramps up to full capacity and operates over the full course of a year.

The UAE has also been at the forefront of the region’s adoption of solar power with, at end-2023, installed capacity of 5.9 GW, a 65% increase on 2022. Solar generated 13.7 TWh of electricity last year. Further capacity additions will see its share of domestic power generation rise.

The country’s updated Clean Energy Strategy 2050 envisages a tripling of renewable energy by 2030 with the share of clean energy capacity installed rising to 30%. By 2031, the UAE also aims to be producing 1.4mn tons/yr of hydrogen, rising to 15mn t/yr by 2050.

Reducing Asia’s coal addiction

Just as the move from oil to gas made more oil available for export, the shift from gas to lower carbon generation sources should support the export of gas, primarily as LNG. A large part of this LNG will end up in Asia, where it can displace both oil in transport and coal in power and heat provision.

Asia’s gas demand is forecast to rise 78% by 2050 to reach 1,590bn m3, according to the Gas Exporting Countries Forum, equating to a 16% share of the region’s energy mix, compared with 11% in 2022. This will be driven by a combination of electrification and coal-to-gas switching. Although Asian gas production will increase, it will not do so fast enough to keep pace with demand. The GECF estimates that gas exports to Asia will, by 2050, exceed 50% of the region’s total consumption.

If gas is not available, Asia’s retreat from dependency on coal will be slower.

Middle Eastern LNG expansion

A significant proportion of Asian gas demand can be met by Middle Eastern countries. While Qatar has taken the lead with its giant North Field expansion, other countries also recognise the potential.

The UAE built its first LNG plant in 1977, consisting of two 1.15mn MTPA trains, to which a third 3mn MTPA train was added in 1994 at Das Island. With upgrades and debottlenecking, capacity currently stands at 6mn MTPA. Operator ADNOC announced this year the country’s first major expansion of its LNG capacity since 1994 with plans to build two new 4.8mn MTPA trains at Ruwais. On June 12, ADNOC announced that a final

ROSS MCCRACKEN

Figure 1: Middle East: power generation by source (TWh)

If there is one stand out trend across the Middle East over the last decade, it is the increase in domestic gas use, primarily for power generation.

investment decision had been taken and the project would proceed. A $5.5bn engineering, procurement and construction contract for the liquefaction plant was awarded to a joint venture led by France’s Technip Energies, which includes Japan’s JGC and the UAE’s NMDC Energy. US company Baker Hughes will build the LNG export terminal.

Notably, the new LNG plant will run on low carbon power, using electric drive systems for gas compression, taking advantage of the country’s nuclear and solar generation to reduce the emissions intensity of LNG production. ADNOC is also electrifying its offshore oil and gas operations, which is expected to reduce their carbon footprint by up to 50%.

Similar thinking underpins neighbouring Oman’s Vision 2040. Although the country has not gone down the nuclear route, it is expanding low carbon power generation through renewable independent power projects. The target is 20% of electricity demand being met by renewables in 2030, rising to 35-39% by 2040. This will reduce the domestic call on gas for power generation.

The country’s installed solar capacity exceeded 1 GW for the first time last year and will take a major leap upward with the completion in 2025 of the 500 MW Manah 1 project. In March this year, a competitive tender was launched for five new wind projects totalling about

900 MW of capacity.

Although yet to take a final investment decision, Oman is considering an expansion of its LNG export capacity as demand growth in electricity consumption is met by renewable energy instead of more gas-fired plant. Oman has three LNG trains in operation with total capacity of 11.5mn MTPA. A fourth train would provide a further 3.6mn MTPA.

Alongside Qatar’s much larger expansion of its LNG export capacities, the Middle East’s LNG producers will likely fill a significant proportion of Asia’s growing need for imported gas over the next decades. Together with the accelerated growth of renewables, this could eventually turn the tide on the 135.7 exajoules of coal consumed in Asia in 2023.

Intra-regional gas trade

Not all countries in the Middle East are gas rich and not all have developed gas supplies in excess of domestic demand. LNG has been key to filling the gaps (Figure 2). Kuwait, in particular, has struggled to slow a decline in its domestic gas production. LNG imports, more than half sourced from Qatar, have helped it balance supply with demand. Kuwaiti LNG imports have risen from 2.3bn m3 in 2023 to 8.9bn m3 last year.

Jordan has also relied on LNG imports in addition to pipeline supplies, bringing LNG into its Floating Storage

and Regasification Unit (FSRU) at Aqaba. The facility, which has capacity of 3.8mn MTPA, has demonstrated its utility by also being used as a conduit for LNG imports to Egypt, where an unexpected decline in gas output from the offshore Mediterranean Zohr field has left the country with a gas deficit.

Dubai has imported LNG from Qatar and Abu Dhabi, as a means of addressing a local imbalance in gas demand and supply, supporting the steady increase over the last decade in intra-regional gas trade. This has been reinforced by gas flows between Iran and Iraq. Although this has helped Iraq meet rising domestic gas demand, it faced interruptions in pipeline deliveries last year and has reportedly experienced payment difficulties as a result of sanctions on Iran.

To address this, the Iraqi government has approved a proposal to build an import terminal at the Grand Fao Port in Basra, most likely using an FSRU to import LNG. In addition, in July, Iran signed a deal with Turkmenistan for the delivery of 10bn m3 of gas, which it will ship onward to Iraq. Iran will build a new 124-km pipeline to facilitate the trade. Iran’s gas balance remains positive, but only just, as demand for power generation has increased significantly over the last decade, hitting a record 323.6 TWh last year.

Not all countries in the Middle East are gas rich and not all have developed gas supplies in excess of domestic demand.

Gas use in the Middle East has been pivotal in meeting regional power demand and providing energy security. It will continue to do so for many years, even as renewable energy generation expands. But as renewable energy replaces gas in the Middle East, that gas can be used to displace coal in Asia, offsetting in revenue terms the potential decline in oil demand and therefore exports implied by net zero targets. The acceleration of renewable power in the Middle East will make gas more available where it is needed most, and pay for the investment in the process.

Guyana’s emerging gas sector

After a meteoric rise in its oil output, Guyana is now working with stakeholders to craft a national strategy to maximise the economic benefit of its substantial gas resources.

JENNIFER DELAY

The last decade has been transformational for Guyana’s oil and gas sector. Since 2015, the South American country has gone from having no verified commercial petroleum resources at all to boasting more than 11bn boe of total recoverable reserves. Almost all of these volumes lie within Stabroek, an offshore block operated by ExxonMobil. The US major began development operations in 2019, and since then Guyana has gone from producing no hydrocarbons of its own to extracting more than 600,000 bpd of crude from three production sites at Stabroek.

ExxonMobil knew before it began oil production that it would have to make provisions for this gas. In its original environmental impact assessment (EIA) for the Liza-1 project, it stated that it expected its first floating production, storage and off-loading (FPSO) vessel, the Liza Destiny, to extract 100,000 bpd of crude and 180 5.1 mcmpd of associated gas. It further reported that it had made plans to utilise as much as of this gas as possible, designating nearly 89% of the total or 4.53 mcmpd for reinjection and most of the rest for use as fuel on the FPSO.

pipeline to pump associated gas from Liza-1 and other offshore oil fields to shore. Georgetown, meanwhile, committed to building the onshore component of the project – a complex consisting of the pipeline’s onshore terminus, a 300 MW combined-cycle TPP and other facilities capable of receiving and using gas, including a natural gas liquids (NGL) plant – at the site of a former sugar plant in the town of Wales. ExxonMobil agreed to cover the approximately $1bn cost of the pipeline, while the Guyanese side agreed to cover the remaining costs, estimated at around $800mn.

However, the EIA also said that “some gas may be occasionally flared on a non-routine, temporary basis,” and ExxonMobil was later reported to have reached an agreement with Guyana’s government that capped flaring volumes at 424,800 cmpd. The US major had the goal of capping routine burn-offs at a much lower level. However, it failed to meet that goal in its first year of operation, as problems with the Liza Destiny’s flash gas compressor (FGC) repeatedly pushed flaring volumes to 453,000510,000 mcpd over the course of 2020.

These problems persisted into 2021, but ExxonMobil was eventually able to replace the malfunctioning FGC with better equipment. It also took this experience into account when preparing to launch Liza-2, its next production project, and used a more advanced design for the gas compression system of the Liza Unity, its second FPSO. As a result, the Liza Unity and the Prosperity, the FPSO installed for ExxonMobil’s third production project at the Payara field, have been able to dedicate even larger shares of their total gas production to re-injection and to onboard fuel consumption. These vessels do continue to flare gas occasionally, but they generally do so within the bounds of ExxonMobil’s agreements with Guyana’s Environmental Protection Agency (EPA).

Gas-to-Energy (GTE)

Work on the GTE project was slow to begin due to issues with permitting and financing. As of late April 2024, however, ExxonMobil had already finished more than 70% of the pipeline and was preparing to suspend production at the Liza-1 and Liza-2 fields so that they could be connected to the conduit. The company then began linking Liza-2 to the pipeline in mid-July 2024 and was expected to begin a similar process at Liza-1 soon thereafter. The pipe will have an initial capacity of 1.42 mcmpd, with gas flows rising later to 3.4 mcmpd as additional fields are connected.

The Guyanese side, meanwhile, is moving more slowly due to foundation problems at the construction site, work delays and rescheduled equipment deliveries. In February of this year, Winston Brassington, the head of the government’s GTE task force, announced that Georgetown was pushing the expected completion date for work on the onshore pipeline terminus, a gasprocessing facility and the 300-MW TPP back from late 2024 to mid-2025. He noted that ExxonMobil was still due to finish the pipeline before the end of the year but indicated that gas would not start flowing until mid-2025. At that point, he said, the Wales TPP will begin operating at a capacity of 200 MW, rising to its full capacity of 300 MW by the end of next year.

The meteoric rise in oil output has somewhat obscured the fact that Guyana also possesses substantial gas resources. ExxonMobil has estimated that associated and natural gas account for about 20% of Stabroek’s total recoverable reserves, or around 481 bcm, and

other companies are hopeful of finding more gas at other blocks. These volumes will not go to waste, as Guyana’s government is working with ExxonMobil and other stakeholders to formulate a national gas strategy that includes gasifying the economy and perhaps eventually exporting LNG as well. It is worth exploring these plans for future development, both at Stabroek and other projects.

Current gas production

Thus far, Guyana and ExxonMobil have made the development of Stabroek’s oil reserves their first priority. However, they have also had to make provisions for gas, as the block’s largest oilfields also contain significant volumes of associated gas that must either be flared or put to use.

ExxonMobil’s initial troubles with gas flaring led the Guyanese government to look more closely at proposals for making associated gas from the Liza oil field available for domestic use. Those proposals focused on the prospect of piping gas to shore for use in a thermal power plant (TPP) that could turn out electricity more cheaply, efficiently and cleanly than the residual fuel oil-burning facilities owned by Guyana Power & Light (GPL), a stateowned utility.

The gas pipeline plan was first mooted in 2015 but remained on hold as of 2020. In 2021, however, it secured the approval of the Guyanese government, and negotiations with ExxonMobil commenced. The parties eventually agreed to invest nearly $2bn in the scheme, which was eventually dubbed the Gas-to-Energy (GTE) project.

Under this plan, the US major pledged to build a

Guyana is therefore now in the position of being a small-scale gas producer, since ExxonMobil, the operator of the country’s only operating fields, is extracting associated gas at its three oil production sites. It is making only limited use of this gas, though, since it does not yet have domestic transportation or distribution networks.

New legal regime

This lack of infrastructure has not discouraged the Guyanese government from making plans for gas, however. To facilitate implementation of these plans, it has enacted a number of legal reforms affecting the oil and gas sector.

These reforms include the Local Content Act and the National Resources Fund (NRF) Act, which were both approved by Parliament in late 2021 and signed

by President Irfaan Ali in early 2022. The two acts are general in nature rather than oil- or gas-specific, with the former seeking to ensure that developers of both oil and gas procure a minimum share of goods and services from local suppliers and the latter seeking to ensure proper governance of money earned through oil and gas sales.

Guyana has also taken the more consequential step of enacting a new oil and gas law to replace the Petroleum Act adopted in 1986. This new law, known as the Petroleum Activities Act, was passed by Parliament and then signed by the president in the third quarter of 2023. The legislation is general in nature and does not aim explicitly to foster gas development or utilisation, but it does include language that may affect future gas projects. Specifically, it outlines the circumstances under which Guyana can work with its neighbours to promote joint development of petroleum deposits that extend beyond the country’s land and sea borders.

These provisions, which lie within the section of the Petroleum Activities Act covering unitization of adjacent licence areas, may prove significant in light of the fact that Stabroek’s natural gas reserves appear to be concentrated in the eastern section of the block. Stabroek does, as noted above, contain mostly oil, but it also holds natural gas as well as associated gas. Moreover, the majority of the natural gas lies in fields such as Pluma and Haimara that are located close to Guyana’s maritime border with Suriname. Indeed, Haimara is less than 10 km away from Maka Central, one of the oil and gas fields within Suriname’s Block 58 that France’s TotalEnergies will be targeting in its first production project. The French major is due to make a final investment decision (FID) on this project by the end of 2024 and then launch development operations in 2028.

There has been talk about combining gas production efforts at Stabroek and Block 58. In March of this year, Suriname’s national oil company (NOC) Staatsolie began talks with ExxonMobil and TotalEnergies about the possibility of joint gas extraction.

Future gas developments

It is not yet clear whether these discussions will bear any fruit. Nevertheless, Guyana’s government has been pressing ExxonMobil to speed up implementation of gas projects. In February 2024, for example, President Ali

The last decade has been transformational for Guyana’s oil and gas sector.

called for “immediate” development of the country’s gas resources and urged the US major to expand the scope of its gas production plans to include exports, perhaps in the form of LNG and perhaps by pipeline to other countries in the region.

ExxonMobil has responded to this pressure by noting its plans to drill more exploration and appraisal wells in the sections of Stabroek that are thought to contain the most gas. It has also agreed to give gas development a higher priority. Nevertheless, Georgetown decided earlier this year to publish a request for bids (RFB) for the design, construction, operation and financing of domestic infrastructure for the extraction and transportation of gas.

As for the Guyanese government, it stands to begin reaping the benefits of the GTE project starting next year. This project is expected to give a boost to the country’s economy by making more electric power available at a much lower cost to both business and residential customers.

In June, it announced that it had chosen Fulcrum LNG, a newly founded company headed by a former ExxonMobil executive, to execute the project, which has been valued at $10-15bn.

This scheme, which will encompass the development and export of gas, is still in its early stages, as the parties have yet to finalise a contract. Guyanese officials have indicated, though, that they expect Fulcrum LNG and its partners – including Baker Hughes, the US oil field service giant, and McDermott, a major US-based engineering firm – to collaborate with ExxonMobil on a stand-alone gas project.

In the meantime, the prospects for development of Guyanese gas reserves beyond Stabroek are at an even earlier stage. Canada’s CGX Energy, along with its partner and parent company Frontera Energy, has found mixed oil, gas and condensate deposits in Kawa-1 and Wei-1, the first two exploration wells drilled in the northern section of Corentyne, an offshore block that lies immediately south of Stabroek along the maritime border with Suriname. However, the Canadian company has yet to state definitively whether these two fields hold enough liquids and/or gas to justify commercial development. It did file a notice of commercial interest in Wei-1 in early August this year in a bid to secure more time for exploration, but Guyana’s government indicated on August 14 that it had rejected the company’s request.

As a result, said Minister of Natural Resources Vickram Bharrat, the licence for Corentyne will now revert to state ownership.

Since CGX Energy had been talking about making an FID in 2026 and then moving to the development

phase in 2030, this development means that Stabroek is overwhelmingly likely to remain the only oil- and gasproducing block in Guyana’s offshore zone. As such, ExxonMobil will continue to lead the way in developing the country’s gas reserves for the time being. For now, that means concentrating on the GTE project and deciding where the collaboration with Fulcrum LNG will go.

Cheaper and cleaner energy

As for the Guyanese government, it stands to begin reaping the benefits of the GTE project starting next year. This project is expected to give a boost to the country’s economy by making more electric power available at a much lower cost to both business and residential customers. GPL’s tariffs currently stand at $0.25-0.36/ kWh but are expected to drop to $0.06-0.07 once the Wales TPP comes online.

Cheaper electricity is not the only value offered by GTE, however. The project will also reduce Guyana’s

carbon emissions intensity by allowing GPL to shutter its existing facilities – namely, a power station that burns residual fuel oil and diesel-burning generators with a combined capacity of around 180 MW – and replace them with a cleaner, more efficient gas-fired combined-cycle TPP. In the process, it will also lay the groundwork for the development of the country’s gas resources on a larger scale – large enough, officials in Georgetown hope, to make Guyana into a regional gas hub capable of supplying a region that now depends on dirtier oil-based fuels. In turn, gas development is expected to help Guyana retain its status as a net carbon sink. The country has said it intends to preserve more than 99% of its existing rainforests, which cover more than 180,000 km2. These forests are capable of removing more than 154 MT of carbon dioxide equivalent (tCO2e) per year from the atmosphere, and the projected emissions from ExxonMobil’s Stabroek project are expected to make up no more than 6% of that total.

New Zealand lays the groundwork for new oil and gas exploration

A blanket ban on new oil and gas exploration in 2018 shocked businesses across the country. A new government recognises the importance of oil and gas to energy security and has set about to rebuild the sector.

Now New Zealand’s oil and gas industry, after facing years of an uncertain future, is firmly back open for business.

In early 2018 New Zealand’s industrial base and energy sector was blindsided by a ban on new oil and gas exploration. The intent was to hasten the electricity sector’s growth moving to 100% renewable system by 2030. We were not ready then, and we are not ready now. Thankfully, sanity has prevailed, and New Zealand is steering back onto the correct course. The catalyst for this change? A new centre-right government was formed in November last year replacing the left-wing government led by its Prime Minister, the Rt Hon. Jacinda Ardern, which imposed the ban.

Our new Prime Minister, the Rt. Hon. Christopher Luxon from the National Party, has formed a government with the centre right ACT party and the centrist NZ First party.

Make no mistake, this is great news for the New Zealand economy, the oil and gas sector and the wider energy sector.

EXECUTIVE, ENERGY RESOURCES AOTEAROA

As Kiwis went to the polls in late 2023, it was clear that we needed a step change. These three coalition partners went into the 2023 election campaign with platforms focused on more investment, more jobs and greater reliance on homegrown energy. Voters agreed.

The new government was concerned that the pursuit of climate change objectives had put our energy security at risk and pledged to reverse the ban on new oil and gas exploration. Core to achieving its energy aspirations has been an early pivot back to using the wealth under our feet – New Zealand’s abundant natural coal, oil, and gas resources.

The drivers behind this pivot are clear – New Zealand has an economy in the doldrums, a huge increase in our government spending, and a cost-of-living crisis with rampant inflation only being tamed by rising unemployment. Our export-dependent economy is being buffeted by global forces we have little control over.

An electricity system wholly dependent on the weather is still not currently feasible or affordable and it still requires thermal firming to ensure homes stay warm and

our industrial base isn’t crippled by very high energy prices.

To leverage the natural advantages we do have, the newly elected Government immediately split the energy and resources portfolio into two. For years this had been treated as a single role, and the shift change towards a sole Minister for Resources signals not only how highly the new government values our resources sector, but the work needed to achieve our resource goals.

Our mineral and petroleum resources sector now looks to rebuild and has a champion within government and, more importantly, around the world, in our new Resources Minister, the Hon. Shane Jones. Minister Jones has embarked on an international travel programme to promote New Zealand’s resources to global investors.

Petroleum is already a crucial part of New Zealand’s economy. The oil and gas sector contributes billions of dollars to New Zealand’s GDP and earns the government hundreds of millions of dollars in royalties, with oil exports in 2022 valued at around NZD 900 million, and Crown revenue from petroleum at NZD 214 million between 2022 - 23.

To sustain current use of natural gas, New Zealand needs to invest. This is the only way we can get the most out of our existing fields and explore new fields.

To make this happen, our new Government has set to work. In a set of recent announcements, it has committed to a focused programme set to breathe life back into the oil and gas sector.

To do this it has developed a legislative programme that will see the release of new exploration acreage. It’s

going to improve the decommissioning rules to reflect industry best practice, shorten regulatory approval time frames, and review the royalty regime to ensure it attracts investment.

Why do we need to promote the sector?

New Zealand has a proud history of oil and gas exploration dating back to the late 1880s. While the inevitable investment cycles have ebbed and flowed over decades, recent policy shocks have chilled investment and resulted in low confidence from the sector.

History will not judge the Ardern Government kindly when considering its energy policies, the effects of which may take decades to address.

The most egregious of these was 2018’s shock announcement to immediately ban the new oil and gas exploration permits (with one on-shore regional exception). This policy announcement came out of the blue, with no mention of it in the run-up to the 2017 election, and no reference to it in the Labour Party manifesto.

At the time, New Zealand was the only country in the world to have carried out this kind of radical and far-reaching policy change.

The economic implications were relatively foreseeable. The ban coincided with major gas fields reaching near end-of-life status. The government was warned repeatedly by the sector that a ban would strangle the gas market by failing to meet its need for investment in new opportunities. Instead, new exploration activity was confined to relatively small existing permit areas.

Figure 1: Estimated supply and demand next 12 months (PJ)

JOHN CARNEGIE, CHIEF

Unsurprisingly, because of this, New Zealand now faces natural gas supply shortages.

The sector has been left trying to squeeze existing mature fields harder and harder just to keep the gas flowing over the last six years, with little success. Reduced output has come at a significant economic cost, especially to major export industries.

Compounding this problem is our lack of LNG import infrastructure. All of our gas production is used domestically.

We’ve previously had a system that was demandconstrained – where the level of demand set how much gas produced – but in a few short years, we’ve moved to being supply constrained. This means that the level of deliverable gas sets how much can be supplied, and that demand needed to drop to match.

This is shown in the previous two graphs. Two things are immediately obvious. We have significant levels of unmet demand (Figure 1), and deliverability is expected to continue to trail demand (Figure 2).

What has this meant for New Zealand?

The effect of the ban, six years on, has been catastrophic for our economy, environment and people.

We now see an energy system in distress. Gas shortages and high gas prices and, given the importance of gas in our electricity system, growing insecurity of electricity supply and rapidly elevating electricity prices. In turn, increased energy hardship has resulted for ordinary Kiwis while strangling the international competitiveness of our gas-reliant heavy industry.

As Kiwis went to the polls in late 2023, it was clear that we needed a step change.

Major gas and electricity users are having to reduce production so that the gas and electricity markets can work.

While New Zealand is growing as a world leader in renewable electricity generation (averaging around 85%), and this is expected to grow to over 90%, the intermittency and variability of our weather-based system needs to be backed by fossil fuels. Coal imports have filled the gap left by reduced gas supply, creating an environmental own goal.

How are we going to fix this?

Our pathway to a solution is clear – either New Zealand must encourage the production of more natural gas or start to import LNG. The new government cannot afford to waste time and hasn’t.

Work on these issues is proceeding at pace. There are

now significant opportunities for international investment in our jurisdiction.

Investors who were badly spooked by the 2018 announcement and a range of subsequent announcements aimed at suppressing the role of natural gas in the economy are weary of returning to New Zealand.

This is openly acknowledged. Both government and the industry, including its peak body Energy Resources Aotearoa, are collaborating to find a pathway for capital to return to New Zealand. Changes are actively being considered to protect against capricious policy changes that harm long-term investment decisions.

New Zealand’s energy resources sector remains an exciting and dynamic investment prospect. We are blessed with abundant energy resources – and we have the physical and human infrastructure to bring it to market.

We’re consistently ranked as one of the best countries to do business and confer a globally recognised reputation as a clean, green, responsible investment destination.

New Zealand is back open for business – and we’d love to hear from you.

The 4th IndoPACIFIC LNG Summit: A Catalyst for Stronger Regional Collaboration

Association’s (MGA) President and IGU Regional Coordinator for South & Southeast Asia. Entitled “Regional LNG Industry Outlook Towards Net Zero Emissions,” his address provided a comprehensive overview of the region’s energy landscape and the critical role of LNG in achieving energy security, affordability, and sustainability.

Abdul Aziz emphasised the immense potential of Southeast Asia as a global LNG hub, driven by its burgeoning population and rapid economic growth. However, he highlighted the region’s challenges, including significant but declining gas reserves, infrastructure bottlenecks and the imperative to decarbonise the energy sector.

As one voice, the region firmly advocates for a collective vision for gas to play a key role in ensuring energy availability, affordability and security for this region. A vibrant gas industry is the crucial foundation and bridge in the energy transition, to continue powering homes, industries and economies for the nations within the region.

impacts of climate change”.

Addressing Industry Challenges and Priorities

The Summit fostered robust discussions on a range of critical topics that could enhance South Asia’s competitiveness in the global LNG market, including:

• Infrastructure Development: The need for increased investment in LNG infrastructure, including regasification terminals, pipelines and storage facilities.

• Market Dynamics: The importance of a competitive and transparent gas market to attract investments and ensure fair pricing.

• Decarbonisation Strategies: The pursuit and implementation of low-carbon LNG solutions and the role of gas in the energy transition.

• Policy and Regulatory Frameworks: The need for supportive and clear government policies and regulations to facilitate industry development.

The 4th IndoPACIFIC LNG Summit, hosted by the Indonesian Gas Society (IGS) in Bali, Indonesia, July 1617, 2024 emerged as a pivotal platform for advancing the region’s LNG agenda. With a focused theme of “LNG’s Role in Net Zero Emissions,” the Summit brought together a distinguished gathering of over 100 industry leaders, policymakers, and experts from diverse countries and regions. Key stakeholders, including representatives from the Bali Governor’s office, actively participated in the event. The summit also witnessed the strong presence of IGU Southeast Asia member countries, such as Malaysia, Thailand and Indonesia, underscoring the region’s commitment to fostering collaboration in the LNG sector. Over two intensive days, attendees engaged in insightful panel discussions and workshops exploring the multifaceted aspects of the LNG industry. Participants were provided ample opportunities for in-depth discussions and knowledge sharing on LNG, including its role in Net Zero Emissions.

Southeast Asia – A Region Blessed with Indigenous Natural Gas

With a population exceeding 673 million and a rapidly growing energy demand projected to triple by 2050, Southeast Asia represents one of the world’s largest and most dynamic natural gas markets, making it a crucial regional stakeholder for the IGU. This region is blessed with indigenous gas resources and holds immense potential to grow its LNG sector. Considering this region’ unique energy needs and challenges, natural gas and LNG are expected to remain relevant and play a critical role in the future to ensure energy security, meet the growing demand and provide affordable energy in the long term for Southeast Asian countries.

IGU Regional Coordinator for South & Southeast Asia Outlines Regional Vision

A cornerstone of the summit was the keynote address delivered by Abdul Aziz Othman, Malaysian Gas

The IGU Regional Coordinator called for a unified regional approach, emphasising the importance of crossborder collaboration, infrastructure development and market liberalisation. He highlighted initiatives such as capacity sharing, joint procurement and regional gas trading hubs that could overcome the challenges ahead and maximise the benefits for all member countries

IGS Chairman’s Call for Sustainable Energy for the Region

During the opening of the conference, Aris Mulya Azof, Chairman of the Indonesian Gas Society (IGS), welcomed attendees and emphasised the significance of the Summit in fostering dialogue and cooperation within the region.

“The Summit provides a timely opportunity for discussing the complex interplay of factors affecting the industry globally. Our task is to ensure a sustainable energy future that balances our growing energy needs with the urgent need to reduce greenhouse gas emissions and mitigate the

Regional Collaboration is Key towards a Resilient Gas Industry

Regional collaboration is essential for creating a gas industry that is not only resilient but also sustainable and efficient. By pooling resources, sharing knowledge, and coordinating efforts, ASEAN countries can better address the challenges of the energy transition and ensure a secure and affordable gas supply for their populations.

The 4th IndoPACIFIC LNG Summit has established itself as a leading platform for the LNG industry in Southeast Asia. It was a resounding success, demonstrating the region’s commitment to the development of a robust and sustainable LNG industry. By fostering dialogue, knowledge sharing, and networking opportunities, the event has contributed significantly to advancing the region’s energy agenda. As the industry navigates the complexities of the energy transition, the subsequent Summits will continue to play a crucial role in shaping the future of the LNG sector in Southeast Asia.

Abdul Aziz Othman, president of the Malaysian Gas Association

Gas in Africa

Africa has for years exported its natural gas or flared it to the atmosphere. Now, various strategies are being examined that promise to reshape its natural gas markets and assist decarbonisation initiatives.

For decades, Africa has mostly flared its natural gas into the atmosphere or exported it as LNG to Europe and Asia, with very little left to feed its growing economies. But over the past few years, the acceleration of global energy transition agendas coupled with geopolitical shifts and a redirection of global capital towards clean energy have all contributed to shape a different outlook for African gas markets. While the diversity of the continent and its 54 economies make it challenging to analyse African gas dynamics under a single lense, key trends have started to materialise since 2020.

An energy for decarbonisation

Just like it is for the rest of the world, natural gas is a logical transition fuel for many African markets that are overreliant on coal or imported petroleum products like diesel and heavy fuel oil (HFO) to generate electricity.

National strategies that integrate natural gas into broader energy decarbonisation plans are increasingly highlighting a pragmatic approach to balancing immediate energy needs with long-term sustainability goals. More than that, they have also started translating into concrete steps and projects for some of the continent’s biggest thermal electricity producers.

Africa’s biggest coal producer, South Africa, has

just issued a draft Gas Master Plan that envisages the commissioning of at least 2 GW and up to 16.6 GW of gas-to-power capacity in the coming years, based on gas demand scenarios. In its most basic assumption, South Africa expects gas to displace more polluting sources of energy within power plants by converting existing turbines. More ambitious plans would include greenfield gas-to-power plants, for which both public and private companies have started formulating plans.

Because even South Africa’s most optimistic expectations will not provide enough domestic gas to meet these ambitions, the country is also progressing plans to build LNG import infrastructure. At the start of the year, state-owned Transnet selected a Vopak consortium as the preferred bidder to develop and operate the future Richards Bay LNG terminal. Additional LNG import options are also on the table at Saldanha Bay and the Port of Ngqura.

These are also the plans of Morocco, Africa’s second biggest coal burner. While the government is putting in place strategies to grow gas penetration across the economy, it is working on securing a partner for the future Nador West Med LNG import terminal that could start construction as early as 2026. Meanwhile, several independent operators are active in exploring for gas

onshore and offshore while developing current gas fields to grow domestic production.

Finally, utilising gas to decarbonise the power sector is also high on the agenda of Senegal, which currently imports significant volumes of petroleum products to generate its electricity. The West African nation is witnessing a significant expansion of its thermal power fleet following the commissioning of the 120 MW Malicounda Power Plant in 2023 and the upcoming 300 MW West African Energy Power Plant in 2024. But just like the rest of its power stations, these will need to rely on imported fuels until a solution is reached to monetise offshore gas fields operated by bp and Kosmos Energy.

Small-scale gas: a new frontier?

But for the continent with the highest energy deficit and some of the most expensive electricity in the world, natural gas means more than just a transition fuel towards a cleaner energy mix.

For years, African governments have been advocating for their rights to utilise their gas reserves to support their industrialisation and economic diversification agendas. However, a reallocation of global capital towards renewable energy sources and growing public indebtness – especially since the COVID-19 pandemic –have prevented most governments from supporting the sector. The situation is calling on the private sector to play a much bigger role in driving gas penetration, thereby shaping most gas infrastrucutre development activity in sub-Saharan Africa.

In markets where public funds are scarce to support new backbone infrastructure, and where gas demand is scattered across several remote industrial and urban clusters, expensive and time-consuming gas pipeline projects are not always the preferred avenue. As the private sector takes the lead on midstream and downstream gas infrastructure, the continent is seeing a flurry of activity around small-scale gas projects that mostly rely on “virtual” pipelines – gas being trucked by roads.

Where backbone gas transmission infrastructure is available, the private sector is able to offer gas distribution pipelines that extend the network into industrial areas. This is largely the case in Nigeria’s Southwest and Southeast but also in Ghana, where Genser Energy has laid a private pipeline serving the country’s gold mines in the Western Region and extending all the way to Kumasi where a new gas-to-power plant was inaugurated this year.

But these developments are limited compared with the growing size of small-scale compressed natural gas (CNG), liquefied natural gas (LNG) and liquefied petroleum gas (LPG) projects that are mushrooming across Africa.

For the continent with the highest energy deficit and some of the most expensive electricity in the world, natural gas means more than just a transition fuel towards a cleaner energy mix.

While Nigeria is witnessing the biggest surge in CNG and LNG projects activity, similar ventures are progressing across all regions, including in Morocco where Sound Energy is building the Tendrara microLNG plant; in Tanzania where TAQA Arabia is expanding CNG distribution infrastructure; in Gabon where Perenco recently commissioned a new LPG terminal and is working on developing the country’s first LNG plant; and in South Africa where Renergen started delivering the country’s first volumes of LNG at the end of 2022.

For most of sub-Saharan Africa, small-scale gas projects are easier to execute and finance, and better suited for environments where demand is scattered and must be gradually unlocked. But the export industry is also following a similar logic of smaller or modular projects that favour time-to-market. This is the case for Perenco’s Gabon LNG project, Eni’s Congo LNG project, but more importantly for ExxonMobil’s Rovuma 18 mtpa LNG terminal in Mozambique – Africa’s biggest – now structured as a modular and electric project.

Regionalisation around gas is proving slow

Regional and cross-border gas trade, albeit high on the agenda of most Western, Eastern and Southern African markets, is proving slow to pick up. The cost and time required to enable such trade – often relying on pipelines stretching hundreds if not thousand of kilometres – is largely to blame despite a growing number of regional ventures being proposed.

Until now, only the Mozambique-South Africa gas pipeline operated by RompCo and the West African Gas Pipeline between Nigeria and Ghana have managed to somewhat formalise these ambitions – albeit the latter remains significantly under-utilised. To grow regional trade, the continent is betting on new projects largely made up of pipeline ventures. The most publicised of them – the Nigeria-Morocco Gas Pipeline – seeks to link up the West African coast from Nigeria to Morocco with landings in each of the remaining nine countries (Nigeria, Benin, Togo, and Ghana being already connected via the West African Gas Pipeline). Political will for the project is strong with state-owned NNPC

MICKAEL VOGEL, DIRECTOR & HEAD OF RESEARCH, HAWILTI LTD

and Morocco’s regulator ONHYM taking the lead on progressing the multi-billion dollar venture.

In East Africa, Tanzania is seeking to establish itself as a gas hub to supply neighbouring Kenya – where several power plants run on HFO and diesel in Mombsa – and neighbouring Uganda which has a growing manufacturing and industrial base. It could also supply Zambia –currently facing a 700 MW deficit – where very ambitious copper production and processing targets will require reliable energy.

Such pipelines are likely to take several years to build and commission, so virtual solutions might be emerging in the meantime. This is the case in West Africa, where Genser Energy is working on plans to truck gas from Ghana to Côte d’Ivoire, but also in Southern Africa where gas availability in Mozambique and South Africa could anchor new supply routes to Botswana, Zimbabwe, or Zambia.

The road ahead

While the progress in developing natural gas markets in Africa is promising, it is essential to recognise and address the challenges that lie ahead. Infrastructure development, competitive policy frameworks, and investment climates will play crucial roles in shaping the future of the

Come what may – preparing for an uncertain energy future

Much like predicting the weather, there can be some difficulty in trying to accurately forecast the future of energy. There are many unpredictable forces acting upon the energy landscape, shaping demand and supply, such as climate change, climate action and geopolitical developments. Then there is the overriding factor of human need. In dire circumstances, survival will trump all else, even if it means breaking promises and commitments, as we saw when the recent European energy crisis prompted the restart of coal plants to keep lights and heat on.

Taken together, what this all means is that the energy future is not set in stone.

In this context, The National Gas Company of Trinidad and Tobago Limited (NGC) has recognised the paramountcy of flexibility in its business, and that having a diverse portfolio is crucial for long-term success and sustainability. Accordingly, since 2016, the company has transformed from a primarily gas-forward business, into a company with a more holistic focus on low-carbon energy development.

To be clear, there has been no dilution in its attention to natural gas. In addition to looking at ways to secure and increase gas supply for the domestic market, NGC has set its sights on becoming a global player in the LNG space. The company now has an increased stake in the domestic LNG business following the commercial restructuring of Atlantic, and is exploring small-scale LNG projects for the Caribbean. In addition, the wider NGC Group of Companies today has a physical presence in gas markets outside Trinidad and Tobago, thanks to three

natural gas liquids (NGL) asset acquisitions in the USA.

At the same time, alongside continued gas development, the company is focusing on clean energy projects and investments. At the outset, the responsibility for exploring and investing in clean energy was jointly held by different subsidiaries within the NGC Group. In 2023, an entirely new entity was created to manage this arm of the business – NGC Green Company Limited.

This subsidiary is now overseeing a portfolio covering clean energy and low-carbon fuels; energy efficiency; sustainable transportation; and associated research and development.

That said, all companies within the NGC Group continue to pursue their own decarbonisation initiatives, to reduce the carbon intensity of their products and services, to stay competitive in a greening market. This includes focusing on methane mitigation; asset integrity management; carbon offset projects such as reforestation programmes; and a suite of public education initiatives around responsible use of energy, sustainability and climate adaptation.

The goal is to create an integrated energy business that is versatile and resilient enough to withstand the turbulence of an ever-changing energy landscape. NGC and its subsidiaries are looking to reconcile corporate profitability and corporate social responsibility – in all its dimensions - because in today’s market, they go hand in hand. Ultimately, they are seeking to build an energy company that will continue to serve the region well into the future.

Demand Projection Dizziness

A long list of uncertainties impacting the US natural gas and LNG markets, ranging from data centre developments to just who will occupy the White House next, leaves future demand forecasts murky at best.

ROBERT KACHMAR, RBAC INC.

Source: EIA

Every time you turn around it seems as though there is a new headline focused on data centres, artificial intelligence (AI), natural gas exports, or more specifically, LNG exports.

New conjectures and projections on just how much additional energy will be required to fulfill this demand run the gamut of the optimistic/pessimistic spectrum. Just this month, published projections for incremental data centre demand from gas-fired generation have ranged from 3 bcf to an astonishing 17 bcfd.

Earlier this year, President Joe Biden made waves with his “pause” in LNG export permitting, a policy since knocked down in court by a federal judge. Now one wonders if the shifting political tides and the presumptive new Democratic nominee for president will try to reinstitute this policy or take an even more radical step.

Vice President Kamala Harris has been selected the new Democratic presidential nominee and based on historical interactions with the energy industry, one might conclude there is more trouble on the horizon.

Looking back at the VP’s tenure as California Attorney General and then Senator, we see an investigation into ExxonMobil over carbon emissions and an endorsement of a federal ban on fracking. In early August, Harris took a more moderate position on energy by walking back her previous comments on a total fracking ban, in hopes of swaying voters in Pennsylvania, Ohio and New Mexico as these are major natural gas producing regions as well as swing states.

On the Republican side, candidate Donald Trump has

already campaigned on additional China tariffs, a policy that could loom large for the LNG industry, as China owns many long-term natural gas export contracts and effectively acts as the swing buyer in the global market.

In the US, AI and data centres are the current hot button topic with new developments every day. Virginia and Texas have both experienced dramatic commercial sector consumption over the past five years due to data centre and cryptocurrency operations. Other states such as South Carolina, Arizona and North Dakota have experienced growth but on a much smaller scale.

What makes data centres interesting is the regionality of demand which will likely have profound basis implications as well as on their demand profiles. Requiring energy 24 hours a day, 7 days a week and 365 days a year, data centres are considered to be “baseload” demand, with serious ramifications if power outages occur, making them poor bedfellows for renewable power generation sources like wind or solar.

Regions where power demand increases, such as the South Atlantic (eg South Carolina, Virginia) and the South Central (eg Oklahoma, Texas), are likely to see strengthening basis prices (relative to Henry Hub). Coupled with substantial forecasted LNG export growth, Henry Hub prices are also expected to increase significantly. Consequently, areas that are not participants in the data centre buildout are more susceptible to weaker basis.

This is seen clearly in the US Electric Generation (ELC) demand in the most recent Q2 2024 release and outlook

Figure 2: Average annual reported power outages per customer, 2019 - 2023

Note: Reported outages are for every 15-minute period. Cutomers per county as of 2022.

by the RBAC’s North American Team using GPCM Market Simulator for North American Gas and LNG. Focusing on the Mid Atlantic, South Atlantic and West South-Central census regions and relative to the Q2 2023 release, which uses EIA’s 2023 Annual Energy Outlook (AEO) ELC consumption forecast, we see ELC consumption declining less rapidly as additional gas demand partially offsets the energy transition. Across these three census regions we see annual gas demand increases as much as 44%, 82%, and 45% as seen below. Other regions are projected to experience smaller increases, with the total of the United States expected to increase approximately 26% through 2050.

The Electric Power Research Institute recently published that electricity demand associated with data centres could double by 20301, effectively consuming 9% of US electricity. On the flip side, others doubt the high projections with the understanding that both chips and AI algorithms become more efficient over time, leading to progressively less energy consumption needs.

Another recently overlooked trend is battery electric, hybrid and plug-in hybrid vehicles (BEVs/HEVs/PHEVs), which continue to make headway in the US (Figure 3), comprising 18% of the Light Duty Vehicles (LDVs) sold in the first quarter of 20242. The EIA expects this vehicle group to continue gaining market share, with 2030 sales exceeding 30% for new LDVs3.This additional load will strain an already burdened power grid, evidenced by the rising number of power outages (Figure 2) per customer as recently reported by the Wall Street Journal, with the Gulf Region as a particular area of interest due to its exposure to hurricanes. Many BEV/PHEV users will likely be charging at home overnight, when solar power isn’t being produced, further highlighting the need for power generation assets that are flexible, reliable, and economic. The 1,000-pound gorilla in the room is the additional LNG export facilities slated to be completed in the near future. Plaquemines LNG export facility is coming online later this year and Golden Pass LNG is expected in late 2025 (delayed due to a contractor bankruptcy). The RBAC Team expects LNG exports to double by 2027, reaching about 30 bcfd or nearly 30% of current domestic demand, with the lions’ share leaving via the Gulf Region.

Though the “pause” by the Biden-Harris Administration did not include facilities already under construction or approved, that doesn’t mean such

1. US data center electricity demand could double by 2030, driven by artificial intelligence: EPRI | Utility Dive. 2. U.S. share of electric and

Figure 3: Quarterly US light-duty vehicles (LDV) sales by powertrain (Jan 2014 - Mar 2024) Percentage of Sales

Source: EIA

Trying to keep track of all the developments is enough to make this analyst dizzy.

projects are free from regulatory risks, as evidenced by the recent Circuit Court of DC Rulings which vacated Federal Energy Regulatory Commission (FERC) approval of Rio Grande LNG and Texas LNG export facilities. These rulings are consistent with other actions by the court, which just vacated FERC approval for William’s Transco Regional Energy Access project in the Northeast, emphasizing that no project is safe on land or sea. Given the current political and regulatory state of flux and the upcoming November elections, it’s possible that a resumption or expansion of the “pause” could be forthcoming. This would obviously jeopardise future activity, but perhaps be a boon to those facilities already permitted, under construction, or operating.

A smaller, yet still consequential “gorilla” piece of the demand picture is pipeline exports to Mexico. Benefitting

from proximity to shale reserves (ie Eagle Ford and Permian basins), Mexico has been quietly increasing the amount of natural gas it imports, setting new records every year. Primarily used for industrial processes and power generation, natural gas consumption in Mexico is highly seasonal, reaching levels as high as 8 bcfd during the summer months, up from the 1.1 bcfd peak in 2010, and there’s still room for Mexico imports to run. RBAC’s latest outlook projects US pipeline export capacity to Mexico to be over 14 bcfd by the end of 2024, though flows are likely to remain near 7 bcfd, or near 50% utilisation. However, LNG export facilities such as Costa Azul LNG, NFE Altamira LNG, and Saguaro Energia LNG in Mexico could dramatically increase these transit statistics.

Mexico is also experiencing a regime change as its

Source: Wall Street Journal

The South Atlantic region will also experience strong demand, with only moderate declines due to the energy transition. That doesn’t even take into consideration the political ramifications of the November elections.

president Andres Manuel Lopez Obrador, sometimes referred to as AMLO, has stepped aside and his protege, Claudia Sheinbaum, will step in after winning the presidential election earlier this summer. The first female president in Mexico’s history, Sheinbaum represents continuity as she shares many of the same political beliefs as AMLO. It will be of consequence how her policies shape Mexico’s energy industry – with a Ph.D. in Energy Engineering she is uniquely suited to lead her country forward.

Mexico’s energy sector has long been plagued by the risk of nationalisation, but with the right policies, Mexico could be in a position for tremendous economic growth. Its access to associated natural gas via the Permian and plentiful sun could set Mexico up for prosperity now and in the future.

Trying to keep track of all the developments is enough to make this analyst dizzy. And while we view LNG exports as the most concrete source of demand in the near term, data centre and EV projections have such a wide range of possible permutations that any significant variation from current outlooks may have an outsized impact on supply/demand balances and gas prices, particularly regionally.

We see continued demand strength in the West South-

Central Census region, home to Gulf LNG exports as well as data centre hubs like Dallas and Austin. The South Atlantic region will also experience strong demand, with only moderate declines due to the energy transition.

That doesn’t even take into consideration the political ramifications of the November elections. If the high end of data centre and EV demand does come to fruition, domestic companies and consumers are likely to be stuck with higher regionally oriented energy costs.

Energy companies and even nations are assessing and hedging potential risks in regional demand growth, and be it price risk or possible supply shortfalls, the key for analysts and managers involved is the ability to run market simulation for various scenarios as the demand picture becomes clearer, paving the way for optimising gas strategies.

RBAC, Inc. has been the leading provider of market fundamental analysis tools used by the energy industry and related government agencies for over two decades.

The GPCM® Market Simulator for North American Gas and LNG™ is the most widely used natural gas market modeling system in North America. RBAC’s G2M2® Market Simulator for Global Gas and LNG™ has been instrumental in understanding evolving global gas and LNG dynamics and is vital in fully understanding the interrelationship

Indian gas demand to triple, but how soon?

India’s government sees gas demand tripling by 2030; the US Energy Information Administration says it will take until 2050. India already has underused LNG import capacity and the growth of its City Gas Distribution networks is impressive, but the completion of major trunk lines remains a key challenge. Meanwhile, India’s subeconomic electricity pricing looks set to leave gas-for-power out in the cold, despite an urgent need to reduce coal-fired generation emissions.

ROSS MCCRACKEN

India’s gas consumption rebounded 7.5% last year, according to Energy Institute data, to a record 62.6 bcm. The jump reflects a return to the growth trajectory recorded between 2015-2021, which was thrown off course by the surge in imported gas prices in 2022.

As India’s domestic production falls short of consumption, the country depends on LNG imports, pooling for some buyers the price of domestic and imported gas. Consequently, the LNG price is a key variable in India’s willingness and ability to boost import volumes and overall consumption.

Spot LNG prices, as represented by the Japan-Korea Marker (JKM), fell in 2023 from the cost-prohibitive highs of 2022 and continued their downward trend in firstquarter 2024 before rising again to about $12.50/mmBtu at the end of July. India’s price-sensitive thirst for LNG has been in evidence.

In the first half of the year, the country imported 13.71 MTP of LNG, 31.3% higher year on year than the first half of 2023, following a surge in imports in the low-priced first quarter. If this pace is sustained, the country could set a new annual record for LNG imports.

Transmission constraints

India has excess LNG import capacity, at least judged by utilisation rates. According to India’s Ministry of Petroleum and Natural Gas, from April-September last year three of the country’s terminals operated at below 20% capacity and another three below 40%. Only the Dahej terminal in Gujurat operated above 90%.

In total, the country has 44.5 MTPA of import capacity. There are also 17 MTPA of onshore terminals and 16 MTPA of floating LNG projects under construction, according to International Gas Union (IGU) data, although the latter have struggled to secure floating storage and regasification units amid Europe’s rush to expand its LNG import capacity.

The most immediate problem is not import capacity but transmission. India lacks major trunk gas pipelines to take gas from import points to distribution hubs.

The Kochi LNG terminal, for example, has operated below capacity for more than a decade, owing to very slow progress in completing pipelines. It took until 2020 to commission the pipeline from Kochi to Mangalore via Koottanad, and the sections between Koottanad and Bangalore and between Bangalore and Krishnagiri are still not complete.

Similarly, GAIL India announced earlier this year a nine-month delay in completing the Pradhan Mantri Urja Ganga pipeline, which will now not be operational until March 2025, assuming no further postponements. The pipeline, also known as Jagdishpur-Haldia-Bokaro-

Dhamra, will stretch 3,306 km and bring natural gas to eastern India for the first time. Some cities along the route already receive gas from the project, which was initiated in 2016. The latest hold-up is attributed to delays in obtaining right-of-use permissions along the full pipeline route.

India has about 24,623 km of trunk pipelines which mainly serve western and northern India. A further 9,130 km have been authorised, according to the government, to create a single grid serving more of the country in the east and south.

CGD investment sustains demand momentum

Further downstream, progress is impressive. New Delhi is targeting a near tripling of natural gas consumption by 2030 from 185 mmcmd to 500 mmcmd. In particular, it has completed the 12th City Gas Distribution (CGD) bidding round, which authorises the development of CGD networks in all remaining unserviced areas of the country, except islands.

CGDs target piped gas distribution to domestic, commercial and industrial consumers as well as the distribution of Compressed Natural Gas (CNG) for the transport sector. Successive CGD rounds have resulted in large-scale capital commitments, which is resulting in the rapid growth of distribution infrastructure.

In March 2022, there were 9 million piped natural gas connections, double the number in the fiscal year 20172018. The number of CNG stations stood at 4,433, triple the number in compared to 2017-2018.

Data from the country’s Petroleum Planning and Analysis Cell as of March this year showed 6,959 CNG stations in operation across 47 states, 13,118,891 domestic connections, 44,471 commercial connections and 19,211 industrial connections.

The expansion in distribution networks is in line with the government’s ambition of increasing gas’ share of primary energy consumption from just over 6% to 15% by 2030.

Industry to be prime driver of demand

Analysis by the US Energy Information Administration (EIA) takes a more circumspect view with regard to India’s gas demand trajectory than its government. It forecasts that Indian gas consumption will triple by the significantly later date of 2050, as opposed to the Indian government’s 2030 target, equivalent to annual growth of 4.4% a year.

The primary driver of demand, according to the EIA, is industry, led by ammonia production for fertilizers and growth in the oil refining sector. One of the government’s key policy goals is to achieve self-sufficiency in the

production of urea, a primary fertilizer input. The EIA forecasts demand growth of more than 250% between 2022-2050 in the production of base chemicals, including urea, and demand growth of more than 400% from the oil refining sector.

Industry already dominates Indian gas demand, accounting, in 2022, for about 70% of total consumption. The EIA sees industry’s share rising to 80% by 2050, transport increases to 10%, with the remainder accounted for by power generation and the residential and commercial sectors.

It is quite possible, given the capital being deployed in the CGD programme, that residential and commercial demand could gain a more significant share of the market and add to higher demand growth than the EIA expects.

Power sector left out in the cold

However, a stand-out aspect of the government’s plans to create a gas-based economy is the limited role for gas in the power sector. In the EIA’s projections, electricity generation is relegated to a small share of total gas demand behind transport. In the government’s plans it also plays a limited role, with the focus on delivering gas to industrial (non-power), residential and commercial customers.

As with LNG import capacity, India has under-utilised gas-fired generation plants, although installed capacity pales in comparison with that of coal-fired generation. A heatwave in May and June this year saw record power demand, which was met by a combination of coal, gas and renewables. Coal, in particular, hit a record level of generation.

The event highlighted the specificities of India’s energy transition. The country is heavily dependent on coal and its economy is expanding fast, creating major challenges in simultaneously reducing emissions and meeting power demand growth.

The country added 2.8 GW of wind and almost 10 GW of solar power last year, bringing the totals for installed capacity to 44.7 GW and 73.1 GW respectively. However, it faces a race against rising domestic power demand far different from advanced economies. India’s power generation rose 7% in 2023 compared with a 1.5% contraction in the OECD.

Solar generation rose by 18.2 TWh, wind by 12.1 TWh, but total generation jumped 128.9 TWh.

India’s roughly 25 GW of gas-fired generation capacity accounts for only about 2.7% of power generation. 52.6 TWh of electricity was generated from gas last year, up 13.2% on 2022, but this was still less than half the level of 2010. Over the summer of this year, the government had to mandate increased gas-fired generation to meet

Our knowledge services and stakeholder events provide a reliable platform for industry value chain, policy makers and regulators, academics, and consumers to source credible information to better understand the complexities of the global gas market. Natural Gas World also produces Global Voice of Gas – the official publication of the International Gas Union.

DECARBONISING

ENERGY: INNOVATION AND START-UPS

Taking gas turbines to a new level

With the world’s first – and so far only – flameless combustion microturbine, Belgium’s Mitis provides power generating capabilities with five times less emissions.

ANNA KACHKOVA

Efforts to pursue emissions-cutting are varied and wideranging, with technologies being developed on both the small and the large scale. On the small-scale side, recent innovations include the flameless combustion microturbine developed by Belgium-based Mitis.

The microturbine is aimed at helping to reduce emissions from decentralised power generation.

“The technology that we are using to do this is called high-speed turbo machines,” Mitis’ CEO, Michel Delanaye, told Global Voice of Gas (GVG). “These are systems which are rotating very fast and which are able to convert the thermal energy of any fuel into electricity and heat.”

Mitis is among a small number of companies to develop a micro gas turbine and is in a minority in particular when it comes to developing turbines in the 1030 kilowatt (kW) range. The company’s turbine features a number of innovations, and Mitis has 13 patents that are either already in place or pending. It can run on a variety of fuels – anything from natural gas or biogas to hydrogen and liquid fuels, according to Delanaye.

One of the features of the microturbine is that it uses a flameless combustion process.

“That’s a particular regime of combustion that is able to produce very low emissions – for example, very low nitrogen oxides (NOx),” he said.

“One of the other innovations we have in our system is that it’s running completely oil-free,” Delanaye continued.

To achieve this, the turbine is rotating – at speeds of 100,000 rpm – on bearings that use a cushion of air. This offers additional advantages in terms of low maintenance and noise reduction.

“We have a combination of efficient conversion of the fuel, very low emissions and a system that is not using any oil,” said Delanaye. “Also, because of this cushion of air, there is no touching of a rotating metallic part with another non-rotating metallic part, which means it’s reducing the noise of the system.”

Delanaye added that the electricity generated using Mitis’ system can also be used to run heat pumps, which enhances the system’s overall efficiency and results in heat and power being co-generated at a lower cost.

“You’re talking about millions of machines per year,” said Delanaye. “The market is a billion-dollar market, basically.”

MICHEL DELANAYE, CEO MITIS

“In the end, we have a lean, cleaner and more efficient usage of the fuel,” Delanaye said.

Development

Mitis started developing its microturbine about 10 years ago and, given the difficulty in obtaining off-the-shelf components, it also developed most components itself. While this process took time, the company now benefits from having control over its supply chain, down to the finer details, according to Delanaye.

In 2020, Mitis secured funding from the European Innovation Council (EIC) under its Horizon 2020 Research and Innovation programme. Then, in early August 2024, the company secured a further C$92,359 from Canada’s Natural Gas Innovation Fund (NGIF) Accelerator under its Industry Grants programme.

Delanaye said Mitis was reaching Technology Readiness Level 6 (TRL 6) with the micro gas turbine and intended to reach TRL 7 by the end of 2025 with full commercialisation by 2026. The company sees the NGIF funding as a significant contributor to helping it reach TRL 7.

Applications and markets

Mitis sees opportunities for several different applications for its microturbine technology. These include commercial buildings, such as hotels, bars or swimming pools. Agriculture is another sector where the microturbines can be deployed, because they can run on varying compositions of biogas – which can be produced on farms using an anaerobic digester – and require considerably less maintenance than piston engines. Delanaye said that such piston engines represent the main competition for the technology.

If Mitis seeks to displace natural gas boilers, the potential market is “huge”, according to Delanaye, even if the company targets the commercial market rather than the consumer market.

“If you think about in Europe, for example, you have about 9mn natural gas boilers that are sold every year in the European market,” he said. “These 9mn are for the consumer market. If you go a little step beyond that

and think about the commercial – hotels, bars, all these kinds of bigger buildings – you’re talking about more like a million systems per year in Europe.”

The boiler numbers are higher in the US and Canada.

“You’re talking about millions of machines per year,” said Delanaye. “The market is a billion-dollar market, basically.”

Canada – a market that is in the spotlight thanks to the NGIF interest – is also illustrative of a country with energy transition plans to which Mitis’ microturbine could be well-suited as users switch fuel types over time.

“You can use [the technology] today with natural gas,” Delanaye said. “Tomorrow, you’ll be able to use it with biomethane and you can use it with hydrogen as well. You don’t have to change much on the machine to do so. You are acquiring a system that can follow you on the full transition to a cleaner energy world.”

Seeking partners

Mitis has identified numerous opportunities globally to deploy its system. Besides Canada, the US and Europe, the company sees traction in countries including China, India and Brazil. These are all countries where various types of gas are used, Delanaye noted.

“For example, India and Brazil are developing a lot of biogas,” he said. “What we are looking at, in order to

the OEM [original equipment manufacturer].”

Delanaye said that given the challenges of trying to break into the major markets alone, Mitis is seeking partners that are already established in these markets, to which it can act as a technology licence supplier.

“We are looking for partners in the US, in Canada, in Brazil, in India, in China and in Europe,” he said. “Also, depending on the type of market, the machine is quite versatile. It can be applied for heating, but it also can be used – for example – in micro grids as a power generation device. These are quite different markets for which we can find different partners.”

Next steps

Mitis still has more work to do in order to reduce costs, Delanaye said. The company views the total cost of ownership (TCO) for its system as being dependent on factors including the spread between the price of electricity and the price of the fuel being used, and also the machine being sized correctly for the type of building it will be used in.

Working with partners is expected to help achieve economies of scale, further bringing down the costs of the technology.

Discussions with would-be partners are confidential at this stage, but Delanaye confirmed that Mitis has been

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