Dear Readers,
Welcome to the first issue of the IGU Global Voice of Gas magazine in 2024.
We are just two months away from the International Gas Research Conference (IGRC2024) in breathtaking Banff, Alberta, Canada. The theme for the event is Fuelling the Innovation Agenda
Innovation is critical to keep natural gas a reliable, affordable, and low-emission source of energy, and IGRC2024 will focus on technical research, gas clean-tech, technology start-ups, and social innovation to showcase global examples of innovation and its positive impact on both the gas sector and the societies it serves to energise. IGRC2024 is a very important technical conference of the IGU, and this year, it also features an outstanding strategic agenda.
I am very excited about taking part in this event, the heart of the engine, that will drive the future of gaseous energy through the ambitious transition we are in, and I encourage you all to join me in Canada on May 13th to 15th.
Turning to the global gas markets at large, 2024 set out to be a positive year. We had good fortune on our side, with the combination of unusually mild temperatures and high levels of storage in Europe, and steady global supply operations. This not only ensured that the European markets made it safely through the winter heating season, but also significantly lowered the global price of gas. As a result, consumers, including many Asian markets, which suffered shortages during the period of volatile and spiking prices over the previous two years, are sighing with relief.
However, as the level of geopolitical risk remains elevated, we should not rush to conclude that we are
out of crisis, as the additional volumes are still some years away, and the global market supply remains tight.
We should also not forget about growing energy needs of the world beyond OECD, and these needs will be met by different combinations of energy sources at their disposal. The countries and regions that are looking to provide energy to societies in environments facing energy and capital scarcity will look for the most affordable options first. That is simply the reality. When the affordability of gas has been challenged over those last few years, we saw a lot more coal entering the energy mixes of the world’s most energy-demanding and growing areas, and the global emissions level saw another rise.
Affordable natural gas is key to moving the needle on the energy transition. It is key to switching away from the most polluting and emitting sources, like coal; and policy, industry, technology and innovation are key to scaling and accelerating a deeper decarbonisation of the gaseous energy supply. These two pillars are necessary for a successful transition, while gas is essential for reliably providing the critical resiliency that the global energy system will need to maintain through the aggressive energy that is being undertaken in the world.
Our editors prepared an excellent issue on innovation and technology in the sector, and I hope you find it insightful and enjoyable.
Li Yalan, IGU President
Welcome to the 15th issue of the Global Voice of Gas magazine, an International Gas Union publication, produced in collaboration with Natural Gas World (NGW).
In the anticipation of the upcoming International Gas Research Conference 2024 happening in Banff, Canada, this May, the issue explores clean technology advances and innovations in gaseous energy, especially those supporting the decarbonisation of gas supply.
In an introductory article, Tim Egan, the President and CEO of the Canadian Gas Association hosting IGRC2024, shares that innovation is more than pure tech, pointing to its very important social dimensions, with examples from Canada.
We also interviewed Paula Gant, CEO of GTI Energy, a key US actor advancing energy technology innovation. Paula highlights that public-private partnerships and collaboration have been key in the net-zero innovation dynamic. We also spoke with Shamairi Ibrahim, Vice President of LNG Marketing & Trading at Petronas, about how Malaysia’s national LNG exporter is leveraging technology and innovation to provide lower-carbon energy, including through the pioneering use of floating LNGs, carbon capture and storage, zero flaring and upgraded LNG carriers.
Turning to Africa, the youngest continent, with an incredible 40% of the population aged 15 years or younger, its role in the future of energy and innovation is going to be pivotal. It is also a massive innovation playing field for energy. The challenge of its currently low energy could be turned into an opportunity to develop energy systems of the future, as the African communities industrialise and their economies grow.
We spoke to Osam Iyahen, Senior Director of the Africa Finance Corporation, established in 2007 to be the catalyst for private sector-led infrastructure investment across Africa. Now with almost two decades of experience and over $13bn in investment portfolio, AFC continues to deliver on its vision to be a leading energy infrastructure solutions provider – from renewables to gas projects.
Next, Rami Shabaneh, Research Fellow at King Abdullah Petroleum Studies and Research Center, stresses the strong value proposition of blue hydrogen as a tool for decarbonisation, and the need for developing an internationally-accepted standard for certifying low-carbon hydrogen. This will help unlock needed investment and facilitate trade, bringing about a much needed global market for the fuel.
Start-ups have played an instrumental role in providing new solutions to further decarbonise natural gas. One such company is Alberta-based Qube Technologies, which provides a continuous methane emissions monitoring solution that is low-cost and
scalable, helping oil and gas operators detect and eliminate methane leaks quickly and effectively, its COO Eric Wen explains in an interview. We look at other innovators in this field, including Californiabased Picarro, which mounts its cavity ring-down spectroscopy devices onto vehicles that survey distribution systems, and Quebec-based GHGSat, which now has 12 satellites in orbit detecting emissions with high-resolution equipment.
We also take stock of how the market for certified natural gas is developing, as a tool for producers to reduce their environmental footprint and prove that to their customers and their critics, and the growing production of bio-methane, or renewable natural gas, which not only has environmental benefits but in many countries can also more affordable than alternative fuels. Bio-methane can be used in all the same ways as natural gas, and when liquefied, has additional applications in both vehicle and maritime transport.
Innovation also means digitalisation and increased automation, which are helping the LNG industry reduce risk and boost efficiency, among other benefits, as we explore in this issue.
Carbon capture utilisation and storage technologies are the bedrock of any decarbonisation scenario, and just about every energy outlook scenario for the energy transition clearly demonstrates it. As experts tell GVG, the scale-up of CCUS is mission critical for meeting net zero. We explore this technology looking to understand where it stands today and what are the future prospects.
Given the decarbonisation imperative, our authors also consider key takeaways of the COP28 summit in Dubai: what were its key successes and which areas lacked progress?
GVG continues to follow critical developments impacting the natural gas market, and in this issue we share a review of risk exposure to potential critical maritime chokepoints, as shown all too clearly by events in the Red Sea region. We also take a look at the upcoming US presidential elections and what implications the result might have for policy affecting natural gas. In a year in which at least 64 countries, plus the EU, are holding votes on governments and legislatures, the US election is perhaps the most critical and divisive one for energy. Finally, our regular updates from the IGU Regional Coordinators will bring you up to speed with the latest developments in gas across Europe, North Asia and Austral-asia and Africa. We hope you enjoy this issue.
Tatiana Khanberg, Strategic Communications and Membership Director, IGUNatural gas indices across 130 locations in North America.
40+ daily power price indices in on-peak and off-peak markets. Outlooks and strategic analysis for power, gas, LNG and clean energy markets. News coverage on gas and power companies, infrastructure, policies, and regulations. 5-year short-term and 30-year long-term fundamentals and price forecasts.
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Check out our latest blog Top 10 questions facing North American gas and power markets in 2024
The Call for Abstracts for the 29th World Gas Conference (WGC2025) is currently underway, and we invite you to contribute, share your diverse perspectives and shape the event theme ‘Energising A Sustainable Future,’ scheduled for 19-23 May 2025 in Beijing, China.
This triennial event pledges a dynamic platform to delve into ground-breaking ideas, technological advancements, and sustainable solutions. Don’t miss your chance to contribute, define and transform the future of the energy sector in one of the curated topic themes:
1. Supply, demand, market and prices
2 Gas narratives under the new context
3. New momentum for LNG
4. Digital transformation
5. New gases in energy transition
6. Methane emission mitigation
7. Best practices through the whole value chain
RODNEY COX Director of Events, International Gas Union
Submit your abstract at www.wgc2025.com and take on a pivotal role at the forefront of discussions that are actively steering the future of energy.
Innovation is critical to keep natural gas a reliable, affordable, and low-emission source of energy.
Be part of the high quality program which includes:
• Global Spotlight Sessions on innovation & the energy trilemma (security, affordability, environment). Strategic panelists and moderators representing all regions of the world.
• Leadership Dialogues and keynotes by the likes of:
◦ Magatte Wade, Entrepreneur, speaker, and visionary leader on the role of African entrepreneurship and innovation
◦ Vaclav Smil, Distinguished Professor Emeritus, University of Manitoba, and Author
◦ Dr. Paula A. Gant, President and CEO, GTI Energy
◦ Dr. Bjorn Lomborg, President & Founder, Copenhagen Consensus Center
• Meet the finalists of the inaugural Global Cleantech Challenge
• Find out how the gas industry is addressing social innovation
• Learn about the latest global research and technical innovations from across the gas value chain
IGRC2024 is bringing global innovators, academics, researchers, and leaders from the gas industry to Banff, Canada. The conference will showcase the latest in technological innovations from across the gas value chain, host the first-ever Global Cleantech Challenge, and have strategic discussions and leadership dialogues to address a broader innovation agenda affecting all aspects of society, including economic development. Register now
Senior Adviser, Japan Gas Association, and IGU Regional Coordinator.
2023 has been another year of extreme volatility for energy.
» Natural gas prices in Asia are now lowered but not to levels seen before Russia’s war with Ukraine.
» While discussion of phasing out all fossil fuels including natural gas took placed in Dubai, COP28, December 2023, we have witnessed unprecedented numbers of final investment decisions taken on for new gas supplies, particularly in the US.
» But these FIDs are not enough to ease the current tight gas market in until at least in the mid of this decade.
» As the Russia- Ukraine war continues, the Asian gas market continues to be affected by disrupted natural gas supply chains.
» Further complicating matters, are the subsequent IsraelHamas conflict and mounting tension in South China Sea.
» In this new reality, the Asian LNG importing counties like, China, Japan, Korea, and Chinese Taipei are facing fundamental changes in the way they secure their energy.
» Australia remains one of the top four LNG suppliers in the world, with a yearly capacity of 89mn t/yr. and exports of 87 mil. tons, or 21% of world traded LNG. According to consultants EnergyQuest, this is contributing USD62.3B in export revenues in 2022, up 82% from previous year because of higher LNG global prices.
» However, tougher emission policies are putting pressure on LNG productions. The Labour government of Prime Minister Anthony Albanese, which came to power in May 2022, has made a legal commitment to achieve net zero by 2050 and pledged to cut GHG emissions by 43% from 2005 levels by 2030.
» Now, existing LNG projects that produce more than 100,000 tons of CO2 equivalent/yr must cut their emissions by 4.9%/yr between now and 2030. This is expected to affect about 215 oil, gas, and mining projects.
» In addition, the new legislation demands new gas fields to abate or offset all reservoir CO2 emissions within Australia. As a result, most new projects will have to combine carbon capture and storage (CCS), drastically increasing project costs. This will hit LNG producers soon as new fields need to be developed to substitute maturing fields that are becoming exhausted.
» The LNG industry could also be affected by gas supplies being diverted for domestic consumption. Under the Australian Domestic Gas Security Mechanism, introduced in 2017, Canberra is allowed to restrict LNG exports to ensure domestic gas supplies.
» The mechanism has never been used, but the new government has expressed a willingness to implement it.
» Given the complexity of evolving Canberra’s policy, foreign investors in Australian LNG projects and LNG importers are concerned about Australia’s long-term reliability as a source of supply.
» Japan was the largest buyer of Australian LNG last year, importing 31.2mn t/yr, equivalent to 43% of total Japanese LNG imports, with China send largest with 22.6mn tons.
» The Japanese government is particularly concerned about the impact on projects for which final investment decisions have already been taken and has requested Canberra to provide more detail information on whether CCS and ACCUs will enable project development.
» Japan may be especially perplexed by Canberra’s new stance because some Japanese customers chose not to renew long-term LNG contracts with Qatar that expired in 2021 and 2022.
» Japan has 24mn t/yr of long-term contracts with Australia, of which 8mn t/yr will expire by 2029. Some may switch to Middle Eastern suppliers that look less likely to try to cut LNG industry emissions in the same way as Canberra.
» Japan’s Minister of Economy, Trade and Industry Yasutoshi Nishimura said that bilateral talks were ongoing “regarding measures for protecting investors and ensuring a stable supply of LNG, to find a mutually acceptable solution”.
» Also, recent news that the White House is leading an interagency process to reconsider its approach to reviewing LNG export applications to non-FTA countries at DOE raised another concern for Japan. It is estimated that 110 mil. tons of LNG export may be affected of which 2 mil. tons are for Japan. This is also raising concern affecting long term energy security for countries relying on foreign energy imports.
» Japan chaired the G7 summit in 2023, and the G7 Climate, Energy and Environment Ministers’ Communiqué, in Sapporo for the first time stressed on the need of “Carbon Management” recognizing that Carbon Capture and Utilization (CCU)/carbon recycling and CCS can be an important part of a broad portfolio of decarbonization solutions to achieve net-zero emissions by 2050.
» CCU/carbon recycling technologies, including recycled carbon fuels and gas (RCFs) such as e-fuels and e-methane were focused on as important technologies to reduce emissions.
» Japan’s gas industry is aiming to replace natural gas with e-methane by 90% by the year of 2050. Existing and future natural gas infrastructure can be used to realise a smooth transition to low carbon gaseous energy.
» This will avoid natural gas infrastructure becoming stranded assets.
» In July 2023, the National Energy Administration’s (NEA) Natural Gas Development Report estimated gas demand would grow by between 5.5% to 7.0% in 2023. In September, a subsidiary of the state-run energy company CNOOC estimated it would be even higher, rising by 8%
» Noticeable gas demand increases came from higher utilisation of gas-fired generation in Southern China, influenced by lower spot LNG prices
» As a result, China’s LNG demand in 2023 seems to, once again, exceed that of Japan’s reaching a new record.
» In a longer-term perspective, China’s LNG demand is likely to continue to increase but not reaching the magnitude witnessed before. This is due to China’s emphasis on energy security prioritizing renewables and domestic coal.
» Chinese Taipei is investing USD 32 billion into renewables, hydrogen and CCS to realise a lower carbon society.
» While renewable energy sources are estimated to supply some 10% of the total electricity last year, it also continues to build new liquefied natural gas (LNG) importing terminals as part of its long-term energy mix strategy, balancing between securing energy supply and climate mitigation.
» Taoyuan LNG Terminal Development, third LNG terminal, located 1.2 km off the coast of Taoyuan City is expected to complete in 2025.
» Fourth phase of the Taichung LNG expansion project is scheduled to complete in 2029.
» Power generation accounted for 84% of total LNG demand in 2022, up 3.4% from 2021. LNG generates 35% of the country’s electricity with coal 45% and nuclear 12%.
Chinese Taipei is investing USD 32 billion for renewables, hydrogen and CCS to realize lower carbon society.
» By mid of this decade, approximately 50% of Taipei’s electricity is estimated to be generated from LNG, with the remaining 30% from coal and 20% from renewable sources.
» New Zealand is pursuing its Hydrogen roadmap to replace natural gas which outline the Government’s position on the future role of hydrogen supporting the transition to net zero 2050.
» As of June 2023, the government has invested $45.5 million in hydrogen-related research.
» New Zealand’s gas pipeline network is foreseeing transitioning to 100% hydrogen by 2050. Hydrogen blends of up to 20% can reduce carbon emissions by approx. 6% without changes to existing appliances. But once 20% of admixture is
reached, existing gas appliances need to be replaced.
» New Zealand’s transition to 100% hydrogen beyond 20% may serve as an example for others seeking replacing methane with hydrogen.
» With the change of government, energy policy may shift to more nuclear and LNG in coming years.
» South Korea relies on 100% of natural gas from overseas. It imported 45 mil tons in 2023 down from 2022 due to increase of nuclear power generation. KOGAS imports LNG based on 80% long term contract. It aims to diversify LNG sources reducing its share for Qatar from 40% down to 20% and reducing LNG from Russia but maintaining imports from Australia.
DIDIER HOLLEAUX
President Eurogas, Executive Vice President Engie and IGU Regional Coordinator.
» After spending most of 2023 between 35 and 55 EUR/MWh (despite some weaknesses in late May and at the peak of summer) European prices of natural gas day ahead on the TTF market place (NL) started to decrease at the end of November.
» An unusually warm start of the winter (except in Scandinavia) combined with a very high level of gas in storage at the beginning of the winter (some significant quantities had even been stored in Ukraine for the western European countries) explained this decrease. By January 15, storage was still on average 80% full in the EU. This level didn’t allow Europe to import a lot of LNG and, as a consequence, some LNG was redirected to other destinations and the price of spot LNG weakened. By end of January the spot price is below €30 per MWh.
» The effect is even more impressive on the futures contracts. The prices of gas for delivery in 2024 remained between €45 and €60 per MWh during most of 2023. They started to decrease in November and are today around €30 per MWh, which translates into a very flat forward price curve.
» That means that the market thought that the risk of shortage of gas for winter 23/24 is very low. Nevertheless this isn’t the case for next winter, and even more for winter 25/26, when any combination of cold winter and production reduction may lead to a tense situation and high volatility.
» The consumption of gas in Europe in 2023 has remained at a low level, even lower than 2022 (around -8% or -31 bcm for EU+UK)
» On the industry side, this is a consequence of the
combination of efficiency efforts but also demand destruction (for instance in fertilisers), even if H2 2023 show some improvement compared to the first half of the year.
» Gas in power generation decreased by 15 bcm and accounted for almost half of the global reduction.
» On the heating side (roughly one third of the reduction) the reduction was due to warm weather, but also demand reduction under price pressure (the customers couldn’t afford to heat their homes or offices as much as usual).
» Russian pipe gas supplies remained more or less at the level where they had stabilized after summer 2022, i.e. 26 bcma (compared to 140 bcma in 2021, before the Russian war in Ukraine).
» Globally the LNG imports remained stable (142 bcm vs 144 bcm at EU+UK level), and the Russian LNG imports too (22.5 bcm vs 22 in 2022, and vs 18.5 in 2021).
» The share of US LNG in the imports increased (74 bcm vs 68 in 2021). Nevertheless, it has to be noted that, for EU only, the 61.6 bcm are less that 40 bcm higher than the pre-war level, and still far from the objective communicated by presidents Biden and Von der Leyen in March 22 (an additional US supply to the EU of 50 bcma ).
» Regarding LNG, we need to take into account that, following the agreement between Bulgaria and Turkiye, some quantities of LNG delivered in Turkish terminals may in fact supply the Southeastern European countries.
» Norwegian supplies to Europe decreased slightly (107 vs 115 bcm) due to maintenance. North African and Azeri supplies by pipe were stable (resp. 33 and 12 bcm).
» Globally (pipe + LNG) the supply of Russian gas to the EU is today less than one third of what it was before the war (48 bcm vs 153).
» The increase of the LNG import capacity is still very actively pursued in Europe with FSRUs being commissioned in 2023 (for instance Le Havre, France, or Piombino, Italy) or about to
be commissioned (Alexandroupolis, Greece), and LNG onshore terminal projects progressing (for instance in Germany).
» As far as pipe are concerned, following the completion of Interconnector Greece-Bulgaria in 2022, the countries of the region are working on developing their interconnections and specially the “vertical corridor” which will allow to ship gas from South to North along the Black Sea.
» In many parts of Europe, Gas TSOs have been actively improving their installations to adjust to the new gas flows resulting from the reduction of Russian gas imports.
» A lot of hydrogen projects are actively being developed in Europe, both for industry and mobility. Nevertheless, after a lot of enthusiasm in the past years, 2023 has seen some developers reassessing their projects, and putting some of them on the back burner, either because of inflation, because of supply chain issues (manufacturers of electrolysers are struggling to deliver quantities and quality), or lack of customer commitment.
» Biogas is still developing well. Europe produced 21 bcm of biogas through 1,300 plants in 24 countries in 2023, of which 4.2 bcm of biomethane. The industry is focusing on the target of more than 35 bcm of biomethane in 2030 in the EU.
» At the same time, other sources of biomethane are being developed, as the Salamnder Project in Le Havre, which was officially launched in June 2023 and aims at producing gas from plastic and timber waste.
» Therefore, we anticipate that the development of green and low-carbon gases could, within a few years, compensate the continued decrease of the domestic natural gas production in Europe, and stabilize the level of domestic gas resources.
» The European gas industry shall remain prudent for the two years to come because we know that the offer/demand balance is tight and that a cold winter or a combination of technical or political events could create a new crisis.
» In the long term, we see the world LNG offer/demand equilibrium improving after 2027, unless the Asian demand for gas increases dramatically.
» In this context the pause decided by the US administration in the permitting of new LNG project exporting to Europe is seen as a negative signal and a significant risk to increased prices and volatility in the medium term. The European industry has expressed its concerns to the US administration.
...any combination of cold winter and production reduction may lead to a tense situation and high volatility.
KHALED ABUBAKR
Chairman, Egyptian Gas Association. Executive Chairman, TAQA Arabia and IGU Regional Coordinator
The current dynamic developments in Africa’s gas industry demonstrate the continent’s growing importance as a key player in the global energy market. The agreements and projects outlined below highlight the efforts of African countries to increase domestic production, explore new reserves, and diversify their energy sources, while also looking to grow domestic economies and improve access to energy. These projects have high potential to drive economic growth, create employment opportunities, and improve energy security not only within Africa but also in neighbouring regions and even Europe.
» Eni and the National Oil Corporation of Libya (NOC) agreed on the development of “Structures A&E”, a strategic project aimed at increasing gas production to supply the Libyan domestic market as well as to ensure export to Europe. “Structures A&E” is the first major offshore project in the country since the early 2000s. The combined gas production from the two structures will start in 2026 and reach a plateau of 750 mmcf per day (million of standard gas cubic feet per day). The project also includes the construction of a Carbon Capture and Storage (CCS) facility at Mellitah, allowing a significant reduction of the overall carbon footprint, in line with Eni’s decarbonization strategy.
» Nigeria, Morocco intensified discussions to accelerate the Nigeria-Morocco Gas Pipeline Project in line with the series of Memoranda of Understanding (MoUs) signed between the two countries in Abuja in 2022. Both parties emphasized the strategic importance of the project to the two countries and the entire African continent and the need to drive it to
completion expeditiously in line with the objective of stemming energy poverty on the African continent. The 48” x 5,300Km pipeline, with capacity of 30 bcm per year, would traverse Republic of Benin, Togo, Ghana, Cote d’Ivoire, Liberia, Sierra Leone, Guinea, Guinea-Bissau, Gambia, Senegal, Mauritania, and terminate in Morocco with a spur to Spain.
» Algeria’s SONATRACH has signed a ten-year agreement that will extend the company’s long-term storage and redelivery capacity at the UK Grain LNG terminal starting from January 2029. This is the first agreement covering an import capacity of 125 GWh/d (equivalent to 3 MTPA of LNG), resulting from the competitive auction process initiated by Grain LNG, launched in September 2023. The Grain LNG terminal, located on the Isle of Grain in Kent, has been expanding to store and deliver the necessary quantities of gas to meet up to 33% of gas demand from the United Kingdom.
» Tanzania Petroleum Development Corp. has doubled its stake in the Mnazi Bay natural gas field operated by Etablissements Maurel & Prom SA as part of plans by the East African nation to increase government participation in strategic projects. TPDC signed an agreement with the French company on February 3 to boost its share in the gas-producing prospect south of the country to 40%, after purchasing a 20% stake from the Paris-based company for $23.6 million. Maurel & Prom – before the latest transaction – controlled 80% of the Mnazi Bay gas field. President Samia Suluhu Hassan is pushing for Tanzania to boost production of natural gas and build pipelines to export it to neighboring countries.
» Eni announced the introduction of gas into the Tango Floating Liquefied Natural Gas (FLNG) facility moored in Congolese waters, only twelve months after the final investment decision. Following completion of the commissioning phase, Tango FLNG will produce its first LNG cargo by the first quarter of 2024, placing the Republic of Congo on the list of LNG-producing countries. The Tango FLNG facility has a liquefaction capacity of about 1 bcm per year and is moored alongside the Excalibur Floating Storage Unit (FSU), using an innovative configuration called “split mooring,” implemented for the first time in a floating LNG terminal.
» Australia’s Invictus Energy Ltd. has discovered gas in northern Zimbabwe, nearly three decades after Exxon Mobil Corp. halted its efforts to locate oil in the area. Four samples from the Mukuyu-2 well at the CaboraBassa project have revealed the presence of gas. While this development is promising for the East Southern African nation, Invictus will need to conduct further drilling to determine the exact volume of the reserves. Exxon, then Mobil Oil Corp., abandoned exploration in Zimbabwe back in the 1990s after concluding that any discoveries were more likely to hold gas than oil. Its data was used by Invictus, which in March last year reached an agreement with Zimbabwe to increase its exploration license area sevenfold.
» Uganda and Tanzania have agreed to carry out a feasibility study for a pipeline linking Tanzania’s gas fields to Uganda. Tanzania has an estimated 57.5 trillion cubic feet of recoverable natural gas and uses some of it to produce 64% of the 1,872 MW electricity on the grid, according to the ministry of energy. Uganda has an installed generating capacity of about 1,500 MW reliant mainly on hydropower and is moving to diversify its sources of electricity and accelerate its energy transition. Tanzania is currently awaiting cabinet approval for a $42 billion liquefied natural gas (LNG) project after completing negotiations with Equinor, Shell and Exxon Mobil. The project would unlock a natural gas deposit of more than 36 trillion cubic feet.
» TotalEnergies and its partners CNOOC, Sapetro, Prime 130, Nigerian National Petroleum Company Ltd announced the start of production from the Akpo West field on the PML2 license in Nigeria. Located 135 kilometers off the coast, Akpo West is tied back to the existing Akpo Floating Production Storage and Offloading (FPSO) facility, which started-up in 2009 and produced 124,000 barrels of oil equivalent per day in 2023. By mid-2024, Akpo West will add 14,000 barrels of condensate production per day, to be followed by up to 4 mmcm of gas per day by 2028.
» Petrofac has secured a new contract from BP to provide operations services for the Greater TortueAhmeyim (GTA) liquefied natural gas project in Mauritania and Senegal. The multi-million-dollar deal is for three years and covers a wide scope of services, including onshore and offshore
management and supervision, provision of personnel, and equipment maintenance. The GTA project is about 90% complete, according to BP. The field, located offshore on the border between Mauritania and Senegal, will produce gas from an ultra-deepwater subsea system and mid-water floating production, storage and offloading (FPSO) vessel, which will process the gas and then transfer it to Golar LNG-owned Gimi FLNG unit.
» Angola’s Sonangol inaugurated December 14 the second phase of the Falcão project, an investment of $42.8 million dollars (€38.9 million) that will supply gas to the combined cycle thermoelectric plant and fertilizer factory in Soyo. The aim is to supply treated gas to the Soyo plant in Zaire province and to other industrial projects such as the ammonia and urea factory, which is considered strategic for the country, guaranteeing self-sufficiency in fertilizers.
The recent developments in the oil and gas industry in Africa demonstrate the continent’s growing importance as a key player in the global energy market.
Innovation is critical to maintaining the value proposition of energy to society. As will be seen at the upcoming IGRC2024 conference, there’s more to it than developing new technologies: it involves a host of other dimensions that have a positive impact on society.
Throughout history, innovation – in its broadest sense – has enabled society to prosper, and people to enjoy a better quality of life and greater freedom. This is especially true for energy, where the greater availability of affordable, reliable, acceptable energy has delivered profound benefits. But today when we think of innovation in the energy world, we tend to focus on specific technology developments, such as a gadget that delivers efficiency improvements or reduces environmental impacts. Such developments are indeed integral to innovation. However, a step back from the very particular technical sense to the broad sense opens the door to a much needed reflection on the deeper value of energy to society.
Gas Innovation Fund (NGIF) – a creation of the Canadian Gas Association to trigger entrepreneurial activity in the gas sector. That effort has evolved into a series of projects including a grants fund offering no-stringsattached awards to entrepreneurs with creative ideas, a venture fund making equity investments in start-ups that have proved themselves, and an emissions testing centre working to measure performance and de-risk various new ideas. Funded by the full gas value chain, the NGIF entities and their work with start-ups are driving innovation forward in Canada’s gas sector.
impacts, and better waste management practices are innovations in the sector driven by a commitment to continuously improve – which in itself is an innovative way for companies to operate. IGRC2024 will explore notable examples of gas sector innovation that have delivered significant environmental benefits.
And finally, on the broader topic of the value proposition of gas for society at large (and how that underscores innovation in all other things), IGRC2024 will see leaders from around the world share their perspectives on the status of the gas industry in their country, and how gas innovation is addressing and can further deliver on their country’s key priorities.
A special NGIF project for IGRC2024 – a Global Cleantech Challenge involving the award of up to $10 million in grant money – will see a selection of prize winners from across Canada and around the globe recognized at the Banff global conference. Award winners – after a rigorous review process – will be identified for their clean technology development ideas in natural gas production (upstream), transmission (mid-stream), and distribution and end-use applications (downstream). IGRC2024 will host the award ceremony for the finalists of this challenge.
TIMOTHY M. EGAN PRESIDENT & CEO, CANADIAN GAS ASSOCIATIONThe programme for the upcoming International Gas Research Conference (IGRC2024) reflects this broader scope of innovation. IGRC2024 is building on the tradition of past IGRC’s – a strong R&D focus – and adding other aspects of innovation including the merit of fuelling new ideas through start-ups, the long-term benefits of social innovation, deeper environmental benefits, and an appreciation of the value proposition of how gas energy and its infrastructure undergird a prosperous society. Exercising ‘home ice advantage’ (as we say in hockeyloving Canada) IGRC2024 will present an opportunity to showcase domestic examples of much of this broader reflection.
On start-ups, the event will give profile to the Natural
On the topic of social innovation, IGRC2024 will provide an overview of how Canadian energy companies and indigenous communities are working together to develop innovative new models for energy project development. One of the most remarkable aspects of the LNG industry in Canada today is that indigenous communities have become environmental regulators, partners, investors – and increasingly, champions – of projects. The message is that LNG development in Canada has presented a clear and key path to indigenous economic reconciliation – the extension of enormous opportunities for Indigenous Peoples in Canada to participate in and prosper from the natural gas value proposition.
Socially innovative models like these create value for communities, certainty for proponents and investors, and a foundation on which technical solutions can establish their value. They also show how gas energy development can address challenging global issues like poverty, which has been an all-too-common reality for many indigenous in Canada. Social innovation in the gas sector is helping indigenous people rise above that poverty.
On the broader environmental agenda, over the past several decades, increased gas use has delivered enormous environmental performance improvements. Lower air emissions, reduced water use, reduced land
One fundamental point likely to come out of these discussions is how maintaining energy diversity is a paramount concern. A recent weather episode serves as a vivid illustration. During the second week of January, a “polar vortex” locked in across North America, driving temperatures down well into the minus 40s (°C), with wind chills in the minus 50s (°C). It triggered alerts from various authorities to reduce electricity use. On January 12, around 4 pm in the western Canadian province of Alberta, wind and solar generation facilities were operating at only a few percentage points of their capacity. But power was desperately needed. Fortunately, a combination of in-province and neighbouring jurisdiction power sources – such as natural gas-powered plants – helped meet the power needs of the province.
The alerts were all about a single energy system: the Alberta electricity grid. While that grid was under strain, a parallel system – the natural gas delivery system –was supplying approximately nine times the energy and operating without any alerts required: while there was approximately 12,000 MW of electric power on hand, there was at the same time over 110,000 MW of gas energy equivalent keeping the province going.
The episode made clear how multiple options in an energy system are key – the innovative integration of those systems to ensure customers get the reliable, affordable, acceptable power they need is the priority.
When IGRC2024 comes around in Alberta at the beautiful mountain community of Banff this May, we should be past such extreme cold threats. The conversation will be thought provoking and rewarding. We hope you can join us to fuel the innovation agenda!
Innovations, supported by collaboration and public-private partnerships, will be essential to make a success out of the energy transition, GTI Energy CEO Paula Gant tells Global Voice of Gas.JOSEPH MURPHY
Collaboration and private-public partnerships can help drive the impactful innovation needed to fulfil the bold ambitions of the energy transition, which will involve not only decarbonising energy but all economic activity,
Paula Gant, CEO of US technology development group GTI Energy, tells Global Voice of Gas (GVG). Fuels – both liquid and gaseous – will continue to dominate global energy supply, GTI Energy believes, and the infrastructure used today for hydrocarbons will be of critical use for future drop-in fuels on the road to net zero.
In the years following the Paris Agreement in 2015, private investors and industry stepped up to channel capital into the energy transition, and turn aspirations into action, Gant says. By 2019, energy companies began announcing their own net-zero ambitions, mirroring those made earlier by governments.
“The money was starting to move, and it was no longer just about government intentions. It became about companies making commitments to their investors,” Gant says. “Then the industry started working back from those mid-century commitments to figure out how they will get to net zero. And that’s where innovation comes into play.”
So far, most focus has been on decarbonising electrical systems, and while that work must continue, reaching net zero is a monumental task that will require decarbonising not only entire energy systems but entire economies, Gant says.
“That’s going to take positive, disruptive innovation,” she says, citing the US shale revolution as an example, which in a relatively short amount of time has massively expanded global energy supply.
“There are lots of bold ambitions for the energy transition, but there is also a lot of uncertainty about pragmatically what to do about it,” Gant says. “At the same time there needs to be a sense of urgency – the future is now.”
“There are no solo acts in the energy transition,” she says. “We at GTI Energy are all about impact, and collaboration and partnerships allow us to create that impact.”
Following early research, government funding or other support often helps get technologies off the ground in terms of development. Then, in order to commercialise the technologies, large-scale operators and private equity bring to the table a business strategy and an understanding of how a solution is going to be received on the market, as well as operational and technological know-how and financing, Gant explains.
Despite the great uncertainty about how the energy transition will take shape, what is clear is that fuels, not just electrons, will be needed for the foreseeable future. GTI Energy last year published a meta analysis of five public studies on the pathways for decarbonising the US economy by 2050. The intent was to identify commonalities across the studies, to reduce the high level of uncertainty regarding the energy transition.
“A key thing that came out is that molecule fuels –gases and liquids – are ubiquitous in net-zero energy systems. They play a central role across the economy including in power generation. Even in the studies that assume the most aggressive electrification, we’re still seeing 60% of final energy demand underpinned by fuels.”
If fuels are to retain their dominant position, then efforts should be directed towards decarbonising those molecules, Gant says.
The analysis of the studies also concluded that pipeline gas infrastructure would be critical in every netzero scenario.
Energy systems need not only to be lower-carbon but also lower-cost. “We’re not just looking to decarbonise developed economies, we’re looking to have decarbonised, growing and robust economies in the developing world.”
This should be a central goal when mapping out the pathway towards net zero. The emphasis should also be on what can be achieved in the short term that can have multiplier benefits in the long term, whether in the developed or developing world, according to Gant.
“It may be that the molecules moving through those pipelines may change. We may have increasing renewable natural gas, or hydrogen-rich gas, or synthetic methane as drop-in fuels moving through those pipelines in the future, but we’re going to need that infrastructure,” she says. “It accelerates the pace and it reduces the cost of reaching net zero.”
In order to move new technologies and operational practices from the research phase to commercialisation, collaboration is key. GTI Energy seeks to create platforms where stakeholders can come together to de-risk the experimentation with these technologies and practices. Also critical to supporting new innovation is public-private partnerships.
Natural gas can support energy security, raise living standards and reduce emissions across the world, but addressing methane emissions is necessary to maximise its climate benefit, Gant says. Supporting this cause is the Veritas initiative.
For the last few years, GTI Energy has been working with operators across the natural gas supply chain along with other stakeholders – from academics and environmental NGOs to investors, policymakers and
“A key thing that came out is that molecule fuels – gases and liquids – are ubiquitous in net-zero energy systems. They play a central role across the economy including in power generation. Even in the studies that assume the most aggressive electrification, we’re still seeing 60% of final energy demand underpinned by fuels.”
PAULA GANT, CEO OF GTI ENERGY.
technology providers – to develop a consistent approach to measuring and verifying methane emissions. And Veritas, released in February 2023, was the product of that labour.
Veritas provides standardised, science-based and technology-neutral measurement protocols that are designed to assemble methane emissions inventories that are verified by direct field measurements, providing data that is credible that can in turn help the oil and gas industry report and ultimately address its emissions.
Heightened awareness of the climate impact of methane emissions has led to a flurry of technology and equipment solutions emerging to tackle the problem, as well as various emissions certification schemes.
“We were looking for a way of creating some simplicity out of that confusion with Veritas,” Gant says. “The elemental role is to create greater credibility assigned to the data that we’re getting off of all these new technologies that are coming into the space, and greater confidence in how companies are using that data to create their emissions inventories, whether for regulatory or investor reporting or natural gas certification.”
This helps operators and regulators determine which combinations of technologies provide the best information for specific types of operations. Not only does this lend credibility to reporting, but it also helps operators reduce the cost of quantifying and reducing their emissions.
GTI Energy and partners released an updated second version of the Veritas protocols in December.
The organisation is looking to introduce a similar standardised methodology for accounting for emissions from low-carbon hydrogen supply, through its Open Hydrogen Initiative.
“What success looks like for the Open Hydrogen Initiative is that we no longer talk about the colour of hydrogen, whether green or blue or otherwise, because we can be much more granular and accurate about what the carbon intensity of hydrogen is at the point of production,” Gant says. “Plan a funeral for the hydrogen colour wheel.”
Hydrogen is “having its moment,” she says. It is extremely versatile as a low-carbon fuel, with applications across heavy industry, transport and power generation, and serves as a valuable energy carrier. In the US, “catalytic” investments are being made to create the hydrogen economy. The role of the US Department of Energy has shifted, from being a subsidiser of early research and development to focusing on commercialising and scaling up hydrogen technologies, she says, from establishing public-private partnerships to providing low-cost capital through the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA).
Certified natural gas is increasingly being seen as a tool for producers to reduce their environmental footprint and, perhaps more importantly, prove that to their customers and their critics.DALE LUNAN
GEORGES TIBOSCH CEO, MIQ JON OLSON CEO, CG HUB
Natural gas is expected to fill an ongoing role in a secure global energy future, but producers are, at the same time, expected to strive for continuous improvement in their environmental performance and provide greater transparency surrounding the impact natural gas has on the environment.
In recent years, this has translated into a growing movement to certify natural gas as “responsibly produced” using a number of platforms. In some cases, producers are opting for more than one certification process, to capture the most benefit from the “responsibly produced” label.
MiQ, considered the global leader in methane emissions certification, has certified about 20% of US natural gas production. MiQ grades natural gas on its methane emissions and awards a letter grade – from ‘A’ to ‘F’ – to assist in the differentiation of natural gas production and incentivise continuous improvement along the natural gas supply chain.
Grade A certification is awarded for methane emission intensity at or below 0.05%; a B grade is awarded for methane intensity at or below 0.1%, while a C grade is
awarded for methane intensity at or below 0.2%. Only facilities with an A, B or C grade are certified.
In October 2023, Gulfport Energy was added to MiQ’s list of certified producers, earning an ‘A’ grade on its 1 bcfd of Appalachian gas production, while in November 2023, privately-owned PennEnergy Resources received an A grade from MiQ across its entire operating asset base of 400 Appalachian wells. That boosted the roster of MiQ-certified facilities to 19, operated by 13 of the largest US natural gas producers, including EQT, Chesapeake Energy, BP and Repsol.
MiQ says it has certified about 21 bcfd of US natural gas production, with 78% of the facilities it has assessed receiving an A grade, which is only available for facilities with methane intensity of 0.05% or less. All the others have methane intensities at or below 0.2%.
For comparison purposes, the MiQ-Highwood Index™, which measures methane intensities along the gas supply chain, applies a methane intensity of 1% to US natural gas production, and 2.2% for the entire gas supply chain.
“Across the total US supply chain the average methane leakage is about 1.0%. But 20%-plus of the US producers are less than 0.2%, which is very good, even on a global basis.”
GEORGES TIBOSCH, CEO, MIQ
“Across the total US supply chain the average methane leakage is about 1.0%,” MiQ CEO Georges Tibosch tells Global Voice of Gas (GVG). “But 20%-plus of the US producers are less than 0.2%, which is very good, even on a global basis.”
Most of MiQ’s certification work is focused on the upstream and midstream sectors of the industry, but it has also developed a greenhouse gas (GHG) emissions framework to assess all emissions of methane, CO2 and NOX from the LNG supply chain. By the end of the year, it hopes to begin certifying LNG production and to eventually provide certification that proves the methane intensity of a particular LNG cargo.
Such certification may become exponentially more valuable to gas producers and LNG developers in light of US President Joe Biden’s pause on new applications to export LNG to non-FTA countries. Biden ordered the review – apparently to improve his standing with his leftwing base ahead of the November presidential elections – and asked the Department of Energy to consider the methane intensity of LNG exports and how they impact the global climate crisis.
“This federal review is being used to hold the LNG industry accountable because operators have failed to be transparent on emissions,” Tibosch said when the review was announced.
If LNG is to be seen as an energy solution in the medium term – as many gas industry players insist – its emissions profile needs to be better than the coal it is intended to replace. And producers and LNG developers need to be able to prove that, Tibosch added.
“LNG exporters need to step up and have the emissions of their assets and gas purchased verified by third party auditors, so that they can prove their LNG is a net positive for the climate compared to coal.”
While all of MiQ’s certifications so far cover US natural gas production, it is looking abroad to expand its coverage, including in the North Sea, Tibosch tells GVG
“We are starting to engage with a lot of national oil companies as well, for example, because the national
oil companies, some of them might have high methane emissions, but the companies that have got high methane emissions, they are actually the easier ones to solve quite often because it’s much more difficult to go from 0.1% to 0.05% – by then you’re doing a lot of tweaking, but those first couple of percentage points, in particular, it is quite clear, generally, what needs to happen.”
Equitable Origin, another growing certification platform, measures the environmental impact of oil and gas production based on five principles – corporate governance, human rights, Indigenous Peoples’ rights, fair labour conditions, climate change, biodiversity and environment. Equitable Origin says it has certified about 15% of US and Canadian natural gas production, with some producers certified by both the MiQ and the EO100™ protocols. Apart from the joint certifications, Equitable Origin has certified about 3 billion cf of natural gas.
Equitable Origin’s EO100 Standard for Responsible Energy Development (EO100™) certification produces a letter grade for site performance in meeting each of the five principles, with a minimum ‘C’ grade for each of those principles required to achieve certification.
“The role of natural gas in the energy transition is highly contested and justly so,” Equitable Origin CEO Jason Switzer wrote in a year-end blog in January. “EO’s model of global standards and expert independent certification will be essential in helping to crediblydifferentiate better performance.”
Its partnership with MiQ, he added, allows producers to undertake both certifications at reduced cost and disruption, “combining our broad ESG coverage with their laser focus on methane abatement.”
Earlier this year, Seneca Resources became the first producer to receive an A grade under EO’s new system, demonstrating scores of 98% or higher across all five ESG principles in the EO100™ standard.
Alongside the original standard, Equitable Origin has developed technical supplements for onshore natural gas and light oil production, natural gas gathering and processing and natural gas transmission and storage, which is still in a draft stage.
“This is what the market needs –a centralised place for liquidity. The market needs a place where it can get that price discovery, count what, where and at what price. And they need market education.”JON OLSON, CEO, CG HUB
Some of the largest gas producers in the US and Canada have been certified under the EO100™ standard, including EQT, Chesapeake Energy, ARC Resources, Equinor, Seneca Resources, Northeast Natural Energy, Vermilion Energy and Pacific Canbriam Energy.
As the volume of certified gas continues to grow, the market is clamoring for a platform on which to trade both certified gas, which can fetch a premium, and the underlying environmental certificates generated by the production of certified gas.
Two platforms have emerged as leaders in this field, CG Hub, which was launched by TruMarx Data Partners in 2023, with the collaboration of from MiQ and other subject matter experts, and Xpansiv, which uses blockchain technology to facilitate the trade of certificates.
CG Hub trades in both physical gas and certificates, while Xpansiv trades only in certificates.
“The growth in the certified gas market has been rapid, and we expect to see the trading volumes rise as buyers are gaining a deeper understanding of how certified gas could contribute to their sustainability strategies,” Tijbosch says. “The ability to trade MiQ certificates on the CG Hub provides a huge opportunity for buyers to choose lower emissions natural gas and demonstrate Scope 3 emissions reductions, and we expect other platforms to join imminently too. Having certified 20% of US natural gas, we are moving closer
to achieving our goal of eliminating oil and gas methane emissions this decade.”
While Jon Olson, CEO of CG Hub, isn’t in a position to identify who is actively trading on the hub due to confidentiality provisions, he does tell GVG. “it’s a premier list with some great names, and it’s growing continually.”
Seneca Resources and Northeast Natural Energy were among the first to join the hub in the summer of 2023, and together provide customers access to more than a billion cfd of certified gas liquidity.
“This is what the market needs – a centralised place for liquidity,” Olson tells GVG. “The market needs a place where it can get that price discovery, and see who has what, where and at what price. And they need market education.”
Although the CG Hub is a marketing partner with MiQ, the platform is certifier agnostic, Olsen says. It manages information from Project Canary, another provider of certification services, from Equitable Origin, and from partners in the Oil & Gas Methane Partnership 2.0 (OGMP). It also will manage information provided by producers who choose to self-certify.
“We’re certifier agnostic, we’ll work with anybody. We’re registry agnostic, we’ll work with anybody. Our goal is to help our customers work with who they want to work with [and] to have a permanent record of what they did so they can report it. The whole name of this game is reporting. What’s the sense of measuring any of this stuff unless you report it.”
standard for certifying hydrogen as clean will unlock needed investment and facilitate trade, bringing about a global market for the fuel.JOSEPH MURPHY
Blue hydrogen has an important role to play in the energy transition, but a single internationally-accepted set of standards for certification of how cleanly it is produced is needed to unlock investment, facilitate trade and build a global market for the low-carbon fuel, the King Abdullah Petroleum Studies and Research Centre (KAPSARC) argues in a discussion paper published in December.
Hydrogen is classified as blue when it is produced from natural gas via steam methane reforming, with CO2 that results from the process being captured and safely stored. In the paper, Enabling Blue Hydrogen for a LowCarbon Future, KAPSARC notes that the technologies needed to produce blue hydrogen are both scalable and technologically mature, without needing significant innovation for deployment. In contrast, the development of large-scale electrolysers to produce green hydrogen from water “is still in its infancy,” Rami Shabaneh, a research fellow at KAPSARC that co-authored the report, tells Global Voice of Gas.
“Blue hydrogen can facilitate the rapid and substantial reductions in emissions that we need to meet those 2050 targets,” he says. “We cannot simply wait for green hydrogen to scale up. But blue hydrogen needs to be developed responsibly.”
Prior to the energy crisis, it cost $1.5-2.5/kg to produce blue hydrogen, versus a wide range of $3.1-9.0/kg for green hydrogen, according to the International Energy Agency (IEA) (see figure 1). When natural prices climbed to record heights in 2022, its cost rose to $5.3-8.6/kg, though gas prices have since subsided.
In any case, blue hydrogen can be developed more rapidly thanks to its technological maturity and scalability, supporting the development of hydrogen infrastructure and encouraging hydrogen utilisation, creating a market that is ready for when green hydrogen is available at scale, KAPSARC notes.
If you look at the emerging certification schemes, they are defining what is clean very differently.
RAMI SHABANEH, RESEARCH FELLOW AT KING ABDULLAH PETROLEUM STUDIES AND RESEARCH CENTER.
On how clean blue hydrogen can be, based on IEA data, that hydrogen produced using a SMR with a 60% carbon capture rate, which has been achieved at existing facilities, results in an emissions intensity of 5-8 kg of CO2 equivalent per kg of H2 (see figure 2). This drops to around 1-6 kg with capture rates above 90%, where upstream and midstream emissions comprise most of the overall emissions. KAPSARC notes that capture rates exceeding 90% are feasible when emissions are addressed from flue gases produced in the SMR furnace’s combustion process, and that advanced technologies such as partial oxidation reforming and autothermal reforming can achieve capture rates of more than 95%.
In contrast, green hydrogen has an intensity range of 1-2 kg.
However, though momentum behind clean hydrogen is
growing, it is critical that standards and certifications are implemented to build a sustainable economy for the fuel. The standards serve as predefined criteria or benchmarks for the value of the hydrogen in reducing emissions, while certification is needed to confirm whether those standards have been met, covering the whole supply chain from production to storage and transportation to end use.
Since the global clean hydrogen industry is very new, experience in certification is limited, and most existing and proposed schemes are focused on green rather than blue hydrogen.
“This situation is unsatisfactory given the significant role blue hydrogen could play in accelerating the commercialisation of clean hydrogen globally,” KAPSARC says.
As it currently stands, green hydrogen dominates
RAMI SHABANEH, RESEARCH FELLOW AT KING ABDULLAH PETROLEUM STUDIES AND RESEARCH CENTER.the pipeline for clean hydrogen projects. Of the clean hydrogen projects slated to come online by 2030, with a combined capacity of 38 MTPA, 25 are green hydrogen and only 13 are blue hydrogen.
Standards and certification are key to secure policy support for production projects, facilitate international trade and generate demand. But not only are most existing systems, including both voluntary and mandatory, designed for green hydrogen, as noted, those that do apply to blue hydrogen vary greatly in standards.
“You need certification because end users, who are paying a premium for it because it’s clean, need to know its environmental attributes, how it’s produced and its carbon intensity,” Shabaneh says. “But if you look at the emerging certification schemes, they are defining what is clean very differently.”
For instance, the EU classifies hydrogen as clean if its emissions intensity is no more than 3.4 kg of CO2 equivalent per kg of H2, whereas hydrogen must have an intensity of under 4 kg to secure subsidies in the US. In the UK it is only 2.4 kg.
Then there is the issue of how that intensity is calculated. While the EU RED II system covers well-towheel emissions, the UK and US schemes include only well-to-plant gate emissions. There is greater disparity in voluntary schemes, with China Hydrogen Alliance counting emissions only from the production plant and the Japa Aicihi Prefecture Low-Carbon Hydrogen Certification covering plant gate-to-wheel emissions, excluding the upstream.
This will cause problems given that there needs to be significant international trade of blue hydrogen for the fuel to make an impact on emissions, with countries like the US and in the Middle East positioning themselves as exporters to serve import markets such as Japan and the EU.
“If you’re an exporter like Saudi Arabia you are vulnerable because it’s very hard to design a plant right now when different regulations are in place in different countries, so hydrogen from your multibillion-dollar project could be accepted in one place and not another, because it doesn’t fit the criteria,” Shabaneh explains.
Governments need to work towards a mutuallyaccepted certification scheme based on the same
“We all need to be working on the same Excel sheet to calculate the carbon intensity of the hydrogen production, and this will facilitate trade and encourage investment,”
RAMI SHABANEH, RESEARCH FELLOW AT KING ABDULLAH PETROLEUM STUDIES AND RESEARCH CENTER.
standards, he says, with the same methodology used to calculate the carbon intensity of different production pathways.
“We all need to be working on the same Excel sheet to calculate the carbon intensity of the hydrogen production, and this will facilitate trade and encourage investment,” he says.
KAPSARC also argues in its paper that there should be separate certifications for surface and subsurface emissions. In the case of blue hydrogen, the former would primarily relate to those not captured from the SMR and upstream methane emissions associated with the natural gas supply. The latter would relate to any leakage from permanent storage sites. When it comes to storage, the good news is that there is already international guidance
by the IPCC and UNFCCC setting out definitive criteria for CO2 storage to be considered permanent, Shabaneh says.
Once there is an internationally-accepted standard for hydrogen, then an independent body would be used to audit emissions, with the process potentially supported by digitalisation, Shabaneh says.
A positive step was seen at COP28, when a declaration of intent was announced on global collaboration on certification schemes for hydrogen that has been signed by 40 countries. The intent also recognised the roles of both renewable and low-carbon hydrogen in addressing climate change. Shabaneh hopes that more countries will sign up to the initiative in the runup to COP29 in Baku later this year.
Coal Gasification (unabated)The world needs to embrace CCUS as an essential part of the energy transition, rapidly scaling up its development over the coming decades.JOSEPH MURPHY
Carbon capture utilisation and storage (CCUS) is a proven and practical solution for decarbonisation, and its rapid scale-up is mission critical for meeting net zero, experts tell Global Voice of Gas (GVG).
The case being made that CCUS should have a diminished or even negligible role in the energy transition often rests on unrealistic assumptions about how quickly the world can shift away from hydrocarbons. Time and time again, predictions of peaking demand for fossil fuels have not borne out.
Criticism of CCUS relies on “an uninformed view that the transition from fossil fuels can happen much faster and on a much larger scale than is physically possible, much less intellectually possible,” explains Charles McConnell, executive director for the Center for Carbon Management in Energy at the University of Houston.
“We’re going to add another 2-3bn people to this earth over the next 30 years and most of them will be located in cities.” This means the world will need more energy to move, power, heat, cool, and in many cases –build – these cities.
Adam Sieminski, senior advisor to the board of the Riyadh-based King Abdullah Petroleum Studies and
Research Center (KAPSARC), argues that
Rapidly replacing oil and gas also means rapidly replacing the extensive infrastructure that has been built to support the energy system. The more immediate focus should be on decarbonising hydrocarbon supply, through the elimination of methane emissions and routine flaring, and advancing CCUS, he says.
Often, according to Sieminski, scenarios where CCUS play a minor role in decarbonisation are based on two significant assumptions.
“Firstly, there is a very optimistic view on how much energy demand growth will slow down compared with its growth in the past,” he says. “The second problem is the fallacious idea has been embraced that renewables and increased energy efficiency are all you need to deliver rapid declines in emissions.”
In particular he stresses the lack of other feasible solutions for decarbonising hard-to-abate sectors such as aviation, cement production and metal smelting.
Too much discussion around the energy transition is guided by “philosophy”, McConnell believes. “We need practical solutions, and CCUS provides them.”
CCUS is not an inexpensive technology and the higher the capture rate the higher the cost. “But if you look back 20-25 years, there were people that were saying that solar and wind power were impractical because they were too costly,” Sieminski says. “What we managed to do with scientific and engineering innovations was to bring the costs down – we need to do the same thing with other technologies such as CCUS.”
Meanwhile, the idea that CCUS is an unproven technology is “demonstrably wrong,” he adds. “The oil and gas industry has been finding ways of capturing and storing carbon for half a century.”
Costs vary greatly from country to country and project to project, and are subject to factors such as the concentration of CO2 in the gas at the capture site, the means and distance of transport and whether the CO2 is stored onshore or offshore, according to Alex Zapantis, general manager for external affairs at Australia’s Global CCS Institute.
On one end of the spectrum he points to the Moomba CCS project in south Australia, which developer Santos estimates will have a full lifecycle cost of under $25 per T. The CO2 is separated from natural gas produced at Cooper Basin fields and then stored in depleted reservoirs. On the other end, he notes that costs can reach around $120 per T.
Even at this higher cost, though, the technology is still a very competitive abatement solution compared with the
available alternatives, Zapantis says. And like any other technology, such as renewables, costs will very likely fall as the industry expands, he says, through economies of scale, innovation, increased competition between vendors and greater specialisation, whereby different companies handle capture, transport and storage respectively.
“There is nothing special about CCS in this sense – just as with any other new industry, things get cheaper over time,” Zapantis says. “CCS is only just starting on that journey.”
James Fann, president and CEO of the Canada-based International CCS Knowledge Centre, notes that lessons are being learnt from projects already in operation. Some like the CCS facility at the Boundary Dam power plant in Saskatchewan have been capturing and safely storing CO2 for a decade. Those lessons are now being applied to new and larger developments, to improve capture efficiency and reduce operating and capital costs.
Just as policy support was critical when renewables were emerging, it is also essential for scaling up CCUS. Different countries have adopted different approaches to this support. While the US relies heavily on tax credits, the EU has focused more on grants and loans. Many governments have also restricted or priced emissions, while indirect support has also come from incentives provided for the production of blue hydrogen.
A global carbon tax is critical, McConnell stresses.
Getting one accepted around the world would be no small feat, but precedents have been set regarding other environmental issues, such as international limits on sulphur content in fuels.
“What a carbon tax does is raise the performance requirements for everyone across the board,” he explains. “But when you just have government grants and tax incentives in one place that aren’t there elsewhere, you end up with a global mismatch of countries enforcing requirements and others which are not.”
Policy should enable as many R&D and pilot CCUS projects to be developed globally as possible, Sieminski says, as well as prioritise the advancement of commercial ones that have the greatest impact on emissions. A global agreement on accepted, and robust measurement, reporting and verification (MRV) standards on emissions is also needed, to spur the development of a global market for CCUS.
Policymakers should keep an “open mind” about the options for establishing a circular carbon economy,
whether that is pursuing CCS, direct air capture (DAC) or carbon offset scheme such as forestation, according to Sieminski. An eventual goal should make capture costs so low that CO2 becomes a value-added product. He points to the example of locking away carbon within concrete, which not only abates emissions but also makes the concrete stronger and lighter.
McConnell says he is “encouraged that we’ve moved past the era of only institutional research and government grants, because if that’s all we’re ever going to do, it’s never going to be impactful.” Now the world is moving towards commercial models that can advance CCUS at scale, he says.
Predictable regulation and policy is also key.
“The biggest thing we hear from industry is the certainty they need from regulations and policies,” Fann says, with the lack of that certainty potentially holding back development.
“We can’t be hampering our ability to make investments by uncertainty in the regulatory regime here
“We can’t be hampering our ability to make investments by uncertainty in the regulatory regime here in the US or frankly anywhere in the world. Uncertainty directly impacts risk which directly impacts investment.”
CHARLES MCCONNELL, EXECUTIVE DIRECTOR FOR THE CENTER FOR CARBON MANAGEMENT IN ENERGY, UNIVERSITY OF HOUSTON
in the US or frankly anywhere in the world,” McConnell says. “Uncertainty directly impacts risk which directly impacts investment.”
Based on the average of 90 models reviewed by the UN International Panel on Climate Change (IPCC) in its Special Report on Global Warming of 1.5°C, approximately 10 GT of annual CO2 must be geologically stored by 2050 for the world to keep temperature rise under 1.5°C. According to the Global CCS Institute, there are currently 43 CCS projects operating with a combined capacity of 50 MTPA, another 28 under construction with 33 MTPA of capacity and more than 300 at the study phase with a capacity of around 300 MT.
To reach 10 GT of annual CO2 capacity by the middle of the century, capacity needs to reach the gigatonne level by 2030, but the current project pipeline means it is unlikely it will exceed 1 GT until the mid-2030s, Zapantis says.
“We are not on track, but CCS is not alone. Neither are renewables, bioenergy or many other technologies.”
To make a bigger impact faster, Sieminski stressed the importance of CCUS hubs, like those proposed in the US, Europe and the Middle East, where there is heavy industry to decarbonise, hydrocarbons to produce hydrogen and viable CO2 storage sites, as well as extensive infrastructure to support all this. “Essentially all the elements you need to make CCUS really work.”
But ultimately, progress on CCUS in only select locations in the world is not going to move the dial on climate change, according to McConnell. The technology needs to go global.
“If this doesn’t get all the way to China and India, sooner rather than later, it isn’t really going to make an impact,” he says. “The major emissions are there and we need to provide a technology solution that helps address them. And CCUS can be a big part of that solution.”
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With more robust regulatory demands in Europe, the US and Canada, reliable leak detection technologies are emerging to support compliance.ELSIE ROSS
Amid global concerns about climate change, methane is increasingly important as the potent greenhouse gas driving global warming in the short term.
And as governments mandate Leak Detection and Repair (LDAR) programmes such as US EPA Method 21, Alberta Directive 060 and European Method EN 15446, reliable emissions monitoring has become an imperative for the oil and gas industry.
“What we see is absolutely, there is a lot of pressure at all levels on gas operators to clean up their operations, to convince and justify to their communities and their regulators that they are helping reduce emissions,” Julien Klein, senior director of product development in the gas group at Picarro, a California-based technology company focused on the distribution segment of the natural gas industry, tells Global Voice of Gas. “They have a challenge in convincing society that gas can be sustainable or a bridge energy for the next 50 years.”
In response to that demand, technology companies such as Picarro and Montreal satellite developer GHGSat are developing new technologies capable of more accurate and immediate measurement and leak detection.
Picarro employs vehicle-based surveys along distribution pipelines GHGSat now has a constellation of 12 satellites orbiting the earth to provide real-time leak detection, with
a focus on methane emissions.
Picarro’s AMLD (advanced minimum leak detection) technology is a vehicle-based solution to identify, measure and quantify low levels of methane fugitive leaks and emissions on the gas distribution grid from a distance of several hundred feet, from main or service pipelines.
“The productivity is much higher than the conventional methods of surveying scanning that are typically done on foot,” Klein says.
An analyser on board that is sensitive to parts per billion (essentially three orders of magnitude lower than previous technology) measures both methane and ethane, taking wind conditions into account.
“That allows us to sniff essentially leaks or plumes of gas, even if they’re highly diluted after propagating in the atmosphere,” he says.
As the vehicle goes through a plume, the analysis can determine the source and volume of gas being emitted and whether it’s coming from a natural gas facility with the right mix of methane and ethane or if it’s something that can be attributed to sewer gas or some other biogenic sources.
Data from multiple passes is combined to help narrow the geographical area of interest.
“So it’s not direct pinpointing of a leak, but it’s creating
basically an area of interest that can then be investigated on foot by an operator to find the actual leak,” Klein says.
“We make these very fine measurements and then we have protocols where our customers will join multiple times and will accumulate basically a statistical representation of whatever we are measuring,” he says.
“And we have [focused] in on some algorithms over the past decade, to turn that raw data into something that makes sense that can be consumed by an operator, and that can be acted on by an operator.”
Faster detection of leaks enables operators to repair them sooner, resulting in substantial emission reductions, which also is a driver for regulators, says Francois Rongere, Picarro’s senior director of solution architecture for climate and safety.
Another Picarro game-changer is the capability to estimate flow rate (size of leak) from a distance as part of the data collection from the vehicle, Klein says.
“So it’s very powerful, because without getting out of the car, our customers can have a good idea of where the big leaks are, and where the small ones are,” he says. “So they can do some kind of triage, both at the local level, but also at the scale of the network to understand where the large leaks come from.”
Because the technology and its method are all about being quantifiable, auditable and based on actual measurements it helps increase regulator confidence that operators can address emissions, Klein adds.
“We’re able to take up to millions of data points on these emission flow rates and emission sources so we’re able to build a very robust representation of that distribution of leaks in a network. We use that data to essentially build 100% measurement-based emission inventories.”
Operators can then go to their respective regulators and provide the raw data along with the science and algorithms to demonstrate how they arrived at their results.
Although Picarro technology is “kind of an all-in approach where you make a big capital investment,” that investment yields many benefits, according to Klein.
While some clients are highly focused on emissions abatement, many are also looking at its data as a general source of truth to manage their networks, for public safety, and for maximizing the value of their assets, he says.
“With clients that we work with at scale, we see that the economic benefits of having that data are actually quite substantial and then, the return on investment or the return on equity is very favourable, because that data is so powerful.”
Formed in 2011 as a private company, GHGSat
Faster detection of leaks enables operators to repair them sooner, resulting in substantial emission reductions, which also is a driver for regulators.
launched its first emissions detecting satellite, Claire, in 2016, and since then has added 11 more, including one of the most recent, Vanguard, which is the world’s first high-resolution instrument dedicated to detecting CO2 emissions from industrial sources.
“Our high-resolution satellites helped put methane – a greenhouse gas that was out of sight and out of mind – at the top of the climate agenda,” GHGSat CEO Stephane Germaine said when Vanguard was launched in November 2023. “Now our goal is to harness this experience and change the conversation around CO2. With regulators, investors and the public increasingly holding companies to account, for both their direct and indirect emissions, there is little doubt that better CO2 data is needed.”
All of GHGSat’s satellites use its patented emission sensing technology that can detect methane emissions and locate individual sources of those emissions from polar orbit 500 km above the earth.
In 2022 – the last year for which final data is available – GHGSat’s constellation, at the time comprised of six methane sensors, made more than 500,000 observations spanning close to two million km2 in 69 countries and detected emissions totalling 179 MTCO2-e, a 25% increase over 2021.
In 2023, six more satellites were launched, along with Vanguard. Five of those – Mey-Lin, Gaspard, Oceane, Juba and Elliot – expand GHGSat’s capabilities for the high-resolution detection of methane emissions at the facility level.
The additional coverage provided by the six new satellites helped to detect over 361 MTCO2-e of emissions from more than 14,000 plumes worldwide, Jean-Francois Gauthier, GHGSat’s senior vice-president, strategy, told GVG
And the company has another six satellites on order, with four of them to be launched in the second half this year, he said.
GHGSAT’S SATELLITES C9, C10 AND C11, LAUNCHED IN NOVEMBER 2023. [IMAGE CREDIT: GHGSAT]
Renewable natural gas – or biomethane as it’s called in Europe and Asia – is being used to decarbonise natural gas supply chains around the world.DALE LUNAN
Biogas, derived from a variety of organic feedstocks through natural decomposition in landfills or anaerobic digestion of agricultural waste products or municipal sewage, and upgraded to produce pipeline-ready biomethane, or renewable natural gas (RNG), remains a relatively minor piece of the global gaseous energy equation.
According to the International Energy Agency (IEA), investments in biogas and biomethane have averaged less than $4bn/year over the last decade.
But under the IEA’s current stated policies scenario (STEPS), that spending could more than triple, to reach around $14bn by 2040, while under the agency’s sustainable development scenario (SDS), investments could reach $30bn by 2040.
The IEA thinks that “Biomethane and biogas projects remain the largest destination for low-carbon gas investment, capturing 40% of the total.”
In most countries, using domestically produced biogas and biomethane offers an opportunity to reduce more expensive fuel imports, the IEA says.
Both India and China have substantial biomethane potential, a significant portion of which is available at
relatively low cost, and the IEA projects biomethane consumption in 2040 under SDS at around 35 bcm in India and 90 bcm in China.
“If this energy demand were to be met instead by natural gas, imports would be around 15% higher in India and 35% in China,” the IEA says.
Low-carbon hydrogen and biomethane blended into global gas grids in the IEA’s sustainable development scenario could avoid about 500 MT of annual CO2 emissions.
In Europe, biogas has mainly been used over the last 20 years as a fuel for power generation, but recently, policies promoting diversified use of biogas has led to an increase in biomethane, which is produced from biogas by removing biogenic CO2 and other impurities.
In Europe, the potential for biomethane’s penetration into traditional natural gas markets has caught the attention of banks and major natural gas producers alike.
Goldman Sachs created Verdalia Bioenergy in 2023 to capture biogas and biomethane production opportunities across Europe, while Cargill, the world’s
Global Voice of Gas (GVG) and is working to close on the seventh facility.
UK majors Shell and BP are also jumping in – Shell with its purchase of Nature Energy Biogas, with plants in the Netherlands and Denmark (where biomethane as a part of total gas demand rose to 40% in 2023 from just 3% in 2016), BP with its December 2022 acquisition of Archaea Energy, the largest US producer of RNG.
The $4.1bn deal brought to BP’s portfolio 50 RNG and landfill gas-to-energy facilities which together produce about 6,000 barrels of oil equivalent (boe) per day of RNG. Archaea has a project pipeline that supports a potential five-fold increase in RNG production by 2030, including a joint venture with Republic Services that aims to develop 40 landfill RNG projects across the US.
Last October, Archaea launched its first landfill RNG project since its acquisition by BP, with a modular facility at a landfill in Indiana that will processes 3,200 cf/minute of landfill gas into enough RNG to heat more than 13,000 homes.
Archaea is supplying up to 7.6 mmBtu per year of RNG to Canadian utility FortisBC, which blends it into its natural gas distribution system and has a commercial partnership with Quebec gas utility Energir for the purchase from Archaea of about 2 mmBtu.
And UGI Utilities will purchase more than 300,000 mmBtu per year of RNG from an Archaea landfill site in Pennsylvania over a five-year period.
Canadian energy infrastructure company Enbridge is also a significant player in the North American RNG business, and in November 2023 announced the purchase of seven operating landfill RNG facilities – six in Texas and one in Arkansas – from Morrow Renewables, now called TomorrowRNG.
Enbridge closed on the first six facilities under that deal in January this year, an Enbridge spokesperson tells
“These facilities currently produce an aggregate of about 5 bcf of RNG per year,” the spokesperson says. “The RNG produced is sold under long-term offtake agreements to parties that will use it for compressed natural gas and to sell to other markets.”
Enbridge Gas, the utility arm of Enbridge, is also involved in nine other Canadian RNG projects – six operating and three under construction – with an additional 20 projects in various stages of development.
“We are currently working with various municipalities, landfill owners and private merchants in Ontario, New Brunswick, Alberta and Manitoba to assess and develop RNG project opportunities,” the spokesperson says.
In the spring of 2023, Enbridge announced a $C80mn investment into Divert, a US company which diverts wasted food from landfills and processes it into RNG, and joined with it in a US$1bn infrastructure development agreement, which began to bear fruit in September 2023 when ground was broken on a plant in Longview, Washington expected to be operational by the end of this year, the Enbridge spokesperson says.
“The facility will be able to offset up to 23,000 T of CO2 a year at full processing capacity, the equivalent to removing 5,000 gas-powered cars from the road annually,” the spokesperson says. “There will be more projects to come – locations and specifics haven’t yet been announced.”
Transport is an end use that provides the most revenue for biomethane producers, not only in Germany but elsewhere in Europe and increasingly in the US.
German logistics company Westfalen in January announced a collaboration with food wholesaler EGV to
SOURCE: MORROW RENEWABLES largest agricultural trader, plans as many as three plants in Europe.
“The RNG produced is sold under long-term offtake agreements to parties that will use it for compressed natural gas and to sell to other markets.”
ENBRIDGE
supply bio-CNG to the transport industry, building on the opening in 2023 of its first bio-CNG filling station for commercial vehicles. It is also spearheading the adoption of CO2-neutral bio-LNG, beginning with a campaign to replace conventional LNG with bio-LNG at four Westphalia LNG filling stations.
In the US, California-based Clean Energy Fuels (CEF) is a leading distributor of RNG in North America and in February it opened two new RNG fueling stations in the Dallas-Fort Worth area, expanding on its network of more than 600 such facilities in the US and Canada.
The two stations – and others that are in various stages of development – come at a time when RNG is being increasingly looked at by fleet operators as a way to meet their own emissions reduction goals, CEF says.
Cummins is expected to make its new X15N natural gas engine for heavy duty trucks available for commercial deployment later this year. The engine is already being tested by some of the largest and most demanding fleets in the US, including Walmart, Federal Express and UPS.
RNG sales in 2023, CEF said in its year-end results, increased to 225.7mn gallons, up from 198.2mn gallons in 2022.
CEF is also pushing into the production of RNG, and
in February began operations at its latest RNG production facility, on a dairy farm in South Dakota.
The $34mn facility, on the 5,000-head Tri-Cross Dairy farm in Viborg, is forecast to produce 1mn gallons per year of negative carbon-intensity RNG. Construction was completed in December 2023 and injection of pipelinequality RNG began shortly after. CEF is in the process of filing the necessary applications to generate federal and state environmental credits.
A week later, CEF announced it had launched a $42mn RNG project on a dairy farm in Iowa, which is expected to produce 1.7mn gallons per year of low carbon-intensity RNG for injection into the national gas distribution grid. Three anaerobic digesters on the farm will process about 240,000 gallons per day of manure produced by the farm’s 8,000-cow herd.
“We anticipate 2024 to be a pivotal year in the demand for RNG fuel in the transportation market with the introduction of Cummins’ X15N natural gas engine for heavy-duty trucks,” says Clay Corbus, CEF’s Senior Vice President for Renewables. “Clean Energy’s fueling infrastructure is expanding to meet that demand and we’ll need a constant source of additional low-carbon RNG to supply those stations.”
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BioLNG production and use in Europe is growing, offering a large-scale, sustainable alternative to traditional fuels in the hardest-to-abate areas of the economy. However, investment levels remain short of that required to reach EU targets, and policy does not always reflect the fuel’s true benefits.
ROSS MCCRACKENDespite the huge push for electrification backed by renewable power generation, a substantial proportion of Europe’s future energy supply will still need to be met in gas or liquid form. For key parts of the economy – long haul road, maritime and air transport and hard-to-abate industrial processes – electrification remains neither economically nor technically viable.
The production of bioLNG, also known as Liquified Biogas (LBG), offers a near complete carbon cycle without the direct and indirect land use change issues that bedevil liquid biofuels, as a result achieving both genuine sustainability and energy security.
Moreover, this is no futuristic technology. LBG is routinely produced and used today. Significantly, it does not carry the massive infrastructure requirements of other low carbon fuels, such as ammonia, methanol or hydrogen, in terms of new transportation and fuelling infrastructure. Nor does it need significant end-use technology advancements. It is a direct drop-in fuel, chemically the same as the natural gas and conventional LNG with which Europe is already familiar and heavily dependent upon.
LBG is the easily transportable end-product of liquifying
bio or synthetic methane. Biomethane is produced primarily from the anaerobic digestion of organic materials, such as organic waste, manure, crop residues and sewage sludge. This produces biogas, which is upgraded by the removal of CO2 and other impurities to create biomethane.
There is also growing interest in synthetic methane, which can be produced, for example, via the gasification of lignocellulosic biomass (woody matter) and methanation, or via electrolysis using renewable power to produce hydrogen, which then also undergoes methanation.
There is, in fact, a unique symbiosis between the production of bio and synthetic methane.
Upgrading biogas to biomethane involves the removal of CO2, which is required for methanation. Facilities could be co-located to capture the natural methane emissions from organic materials and wastes, reusing the biogenic CO2 as feedstock for a synthetic methane plant.
The reuse of biogenic CO2 is particularly attractive in creating closed carbon loops, and LBG technology specialists like the Netherland’s Nordsol are keen to promote its potential as a useful feedstock. Bio-CO2 produced from its plant in Amsterdam is already being used today in greenhouses, displacing fossil CO2 and
“Although there is more than enough sustainable biowaste to make biomethane, the quantity is not infinite”
contributing to the growth of vegetables, which ultimately, in the form of biowaste, provide some of the feedstock for the company’s energy efficient LBG plants.
European Biogas Association (EBA) Policy Manager Anna Venturini also highlights the value of biogenic CO2, arguing that the creation of a market for sustainable carbon would reward the capture, use and storage of bio-CO2 from the biogas sector. She notes that biogenic CO2 can be used in organic fertilisers as well as renewable energy carriers and as an industrial gas.
“Although there is more than enough sustainable biowaste to make biomethane, the quantity is not infinite” according to Nordsol’s Remco Krul. This is why LBG producers and consumers argue that biomethane should be consumed in the end uses where it has the biggest environmental and social impact.
The European Commission backs this approach. In February, the Commission published its proposed emissions targets for 2040, reiterating that the primary destination for sustainable biofuels should be the hardto-abate areas of markets for which electrification is not currently viable. In effect, this means transport and, by extension, that LBG displaces primarily oil products rather than natural gas.
In its earlier REPowerEU plan the European Commission set a production target of 35 bcm of biomethane by 2030, sending an important signal to the sector. Funds have flowed in, and more resources are being recognised as viable.
In 2022, a study conducted by Gas for Climate, Biomethane production potentials in the EU, estimated that 41 bcm of biomethane could be sustainably produced in Europe by 2030, rising to 151 bcm by 2050. Of the resources identified by the study, 38 bcm in 2030 and 91 bcm in 2050 come from anaerobic digestion, with sequential cropping the dominant source of growth post2030. Thermal gasification potential was put at 3 bcm in 2030, rising to 60 bcm in 2050.
According to the study, even more biomethane potential could be unlocked through the use of other
feedstocks such as seaweed or biomass produced on marginal or contaminated land.
According to the EBA, at the end of 2022, there were 27 active LBG plants in Europe, a number estimated to have grown to 55 in 2023.
The EBA’s tracking suggests Europe will have more than 109 LBG plants operating by the end of 2025, at which point combined capacity will reach 15.4 TWh per year, the equivalent of about 1.6 bcm of natural gas based on gross calorific value of 35.17 MJ per cubic metre.
According to the EBA, of the plants built since 2017, most use agricultural residues, organic municipal solid waste and sewage sludge, while almost none run on monocrops. There is also a trend towards larger facilities.
On the demand side, Europe already has a large network of LNG filling stations where LBG can be provided directly. In 2022, the EU had 1,898 bio-CNG (Compressed Natural Gas) and 123 LNG filling stations. By last year, the network had ballooned to over 4,000 CNG and 650 LNG facilities.
In the maritime sector – even though the shipping industry appears to see-saw in its enthusiasm for different low carbon fuels – there are already sufficient ships in operation in European waters to create a viable market for LBG.
According to classification society DNV, there are 493 LNG-fuelled ships currently in operation worldwide, with a further 523 on order. These include some of the largest container ships on the water, such as the fleet operated by CMA CGA, which completed the first LBG bunkering trial in Rotterdam in December 2021, using a 10% LBG blend.
While only 0.51% of the global shipping fleet currently uses LNG, the order book for new vessels shows a share of 9.43%. In other words, of new ships under construction, nearly one in ten will be able to use LBG. Almost half of the world’s LNG bunker vessels are in Europe, as is the majority of the global LNG-fuelled shipping fleet.
LBG is generally more expensive than conventional LNG, but its price is much more stable and not always higher
The ability to piggy-back off the expansion of LNG infrastructure is one of LBG’s most significant attributes in terms of rapid scalability and economic viability.
According to Krul, there are three routes to market at present: relabelling conventional LNG as LBG through the surrender of carbon certificates, known as ‘book and claim’; mass balancing; and the direct conversion of biogas to LBG at dedicated plants.
The first pathway requires rigorous certification to ensure the offsets are genuinely sustainable. The second route leverages the economic benefits of large-scale facilities, but also requires certification as it requires the balancing of gas used for bioLNG to equal biomethane production, even if that biomethane does not always make its way to the mass balancing facility. The mass balancing approach has run into major problems in other industries, for example, cotton production.
The third route, in contrast, offers simple verification and a localised waste-to-energy system that is both scalable and affordable, reflecting the decentralised nature of biomethane production.
As the growth in fuelling infrastructure and production facilities indicates, the sector is attracting investment. However, current biomethane production is estimated at about 3.4 bcm in the EU and 4.2 bcm in Europe as a whole, far short of the EU’s 2030 target. Gas for Climate’s December 2023 report, Market state and trends in renewable and low-carbon gases in Europe, says that, at present, planned investment in the biogas sector covers only 20% of future needs.
Policies exist which support LBG production, but they are not uniform across Europe, and there are also policies which mitigate against the fuel’s wider adoption.
As Magnus Folkelid, Global Sales Manager Biogas at Wärtsilä Gas Solutions, says, German regulation mandates that transport fuel providers supply a certain quota of green molecules, a rule backed by heavy fines
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In the context of total global energy production, Trinidad and Tobago is a fairly small hydrocarbon producer. Its reserve size notwithstanding, the Caribbean nation has built a reputation as an energy powerhouse, particularly in natural gas-based industries. The country has repeatedly ranked among the top ten LNG exporters in the world and is a global leader in ammonia and methanol production.
One of the main reasons for its disproportionate impact in energy is innovation. Throughout its history, the country’s energy professionals have had to find innovative ways to build a globally competitive energy sector - from the drilling techniques used to extract oil and gas from its complex offshore geology to the pioneering gas-pricing formula introduced by The National Gas Company of Trinidad and Tobago Limited (NGC).
Today, with the global energy sector transitioning toward cleaner fuels and technologies, and the carbon intensity of energy under the microscope, the link between innovation and competitiveness is even more pronounced. NGC - today a global energy player – is evolving its business model and operations, to sustain and expand its presence in now greening markets.
Under the umbrella of its expansive Green Agenda - and with the support of subsidiaries within the wider NGC Group of Companies - NGC is pursuing a number of projects and investments aimed at reducing the carbon footprint of its business and value chain. Among these is a methane mitigation campaign, designed to address fugitive methane emissions from its infrastructure and facilities.
Since 2021, NGC has been utilising satellite technology in combination with infrared cameras to survey its network and above-ground installations for leaks and vulnerabilities that could release methane into the
atmosphere. These innovations in asset monitoring have allowed the company to detect and repair more leaks, reducing its methane output in the process.
In 2023, another innovation was introduced in the form of a mobile application to collect and centralise live data around NGC’s network. Developed internally, the Operational Excellence App allows NGC’s operations and management teams to track natural gas network activity in real time, leading to increased situational awareness around network status and speedier response to network disruptions, such as gas leaks. The app harvests field data from multiple sources and presents it as a dashboard so that real-time, 24-hour data is available on NGC’s gas value chain, gas supply and demand, curtailment, network health, gas-to-power efficiency and downtime.
NGC’s innovations aimed at greening its operations have two important outcomes. Firstly, in the context of a tight domestic gas supply market, every molecule of gas counts. NGC’s current arsenal of tools helps the company ensure the integrity of the pipeline distribution network and keep as many molecules in the line as possible. This in turn contributes to a more secure supply stream for downstream use, and supports the sustainability of the sector. Secondly, these tools are allowing NGC to build a more carbon-conscious business, which is a critical success factor for energy companies in today’s market.
In this regard, innovation will continue to keep NGCand by extension Trinidad and Tobago - at the forefront of energy.
automation are helping the LNG industry to reduce risk and boost efficiency, among other benefits, but there are still further challenges to overcomeANNA KACHKOVA
The LNG industry continues to expand, as new capacity is built to meet growing global gas demand and to help bolster energy security. Given the size and complexity of most LNG facilities, operators are on the lookout for ways to improve efficiency, reduce risk and continue to reduce greenhouse gas (GHG) emissions. And digitalisation and automation are increasingly seen as significant ways of achieving this.
Such technologies are not new, and indeed the LNG industry – and the oil and gas industry more broadly –has increasingly been adopting them over the course of several years. Nonetheless, momentum continues to pick up. For example, Arif Mustafa, Vice President, US Gulf Coast Region for global technology and software company Emerson, tells Global Voice of Gas (GVG) that automation technologies enable a broad range of capabilities, including the safe transfer of liquefied gas, safe operations, custody transfer, corrosion prevention, plant uptime, leak prevention and energy and emissions management.
“As companies work on new and current LNG projects, automation plays a crucial role to ensure projects are completed on time and on budget,” Mustafa says. “Once plants are up and running, this same automation helps ensure they operate reliably, safely and efficiently,” he
continues. “Across the LNG supply chain, automation technology serves as the central nervous system of the plant, using intelligent instruments, software and AI to improve plant performance, avoid downtime and manage risk during constantly changing operational conditions.”
Safety enhancement is a significant contributor in the push for more digitalisation. High-profile outages at various liquefaction terminals in recent years illustrated how long it can take to bring an LNG facility back online after something goes wrong.
In recent years, the oil and gas industry has focused more on efficiency gains, and LNG is no exception.
“Digitalisation has been one of the main drivers for efficiency improvements in the LNG industry,” Nathan Tungseth, ABB Energy Industries’ Senior Vice president of LNG and Regasification, tells GVG. He cites NextDecade’s Rio Grande LNG (RGLNG), which is currently under construction, with ABB contracted to provide automation, electrical and digital services for Phase 1.
“Automation control systems, digital electrification components and industrial drives will enable RGLNG Phase 1 to optimise production assets, increase energy efficiency and operate more sustainably,” says Tungseth.
“In the LNG industry, we’re seeing a strong adoption of digital solutions, largely around digital twins,” he
“As more LNG plants move to electrification, digital solutions with Advanced Process Control (APC) are being implemented to optimise and reduce energy usage.
continues. “As more LNG plants move to electrification, digital solutions with Advanced Process Control (APC) are being implemented to optimise and reduce energy usage.”
Indeed, as the energy transition unfolds, LNG developers are coming under increasing pressure to demonstrate what they are doing to minimise their environmental impact. Electrification is one of the options developers can take to reduce emissions. On top of emission reduction efforts, monitoring of emissions is also necessary. And this too is increasingly a driver behind the increased uptake of digitalisation and automation.
There are various ways in which these technologies can be used for emissions monitoring.
“Emerson’s advanced process control in systems like DeltaV and Ovation, energy analytics and software modelling, combined with intelligent sensors and valves, can optimise combustion processes for greater energy efficiency and lower emissions,” Mustafa says.
Tungseth, for his part, notes that ABB has a suite of emissions monitoring technologies.
“With integrated leak detection solutions that utilise a lightweight UAV/drone, we are able to detect, map and quantify natural gas leak emissions while flying,” he says.
There are still challenges that the LNG industry needs to overcome as it adopts more digital technologies. These include the sheer complexity of the projects involved.
“Because of its complexity, LNG operations demand integration of all technologies, single vendor interoperability, and deep domain expertise,” says Mustafa. “These are massive projects and having an automation partner that understands the complexity helps
minimise costs and project risk.”
Tungseth also points to the complexity of the projects involved and has some suggestions for how this can be approached.
“LNG plants are multi-billion-dollar facilities that take years to develop,” he says. “Often, companies are looking for proven solutions to reduce risk, which means that more collaboration is required to scale innovation in this industry. We can also learn from technology deployment in other industries that are equally complex to support adoption.”
Judith Ponniah, the director of industry marketing for Emerson’s AspenTech business, points to the value of digital twins in helping to overcome some of the major challenges faced by LNG operators.
“LNG operators are under pressure to provide for a rapidly growing market and tasked with meeting lofty production and sustainability requirements,” Ponniah tells GVG. “To win in this challenging environment – while also achieving sustainability goals – both operators and EPC firms will need to take advantage of digital twin technology that optimises across the full lifecycle of the LNG facility.”
“Digital twins are a particularly valuable tool for enabling improved process design, greater manufacturing insight and better operational integrity. Digital twin technology is valuable for both LNG producers, helping them realistically model different design options and process flows to identify the most economical, profitable, and efficient solutions as they create the next generation of plants,” Ponniah continues. “From making investment decisions to analysing design options to startup and commissioning, the digital twin is an invaluable tool
“Digital solutions enable increased safety, efficiency, and quality through design standardisation and operational insights; however, it does take training and upfront implementation costs for optimised execution,”
for LNG businesses that want to achieve financial and environmental goals today while also planning for success tomorrow.”
Over time, another challenge arises, as monitoring has been generating massive amounts of data for decades while the technologies involved have continued to evolve.
According to Mustafa, these data do not get fully used through digital tools such as cloud analytics and machine learning.
“The underlying issue is that traditional automation architectures date back to the 1980s and are very rigid in terms of information management,” Mustafa says. “As a consequence, each operating discipline – such as production, maintenance, safety, logistics and others – all have separate technology stacks, data models and software systems. The recent aspiration of ‘digital transformation’ is proving very challenging because this siloed data is not easy to integrate, leaving companies stymied to achieve the transformative operating insights they seek from new technology.”
However, progress is being made to address this challenge, Mustafa adds.
“A new automation architecture is emerging that is both more open and at the same time, more secure,” he says. “It takes the rigid hierarchical layers of outdated
automation architectures known in the industry as the Purdue Model, and reinvents it with an Intelligent Field, a completely new Edge environment and a new Cloud environment, tightly integrated to liberate data and unleash the power of software.”
Looking ahead, there are further gains to be made using digital technologies. Ponniah sees experienced providers of such digital technologies continuing to help operators hit ever more ambitious targets.
“Digital solutions enable increased safety, efficiency, and quality through design standardisation and operational insights; however, it does take training and upfront implementation costs for optimised execution,” she says. “Many of these common barriers are overcome with the help of experienced technology partners with proven track records. The industry will invest with those who can affect the bottom line though accelerating construction schedules, reducing capex and opex, improving production, and meeting sustainability goals,”
Ponniah continues. “Forward-looking companies have already begun the process of implementing cutting-edge digital technology, investing to build faster while also using the latest innovative solutions to achieve new targets in efficiency, production and sustainability.”
The latest UN climate conference in Dubai made progress on several fronts, but there is still much to be done to have any hope of achieving the goals of the Paris Agreement.
CHARLES ELLINASCOP28, the UN climate conference held in Dubai in December 2023, attended by more than 190 governments, made significant progress in the fight to tackle climate change and global warming. Its key successes were:
• In a historic first, COP28 committed the world to “transition away from fossil-fuels in energy systems, in a just, orderly and equitable manner, accelerating action in this critical decade, so as to achieve net zero by 2050 in keeping with the science”
• Agreement to triple renewables and double energy efficiency by 2030
• Agreement to operationalize funding to address ‘loss and damage’
• Commitment by over 50 international and national oil companies to phase-out methane emissions and eliminate routine flaring by 2030, and align their operations with net-zero by or before 2050, under the ‘Oil and Gas Decarbonization Charter.’
The final deal exceeded expectations. But, as Sultan Al Jaber, COP28 president, said “An agreement is only as good as its implementation.” The world must now demonstrate tangible actions before it gathers again at COP29 in November in Baku.
Simon Stiell, executive secretary of UNFCC, outlined his vision for COP29 in Baku on February 2. He said
that the two key goals to achieve at COP29 are to make bold decisions on emission reduction commitments and massive scaling in climate finance.
A major success at COP28 was the pledge to transition away from fossil-fuels. But, rather prematurely, some called it “the beginning of the end” of the fossil-fuel era.
Clearly, it does not spell the end of fossil-fuels. It is a first step in that direction, but it will take a long-time. The pledge is not time-bound and the wording would allow the use of oil and gas even beyond 2050. It even strengthened the case for natural gas as a “transitional fuel” balancing intermittent renewables.
It is not only petrostates that advocated for this, but also China and India and many developing countries, especially African.
But despite its successes, COP28 made little progress on how to fund the energy transition in developing countries, that argued they cannot agree to bigger decarbonization without adequate finance. Despite the success of operationalizing the ‘Loss and Damage Fund’, funding pledges made at the summit were far below what is needed. Undoubtedly the pledges to triple renewable energy capacity to over 11,000 GW and double energy efficiency gains to 4% by 2030 can make a difference.
They are challenging, but achievable. And so is the ‘Oil and Gas Decarbonization Charter.’ If implemented fully, these could lead to serious reductions in the use of coal. With help from future COPs, these pledges can limit global warming closer to 2 °C.
Climate activists were critical of COP28 agreements for including loopholes, weak language, ambiguities, deferred decisions, and the low levels of funding pledges.
I asked Dieter Helm, professor of economic policy at Oxford University, well-known for his insightful views on sustainable economy, for his take on the COP process. He was forthright: “28 COPs have not made much difference: fossil-fuels are still around 80% of the global energy supplies. Announcing yet more targets and ambitions and signing declarations is what COPs do. What they do not do is lead to credible and rapid implementation in the countries where the greatest emissions growth is likely to take place.” He added “COPs so far have largely ignored the other half of the climate change problem – carbon sequestration.”
The reality of COP outcomes is not lack of ambition but lack of implementation, all the way from Kyoto to COP28. Pledges are made, only to be ignored, to the extent that the 1.5 °C goal now looks out of reach.
As Stiell said in Baku, “an Olympian task lies ahead, given the current pace of energy transition by companies and governments.” He added “the actions we take in the next two years will shape how much climate-driven destruction we can avoid over the next two decades, and far beyond.”
What he did not say – and most environmentalists prefer to ignore – is that energy security and affordability also matter. As euro-elections public opinion polls show these are also important issues that cannot be ignored. What is needed is a balanced approach to energy transition.
The achievements of COPs so far, especially COP28, will not mean much unless they are fully implemented through tangible actions. Key to that is to put in place the funding levels and arrangements required to deliver them. Energy transition, climate adaptation, loss and damage, and disaster relief in general, require huge funding and investments -running into trillions of dollars annually – to turn ambition into action.
Implementation and funding should be the key goals of COP29. As will be setting-up a ‘new collective quantified goal’ (NCQG) to replace the $100bn climate finance commitment by developed to developing countries, that so far has not lived up to expectations.
Simon Stiell said COP29 will be an “enabling COP,”
focused on drastically scaling-up climate finance –“finance is the make-or-break factor in the world’s climate fight.”
Multilateral development banks (MDBs) and the private sector need to collectively raise $2.4 trillion annually for climate funding. But in order to deliver this, MDBs need to be reformed to provide more concessional funding and grants to developing countries, rather than debt-finance. Involvement of the private sector would require getting access to public capital markets and making sure public funds are deployable for sustainable projects.
In addition, countries will need to update and improve targets and actions in their next round of NDCs, due in 2025, that turn COP decisions into reality.
Azerbaijan’s vision for COP29 is: technology transfer, water and peace. It is also sending the message that the success of COP28 shows it makes sense to have “fossilfuel exporters inside the COP tent.”
I asked Professor Helm what does he think should be the key goal at COP29? Simon Stiell says it should make bold decisions on emission reduction commitments. “What are your views especially given what you said in the past about targetry?”
His response was “It is easy to announce targets, with the assumption that either it will all be cheap, or that consumers and industry will pay whatever it takes to achieve the targets. The backlash on net-zero in Europe is entirely predictable: the top-down targets take no account of the ability to pay and a bottom-up assessment looks at how much money is actually available, and then worksout what are the most cost-effective things to do now.” What is needed is a combination of the two.
I also asked him about his views on Stiell’s second goal that what is needed is massive scaling in climate finance. He said “On finance, the key issue is the funding streams which pay for interest on the finance and repay the capital provided. It is funding not finance that matters.”
His view is that COPs have achieved little so far. And on that basis, he believes it would be foolish to expect that COP29 will make much difference. He said “If the solution to climate change lies with COPs, then the outlook would be pretty bleak. Better to start bottom-up.”
Prof Helm’s views can be found in his most recent book “Legacy: How to build the sustainable economy“, published in October 2023.
Undoubtedly, though, oil and gas will again be the focus of attention at Baku. Already the choice of Azerbaijan is being attacked as ‘controversial’ due to the country’s dependence on oil and gas production, much as UAE was on the road to COP28.
The International Gas Union recently sat down with Osam Iyahen, Senior Director at the Africa Finance Corporation, to discuss the work AFC is doing to promote energy developments across Africa.
OSAM IYAHEN, SENIOR DIRECTOR AT THE AFRICA FINANCE CORPORATION
Tell us a little about the AFC, its mission, and the role it plays in Africa’s energy system evolution?
AFC was established in 2007 to be the catalyst for private sector-led infrastructure investment across Africa.
AFC’s approach combines specialist industry expertise with a focus on financial and technical advisory, project structuring, project development, and risk capital to address Africa’s infrastructure development needs and drive sustainable economic growth.
Seventeen years on, AFC has developed a track record as the partner of choice in Africa for investing and delivering on instrumental, high-quality infrastructure assets that provide essential services in the core infrastructure sectors of power, natural resources, heavy industry, transport, and technology & telecommunications. AFC has 43 member countries and has invested US$13 billion across Africa since inception.
AFC’s mission is to be the leading infrastructure solutions provider across all of Africa. With our partners, we are the largest investor in renewable energy on the continent through our joint acquisition of Lekela, with wind farms in Egypt, Senegal and South Africa, with combined gross capacity of 1.27 GW that powers
>1 million homes and offsets 2.7 MTPA of CO2. Other transformational renewable energy projects AFC has invested in include:
• AFC holds a 51% majority stake in Red Sea Power (RSP), a limited liability company responsible for managing the design, construction and operation of the first ever wind farm in Djibouti, advancing its stated ambition to become the first nation in Africa to rely entirely on renewable sources for electricity by 2035
• AFC holds 50% share in the Cabeolica wind farm in Cape Verde, providing 20% of the energy required in the country, whilst drastically reducing the country’s consumption and exports of oil fuels & diesel These projects showcase AFC’s catalytic role in addressing energy poverty in Africa whilst contributing to the continent’s pragmatic transition to net zero.
Energy security and accessibility is critical for rapid industrialization and economic growth in Africa.
Unfortunately, Africa lags behind the rest of the world in terms of energy supply, with over 50% of the population without power. Africa also has the youngest population with around 40% of the population aged 15 years and younger. The lack of available and reliable energy supply has largely stymied the growth of the continent’s youth and productivity where demand has been increasing at the highest rate amongst all continents (~3% p.a.).
Oil and natural gas exploitation will keep dominating Africa’s energy mix. However, the continent has the largest untapped hydropower potential in the world with only 11% of this potential being utilized. It is the main source of renewable energy in Africa with 37+ GW of installed capacity. There is also significant potential for the other renewables -solar, bioenergy, wind, geothermal energy- to contribute to a more balanced energy mix on the continent.
Africa has the highest combined solar and wind potential of any region in the world. It just takes innovative investment structures to realise the potential.
• To achieve net zero by 2050, Africa would need an estimated US$2.8 trillion of domestic and global capital invested. This funding challenge is coupled with perception of investment risk on the continent, even though it has been acknowledged that project finance defaults on the continent are the lowest globally.
• Another bottleneck is the interface with largely financially distressed state utilities, unable to afford the capital investment and system strengthening required.
• The impact of the intermittences of renewable systems can also not be ignored. Solar energy is challenged by the rainy season and the sun cycles, whereas wind energy is more easily accessible at night. For a continent grappling with the urgency of industrialisation requiring reliable baseload power supply, energy transition efforts with the intermittent renewable systems are not a sufficient solution.
African countries produced around 6% of the world’s natural gas in 2022, a proportion that has doubled since 2000 and tripled since the 1990s. Gas production in Africa has increased by an average of 2.5% per year between 2011 and 2021, above the world average of 2.2%.
The main producing countries are Algeria, Egypt and Nigeria, together accounting for over 80% of the
Source: Africa’s energy outlook, Deloitte 2023 studycontinent’s production in 2022. Up to 2026, a 6% growth is expected from Africa’s gas production. Domestic gas reserves in Africa are shown on the picture below.
The gas supply shock of 2022 (drop in Russia’s piped gas deliveries to the Europe Union) reinforced the structural trends that are driving the longerterm prospects for global gas demand. Overall, gas consumption across the mature markets of Asia Pacific, Europe and North America peaked in 2021 and is set to decline over the medium term as a result of the rapid deployment of renewables and improved energy efficiency standards. On the other side, demand growth is almost entirely concentrated in fast- growing Asian markets and in gas-rich countries in Africa & the Middle East.
Africa has the potential to become an extremely important source of global supply. 36% of the natural gas produced in 2022 was exported, of which 61% was in the form of LNG. The main destinations are Europe (60% of 2022 exported volumes) and Asia. The use of domestic natural gas production makes sense for Africa as it offers a considerable advantage of lower energy costs compared with fossil fuel options.
Although African leaders embrace the clean energy transition and the region has enormous renewable energy resources, there is a need to develop the continent’s fossil fuel resources to meet development needs and improve access to energy. Tangible economic gains for society,
such as job creation and skills development are also expected.
To what extent do you feel that policy changes by some financial institutions in recent years may have had negative implications for investment in African energy?
Tighter lending criteria driven by net zero pledges has resulted in a decline in financing for fossil fuel in Africa. Many African economies however rely heavily on fossil fuel revenue for their national budgets. As the leading infrastructure solutions in Africa, AFC’s mandate is to reduce infrastructure deficit on the continent by deploying capital into infrastructure projects in key sectors of the economy on the continent, including Oil & Gas. Our view as AFC is that while renewable sources are the ultimate goal, Africa must also exploit its abundant reserves of natural gas as an essential transitional source of energy to support industrialisation – a position backed by the European Commission’s decision to classify natural gas as a form of green energy and a vital transition fuel in the path towards decarbonisation. According to the World Economic Forum, if all of Sub-Saharan Africa tripled its electricity consumption overnight using only natural gas, the additional CO2 would be equivalent to just 1% of global emissions.
African countries produced around 6% of the world’s natural gas in 2022, a proportion that has doubled since 2000 and tripled since the 1990s.
In the lead up to COP27, AFC launched a climate white paper, that received wide endorsement from several institutions and African leaders. The white paper was aimed at building a consensus of African leaders around a common narrative of Africa for engagement with the world at COP27. Our paper sets out ways in which Africa can balance the need for emissions reduction with critical development imperatives by focusing on three significant areas of change- localizing manufacturing, rebuilding infrastructure for climate resilience and leveraging financial innovation to get access to essential climate funds.
Let’s turn to your core business – financethe significant need for investment in new low-carbon technologies, renewables, as well as continued spending on natural gas supply is likely to put significant pressure on the global capital pool for energy infrastructure. In your view, how should the world see it through this challenge and where does Africa fit in regarding this issue?
Even though Africa accounts for almost 20% of the world’s population and has ample resources, it only accounts for 2% of the global clean energy spending. Africa must be given time to transition and allowed to use its natural gas as a transition fuel. To meet the local development ambitions and energy access, investments need to more than double by 2030 but urgent action is needed to bring down financing costs and boost access to capital.
According to the Financing Clean Energy in Africa report released by the iea and the AfDB, the cost of capital for clean energy projects on the continent is at least 2x - 3x higher than in advanced economies. Lowering it and supporting the creation of investable projects will require scaling up the range of existing instruments.
Leveraging financial input from governments and development partners, AFC has the tools to de-risk
climate investments and offer strong returns to incentivize the mobilization of funding from institutional investors such as pension funds, sovereign wealth funds and insurance companies. Such tried-and- tested financial innovations include public private partnerships, blended finance, B-loans, first-loss equity, insurance and guarantees.
Let’s talk specifically about the recent contributions that AFC has made to supporting the development of natural gas and low-carbon energy in Africa. Take us through what have been/will be the social, environmental, and economic benefits of these projects?
The solution for Africa is that we must ensure that we have clear strategies to improve our energy access, and our energy access must be a mix of energy sources. Renewables are already one of the main sources of electricity for almost half of Africa, and carry great potential for expansion, but alone will be insufficient to address the continent’s energy gap. Gas, an abundant resource in Africa and the least polluting fossil fuel, must be included to bridge the energy access gap on the continent. Africa needs baseload power, and this can best be achieved through gas. AFC has been involved in several gas projects on the continent and is continually seeking to work with credible partners in the sector.
The Corporation made an equity investment of $20 million in Seven Energy (now Savannah), an indigenous oil and gas exploration and production firm focused on the monetization of Nigeria’s discovered but undeveloped gas reserves. The funds were part of a $200 million equity and debt raise for the development of reserves in an oil and gas rich producing region of Nigeria. This unique transaction was geared towards the domestic use of gas, including power generation and supply to captive industrial clusters.
PETRONAS is innovating across the LNG value chain, including through its pioneering use of FLNGs, to unlock sources of lower-carbon energy in a sustainable manner, Shamsairi Ibrahim, the company’s vice president of LNG marketing & trading, tells Global Voice of Gas.
JOSEPH MURPHYHow is PETRONAS leveraging technology and innovation as part of your strategic positioning for the global LNG market, especially with projects in Malaysia and Canada, considering the increasing demand and focus on cleaner energy alternatives?
As a 40-year veteran in the industry, our steadfast commitment in being a progressive energy solutions provider means embracing technology and innovation throughout our LNG value chain, ensuring sustainability across our operations.
Our commitment to become a more prudent producer dates back to 2012. We further strengthened our commitment in 2020, as the first energy company to declare NZCE by 2050. Within our operations, we have minimised venting, flaring, and addressed leakages, as
SHAMSAIRI IBRAHIM, VICE PRESIDENT OF LNG MARKETING & TRADING, PETRONAS
well as transitioned to gas firing during berthing, reflecting our unwavering pledge to safeguard the environment.
With this in mind, we’ve pioneered solutions like our floating LNG (FLNG) facilities, made to not only unlock remote gas reserves, but also introduce a more costeffective alternative to conventional solutions.
Simultaneously, our latest project, LNG Canada, with operations expected to commence by middle of 2025, will have the lowest carbon intensity of any LNG export facility in the world of similar size, serving as a valuable, lower carbon energy source for the Far East Asian region.
In Malaysia, we are collaborating with JX Nippon Oil & Gas Exploration Corp. and JOGMEC to employ carbon capture and storage (CCS) technology for the development of high CO2 gas fields, including the Bujang, Inas, Guling, Sepat and Tujoh (BIGST) fields located off Kerteh, Terengganu.
The development of these new fields reflects our efforts to strengthen customers’ confidence in us, by growing our global portfolio to ensure a continuous and reliable supply of lower-carbon energy. Importantly, it highlights our commitment to innovation and decarbonisation whereby we are unlocking these new gas reserves with sustainability at the top of the mind.
Additionally, we’re promoting the adoption of LNG as a cleaner marine fuel through innovative solutions such as LNG bunkering vessels with refueling services across Southeast Asia. More importantly, the LNG bunkering solution supports the implementation of International Maritime Organisation 2020 regulations to limit the carbon impact from the marine industry.
We are also currently exploring multiple pathways to decarbonise our operations and lower our carbon footprint – from electrification of our LNG plants to establishing new entities to provide clean energy solutions such as renewables, hydrogen, and green mobility.
On top of our own innovations, we are also focused on elevating our buyer-seller relationship where we actively collaborate with partners to decarbonise and make the whole natural gas value chain cleaner. Examples include:
• Collaborating with key industry players, such as JERA, to develop ammonia and hydrogen.
• Conducting a joint technical and commercial feasibility study with ENEOS Corporation (ENEOS) to produce low carbon hydrogen from PETRONAS’ existing facilities, production of green hydrogen from a new hydropowered electrolyser facility, and hydrogen conversion into methylcyclohexane (MCH).
• Combining efforts with Japan Petroleum Exploration Co. Ltd. (JAPEX) to evaluate optimal capture, storage and transportation methods, as well as estimation of emissions, capture volumes and monitoring methods of CO2 stored underground.
• Forming a global alliance and collaboration for LNG bunkering at four locations in Japan. Offshore wind and LNG bunkering alliances to develop solutions in hydrogen, ammonia and CCS.
While gas prices have experienced a significant decline since the peak of the global energy crisis, the market anticipates achieving a more stable balance in the mid-decade with the introduction of new LNG supply. However, how can we ensure proactive measures are taken by policymakers, investors, and the industry to prevent potential complacency and avert future crises?
As a progressive and responsible LNG player, PETRONAS has consistently played our role in safeguarding the
stability of the industry through exploration of new gas reserves and new LNG projects. We’ve also been consistent in advocating for long-term contracts as a means of shielding producers and consumers from market volatility.
Events such as the COVID-19 pandemic and the Russia-Ukraine conflict has further emphasised the need for market stability and long-term contracts.
We firmly believe that establishing long-term contracts with stable long-term pricing mechanisms will not only be able to address the pricing volatility faced by the industry but also establish long-term and sustainable gas demand from buyers. This is also critical for producers who are developing LNG exporting projects which require huge investments and a long gestation period.
As gas is anticipated to play a bigger role as the energy transition progresses, collaboration within the industry must also continue. Collaboration here not just involves producers and consumers, but also the policymakers to ensure a successful energy transition that does not forsake on energy security.
Recognising the equal responsibilities of all parties throughout the value chain, collaboration is key to realising a stable, reliable, and harmonious market. Additionally, the energy transition must address the unique challenges faced by different countries, including balancing affordability, security, and sustainability while meeting growing energy demand. Therefore, at PETRONAS, we believe in taking accountability and playing our part to ensure a just transition that allows progress and sustainable development for all. We must move forward, taking practical steps towards a lowcarbon future together.
The natural gas industry needs to innovate – technologically, commercially, and otherwise – to ensure that gas is as affordable, secure, and sustainable as possible. Take us through how Petronas is innovating towards this goal?
At the heart of our operations, we are driven by our customer-centric approach – meeting our customers’ differing needs by providing sustainable, easy to access and flexible energy solutions. To bring this commitment to life, we continuously innovate to improve the way we produce and serve our customers.
Technologically, we’ve pioneered solutions to revolutionise LNG production on our FLNGs. The design of our FLNGs are more efficient because it eliminates the need for a full-fledged cooling system, simplifying the production process and increasing operational efficiency.
We’ve broadened our range of energy solutions and services, ensuring LNG is readily available and accessible
As a pioneer in FLNG, we envision a future where FLNG facilities will play a game-changing role in transforming the energy landscape.
to customers of all demand capacities:
• The Virtual Pipeline System (VPS) solution was launched in September 2020, delivering LNG to offgrid customers throughout Peninsular Malaysia. This initiative enables various industries and sectors to switch to a cleaner energy source, even in remote locations.
• The LNG Bunkering Solution was introduced in November 2020, and supports the use of LNG as a cleaner marine fuel. Southeast Asia’s first dedicated LNG bunkering vessel, MV Avenir Advantage, spearheads our efforts to comply with International Maritime Organisation 2020 regulations.
Commercially, PETRONAS is at the forefront of innovative contract structures, providing flexibility and adaptability in response to changing market dynamics. Some of the contracting approaches we’ve provided for customers include:
• Flexible Contract Terms: We collaborate with customers to provide contracts with flexible terms that allow for adjustments in delivery schedules, quantities, and pricing based on changing market conditions. This flexibility can help our buyers better manage their energy portfolios and respond to variations in demand.
• Hybrid Contracts: We offer our customers hybrid contracts that combine features of traditional long-term contracts and short-term spot market arrangements.
This approach provides buyers with a mix of fixed and variable pricing, offering more options for managing price volatility while maintaining some level of price stability.
• Indexation and Price Formulas: We offer tailored contracts that use innovative pricing mechanisms, such as indexation to different natural gas indices (JKM, Henry Hub, AECO), or formulas that reflect market conditions. These mechanisms can ensure that the contract’s pricing remains aligned with market realities
• Portfolio Contracts: We offer our buyers access to a portfolio of LNG supply sources, where supply can be sourced from our global portfolio of LNG assets located in Malaysia, Egypt, Australia and soon, Canada. This approach diversifies supply sources and enhances security of supply
There are a great deal of ways for the natural gas chain to be effectively decarbonised. What are the main solutions that PETRONAS is pursuing to decarbonise and future-proof assets?
At PETRONAS, we are deeply committed to minimising the carbon footprint throughout every stage of the LNG value chain – from exploration, production and to transportation and delivery. Our efforts encompass a range of projects and partnerships aimed at ensuring that LNG remains as an environmentally responsible energy
solution for the energy transition.
In fact, in bringing to life our commitment to achieve our ambition of NZCE by 2050, we have embarked on one of the world’s largest CCS projects at the Kasawari gas field in Sarawak. It is expected to come online by 2026 with a target to reduce carbon dioxide volume emitted via flaring by 3.3 MTPA of CO2 equivalent, making it one of the largest offshore CCS projects in the world. Other pathways that we’ve embarked on to reduce the carbon footprint across our integrated LNG value chain include:
• To reduce the carbon footprint of our LNG production process, we are embarking on electrification of our plants and by implementing zero flaring at our assets. Starting in 2024, our PETRONAS LNG Complex (PLC) in Bintulu will gradually be powered by electricity, allowing us to decommission old and inefficient gas turbines.
• While in the shipping of LNG, we have upgraded our LNG vessels with Hull Performance Solution Technology which leads us to an annual reduction of ~18,000 T of CO2 emissions, and we continue to upgrade our existing LNG vessels with newer and energy efficient vessels. We remain steadfast in our pursuit for sustainable LNG production, setting benchmarks and embracing innovations that echo our environmental stewardship in every facet of our LNG value chain. These initiatives showcase our firm commitment to realising a future with
cleaner energy, reflecting our dedication to achieve environmental sustainability and energy security for nations across the globe.
As PETRONAS works on its nearshore FLNG facility in Sabah, could you share updates on what is happening with the project? Also, how is the technology used in the nearshore FLNG facility different from the technology in the existing PFLNG Satu and Dua projects?
PETRONAS reached a final investment decision (FID) in 2022, for a nearshore LNG facility in Sabah.
The nearshore LNG facility is located at Sipitang Oil and Gas Industrial Park (SOGIP), Sabah, is planned for completion by 2027. This project will grow our production portfolio by another 2 MTPA of LNG.
The nearshore LNG facility is designed to be more compact and efficient, with a smaller footprint and reduced costs compared to a full blown FLNG. The nearshore FLNG facility will also feature new technology and innovations that improve efficiency and reduce emissions.
What is PETRONAS’ ambition for floating LNG facilities?
As a pioneer in FLNG, we envision a future where nearshore FLNG facilities will play a game-changing role
At PETRONAS, we are deeply committed to minimising the carbon footprint throughout every stage of the LNG value chain – from exploration, production and to transportation and delivery.
in transforming the energy landscape. Our ambition is to unlock new & existing gas fields using FLNG as a costeffective, flexible, and quick-to-market LNG solution. This technology not only enhances our portfolio but also expands our supply nodes, offering possibilities for venturing into investments in other parts of the world.
FLNGs’ unique advantages position them as the industry’s forward-thinking solution. For example:
• Operationally, the use of FLNG eliminates the need for extensive onshore infrastructure, such as pipelines, processing plants, and storage tanks. For example, we can significantly reduce the length of long subsea pipelines that need to be built from offshore gas fields and the associated capital cost to build the pipeline.
• Additionally, the establishment of FLNG facilities may take significantly less time in comparison to traditional onshore plants; this is a fact at locations where infrastructure & skilled labour are limited.
• The mobility of FLNG allows us to reach remote offshore gas fields that were previously uneconomical. This flexibility translates to more opportunities in exploring stranded and hard-to-reach reserves and increase production. Once the gas field is depleted, FLNG can be redeployed to a new location.
• Last but not least, FLNGs do not require coastal development so we can significantly reduce the environmental impact on the surrounding area. This also minimises requirements for environment and land regulatory permits.
The confluence of FLNG’s operational benefits and the global energy transition, where natural gas plays a pivotal role, positions FLNG as a driving force for industry growth. We see this as an opportunity to foster new collaborations and technologies, facilitating the mobilisation of FLNGs for Malaysia and overseas markets. The combination of these factors reflects the immense potential for further expansion of FLNG technologies.
For the LNG Canada project, can you provide an update and when it is expected to go live by? What are some solutions used at the plant that makes it one of the lowest GHG emissions LNG plants in the world?
PETRONAS is making significant strides at LNG Canada, with the overall project progress currently standing at over 85% completion, based on the LNG Canada 2023 Year End update. This marks a crucial step in expanding and diversifying our global supply portfolio. Our primary focus will be meeting term obligations while also actively participating in the dynamic spot market.
LNG Canada is engineered to be the world’s leading liquefied natural gas facility with lowest carbon intensity of its scale. It’s not merely about production but setting a new standard for safety, reliability, and environmental responsibility. The facility plays a vital role in supporting nations as they transition away from high-emission energy sources like coal.
The low GHG footprint from LNG Canada will be achieved via a combination of factors:
• Raw feedgas from Montney which has a lower CO2 composition.
• Use of widespread electrification of upstream operations such as drilling and processing.
• Use of renewable power from British Columbia’s hydrodriven electrical grid.
This holistic approach positions LNG Canada among the greenest LNG plants globally, designed for an impressive 0.15 T of CO2 equivalent per T of LNG, significantly lower than the global average emissions of 0.26-0.35 T. These initiatives will provide assurance to our customers that they are procuring cleaner LNG produced with lower carbon emission intensity. Together, we are contributing to making the world a better place for future generations.
Global LNG trade hit a record high in 2022 and is forecast to grow by 25% to 500 MTPA by 2028, according to the International Energy Forum. Given seaborne delivery, the industry’s risk exposure to critical maritime chokepoints will increase, demanding a high degree of logistical agility in the face of any disruption risks.
ROSS MCCRACKENFrom mid-November to mid-February, there were almost 50 attacks on commercial shipping in the Red Sea off the Yemen coast, the southern entrance to the Suez Canal and Mediterranean, through which about 7-8% of global LNG trade passes each year. At the time of writing, the Rubymar, a British-registered cargo ship, was drifting abandoned in the area following a missile strike.
Attacks by Houthi rebels, which control large parts of Yemen, have resulted in a major re-routing of ocean traffic around the Horn of Africa, causing freight rates to jump.
The attacks have resulted in reprisals by the US and UK and the launch in February of an EU naval mission to safeguard shipping in the area. The Houthi attacks are in support of Hamas, which is in conflict with Israel in the Gaza Strip. It is an example of the Middle East’s patchwork of loyalties resulting in the widening of an otherwise localised conflict.
It is also a reminder that disruption to one of the world’s key maritime chokepoints increases pressure on other key transits, such as the Panama Canal, which have their own limitations.
The Red Sea provides the southern entrance to the Bab el-Mandeb, Suez Canal route into and out of the Mediterranean. It is one of the world’s busiest transit waterways for LNG Carriers, owing principally to Qatari exports of the fuel to Europe.
The route will become increasingly important to LNG trade as Qatar implements a major increase in its LNG capacity from about 77 MTPA at present to 126 MTPA in the next few years.
Its importance has also grown as a result of the conflict in Ukraine, which has seen more Russian oil head to Asia rather than Europe. The bulk of Russia’s seaborne oil is exported from Black Sea ports via the Bosphorus Strait, another key maritime pinch point, into the Mediterranean for onward transit.
The Red Sea route is no stranger to risk. In 2021, the Ever Given container ship became wedged across the Suez Canal for a week, disrupting global trade flows. Since then, a new channel has been added in the Canal’s southern section, substantially increasing transit capacity.
“The Bab el-Mandeb, Suez Canal route is one of the world’s busiest transit waterways for LNG Carriers, owing principally to Qatari exports of the fuel to Europe.”
Before that, from 2005, Somali piracy plagued the route reaching a crescendo in 2011 when a total of 243 incidents were reported. A World Bank report, The Pirates of Somalia, Ending the Threat, Rebuilding a Nation, published in 2013, estimated that Somali piracy cost the world economy some $18bn.
However, the Suez Canal is not the most problematic of the world’s most important waterways. Unlike the Panama Canal, it does not depend on rainfall to ensure operations, and, unlike the Strait of Hormuz, there are alternative routes, even if they are much longer.
The bulk of traffic in both directions through the Suez Canal start or complete journeys in the Mediterranean basin, Middle East and South or South East Asia. A journey from Livorno in Italy to Mumbai, India increases from 4,392 nautical miles via the Suez Canal to 10,535 via the Cape of Good Hope. Hamburg to Yokohama is 9,148 nautical miles via the Suez Canal, rising to 14,307 via the Panama Canal and 15,680 via the Cape of Good Hope.
The disruption to trade therefore eventually stabilises as shippers adjust to using alternative routes, albeit at the cost of much increased journey times, higher freight rates and insurance.
The simple fact that ships spend more time on the water reduces vessel availability, pushing up charter rates. The reorganisation of logistics takes time. It was only in mid-February that shipping companies started to report a softening of elevated Far East-US freight rates as trade adjusted to the ‘new normal’.
Panama Canal – a victim of climate change?
The Panama Canal’s problems are, notably, of a different nature altogether. In 2022, 38.7 MT of LNG transited the canal from the Atlantic to the Pacific. The Canal
is a crucial waterway for US LNG plants on the Gulf Coast, which is where the majority of current and under construction US LNG capacity is sited.
As Asia represents the strongest long-term source of LNG demand growth, and the US Gulf Coast the largest area of liquefaction expansion, the Panama Canal’s importance to LNG trade will only grow. However, the Canal has for the last six months been operating below normal capacity, owing to a lack of water.
The capacity of the Canal was expanded in 2016 with the addition of a third set of locks, which were designed to reduce water consumption and accommodate larger ships. Each ship that passes releases an average of 52 million gallons of water into the sea using the old locks and about 22 million gallons using the new locks. The water comes not from the Oceans on either side of the Canal, but from inland.
An average of about 14,000 transits take place each year, with about 36 slots available each day. Only ten of these are for Neopanamax vessels (15.2 metre draft in tropical fresh water).
For January, the Panama Canal Authority (ACP) was only able to offer 7 Neopanamax slots and 17 Panamax slots, following the driest October on record for the Canal watershed. Draught restrictions also mean that the largest ships have to carry less cargo to avoid the risk of running aground.
The most important source of water for the Panama Canal is the Chagres River, which at the time of the canal’s construction was dammed to create Lake Gatun. About half of Panama’s population also depends on Lake Gatun for fresh water. While the current lack of rainfall is being attributed to the El Niño weather phenomenon, reduced rainfall as a result of climate change is also a major concern.
The ACP is looking for new sources of water for Lake Gatun, for example from the Indio River or Bayano Lake, but achieving this will take time and be environmentally contentious.
As presently configured, even with the expansion of 2016, the Panama Canal does not look able to cater fully for a significant rise in US-Asian LNG trade, alongside other increases in maritime traffic, without congestion exacerbated by periods of low rainfall. This situation seems certain to benefit European and other Atlantic Basin LNG buyers on the one hand, and LNG projects in Canada and Mexico with direct access to the Pacific Ocean on the other.
The importance of the Suez and Panama Canals, of
Iran, UAE, Oman
Eritrea, Somalia, Djibouti, Yemen
Egypt
Indonesia, Singapore, Malaysia
Turkey
course, pales in comparison with that of the Strait of Hormuz, which is by far the most vulnerable of the world’s key waterways. In addition to Middle Eastern oil exports, all LNG from Qatar – the largest exporter of LNG worldwide in 2022 – and the UAE, as well as some LNG imports to Kuwait, depend on the Strait.
LNG exports via the Strait amount to about 20% of global LNG trade. There is no alternative route and Iran has repeatedly wielded the threat of closure as a weapon in its relations with the West, despite the collateral damage it would inflict on its own trade with the outside world.
However, the Strait of Hormuz is not the only other maritime stress point. The Strait of Malacca provides the shortest shipping route between East Asia and the Middle East. It accounts for about 30% of global trade, including two-thirds of China’s trade and 80% of its energy imports.
China is now the world’s largest market for LNG.
The maritime boundaries of the South China Sea are disputed by China and a number of South Asian countries. In addition, the Strait of Chinese Taipei sees passage of some 40% of the world’s container fleet each year. Maritime security is high on Beijing’s list of concerns as, despite China’s size, the country lacks direct ocean access.
China’s intention is to maintain the security of maritime trade routes vital to its economy, but the lack of
established sea borders and Beijing’s assertive approach create tensions with its neighbours.
A combination of the Ukraine conflict, Red Sea crisis and increased accessibility have increased interest in Arctic Sea routes. They are of particular importance to Russia and its LNG and oil trade as the majority of Russia’s LNG capacity, existing and under construction, is located in the country’s north.
The Northern Sea Route (NSR) offers a much shorter route from northern Europe to Asia than the alternatives.
Hamburg to Yokohama via the NSR is just 6,920 nautical miles, compared with 9,148 via the Suez Canal. If that route is closed or too risky, ships must travel over 14,000 nautical miles via the congested Panama Canal or 15,680 nautical miles via the Cape of Good Hope. The volume of shipping using the NSR is growing, but primarily as a result of increased Russian crude oil and LNG shipments being rerouted from Europe to Asia.
If the Red Sea crisis persists, other shippers may look to Arctic transits as an alternative, but growth is likely to be limited by the still relatively narrow window of opportunity, the risk of delays owing to unexpected ice, the need for ice breakers, which only Russia can provide, and the need for ice-class vessels, in which there has been little investment outside the Russian LNG sector.
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The election result will determine how and under what conditions the non-Free Trade Agreement permits for LNG exports might resume.
JOSEPH MURPHYMore than half of the world’s adult population representing over 60% of global GDP will head to the polls in 2024 in what is an historic year for elections. In at least 64 countries, plus the EU, voters will decide on new governments and legislatures, with energy and climate policy set to take centre stage in many of the political debates.
Perhaps the most critical (and divisive) election for energy is the November presidential vote in the US. The contrast between contenders’ positions on energy policy is stark, spelling significant uncertainty for the US natural gas industry. Critically, the outcome of the election will determine how long a recent pause on authorisations to export LNG to non-Free Trade Agreement (FTA) countries will last, and under what conditions future approvals will be made.
The Biden Administration has pursued an ambitious green agenda, exemplified by the Inflation Reduction Act (IRA) of 2022, touted as the biggest energy and climate investment in American history. The IRA provides close
to $400bn in funding and tax credits for clean energy projects, including the development of blue hydrogen and carbon capture utilisation and storage (CCUS), and it also introduced a penalty for methane emissions.
In light of the global energy crisis, Biden has sought to balance climate considerations with energy security and affordability – not just in the US but also in Europe, which has relied on increased US LNG imports to replace lost Russian pipeline gas supply in the last two years.
The US has also emerged as the top LNG exporter in the world in 2023, with shipments rising 14.7% year on year to nearly 89 MT. This feat is all the more impressive given it was only eight years ago that the country shipped out its first ever LNG cargo. US exports have played a major role since then in keeping the global market wellstocked and accelerating the transition away from coal, particularly in Asia.
Looking ahead, the LNG project pipeline in the US is substantial. The US Energy Information Administration (EIA) forecast last November that US exports would climb to around 153 MTPA by 2027, more than 70% higher than last year’s level. But the outlook beyond that year has
been clouded by Biden’s introduction in late January of a temporary pause on approvals for LNG export projects to non-FTA countries.
The White House argues that the pause gives the Department of Energy (DoE) time to update the economic and environmental analyses it uses to authorise LNG exports. Primarily this means reassessing the impact that future projects would have on greenhouse gas emissions.
The International Gas Union was among a chorus of energy industry stakeholders that denounced Biden’s decision, warning that it sent an “unsettling signal” to global energy markets.
“The current dynamic we are seeing unfold is highly worrying,” IGU Interim Secretary-General Mel Ydreos said in response to the pause. “It is eroding these fundamental market principles and will harm global energy security and emission reduction.”
As the world’s largest LNG exporter, the US has “revolutionised” the global gas market, he said, liberalising it through the introduction of greater
commercial flexibility in trade and contracts. This has helped the world’s energy systems weather the worst energy crisis in history, he stressed, noting that flexible supply was critical for a successful global energy transition and for safeguarding international energy security.
As natural gas produces around half the greenhouse gas emissions of coal on a lifecycle basis, limiting its future supply will mean higher global emissions, he said.
The pause is “very disruptive,” Jason Feer, global head of business intelligence at Poten & Partners, tells Global Voice of Gas (GVG). He warns it creates significantly greater uncertainty not only for projects seeking a DoE permit but also for those that already have one but will need an extension in the next few years.
Compounding the difficulty, the DoE already raised the bar for granting extensions last year.
Most projects due on stream by 2027 or earlier will be unaffected, but it means delays for projects targeting later launches, David Seduski, head of North American natural gas at Energy Aspects, tells GVG. In many cases, developers were hoping to reach final investment
“The current dynamic we are seeing unfold is highly worrying. It is eroding these fundamental market principles and will harm global energy security and emission reduction.”
MEL YDREOS, INTERIM SECRETARY-GENERAL, INTERNATIONAL GAS UNION
decisions (FIDs) on those projects this year, but investors will be wary of committing if there is no guarantee of sales to non-FTA markets.
Some affected projects are near to having enough supply contracts in place to reach FID, but getting to that finish line is now much harder, Feer says, and the same is the case for financing.
Depending on how long the pause lasts, growth in export capacity could stall in the late 2020s and early 2030s, according to Seduski. All told, he estimates that there is around 15 bcfpd (190 MT) of planned LNG export capacity impacted by the decision. Among the largest affected are Commonwealth LNG, Lake Charles LNG and Calcasieu Pass 2.
Future permitting
Republicans in the US House of Representatives passed a bill stripping the DoE of the power to approve LNG exports, leaving the independent Federal Energy Regulatory Commission as the sole body with that remit. But the bill would next need to be passed by the Democrat-controlled Senate and then signed into law by Biden, both of which are unlikely, making its approval in the House a mostly symbolic victory.
The pause is currently slated to last for 15 months. If the Biden administration is re-elected, it could last longer, and scrutiny over future permits will depend greatly on the conclusions of new emissions studies, Seduski says. The frontrunner Republican Presidential candidate Donald Trump said on January 27 that he would undo Biden’s pause on LNG approval immediately if elected.
The pause was introduced via executive order and could be reversed just as easily in the same manner, Eugene Kim, research director for Americas gas research at Wood Mackenzie, notes. A Trump administration could revert back to 2019 emissions studies by the Environmental Protection Agency (EPA) to determine LNG approvals, according to Seduski. These studies concluded that US LNG could reduce emissions by replacing Russian pipeline gas and the burning of coal, while also being less emissions intensive than competing LNG supplies.
If and when the pause is ended, Feer expects there will be a backlog of applications for new permits and extensions, meaning affected projects won’t move forward overnight. Were a Trump administration to open the floodgates on permitting immediately, this could lead to a flurry of lawsuits by LNG opponents arguing that there was not enough time for proper due diligence, he adds.
Amongst other major considerations of impacts from the outcome of the US elections is the IRA, the Biden Administration’s flagship policy instrument for advancing
Some affected projects are near to having enough supply contracts in place to reach FID, but getting to that finish line is now much harder, and the same is the case for financing.
climate and the energy transition.
“A rollback of IRA is also possible or at least weakening of penalties and support through amendments to it,” WoodMac’s Kim explains. However, the IRA is more difficult to undo than the pause on LNG approvals because it is a congressional law.
The oil and gas industry has supported many of the IRA’s provisions, including incentives for CCUS and blue hydrogen.
A lot of American producers are already addressing their methane emissions by certifying their natural gas under initiatives such as MiQ and Project Canary. These initiatives certify gas based on its methane intensity, using comprehensive monitoring and quantification methods. Operators can use this certification to improve their environmental social governance (ESG) ratings, or sell their gas at a premium on the market.
Another critical issue at stake in the upcoming election is oil and gas lease sales on public lands and in federal waters. The Biden administration has held some lease sales, but only under court orders, having tried to halt them several times. Its current plan offers no lease sales this year, and only three sales until 2029. This would mean that the fewest sites would be on offer over a fiveyear period since the 1980s, according to Seduski.
“A Trump administration would likely open up a lot more land for drilling offshore and on public lands,” he says. Public lands do not generate a huge chunk of overall US production, but longer term this could mean a different inflection for US gas production growth. Production will need to grow, including on public lands, to keep up with domestic and export demand.”
Qube Technologies provides a continuous monitoring solution that is low-cost and scalable, helping oil and gas operators detect and eliminate methane leaks quickly and effectively, the company’s chief operating officer Eric Wen tells Global Voice of Gas.
JOSEPH MURPHYOil and gas operators have deployed a wide array of technologies to find and eliminate fugitive methane emissions, but the key challenge has been continuous monitoring. One pioneer in this field is Calgary-based Qube Technologies, which within just over five years has built a significant presence in the North American market, with around 4,500 of its low-cost, easy-to-install sensor devices now deployed at facilities in the US and Canada.
The devices themselves are only one of three parts of the solution that Qube offers its customers. The hardware measures emissions at the site, and then feeds the information to an analytics platform that uses the raw data to calculate flow rates and location. Finally, there is the dashboard, which visualises those insights, allowing customers to manage repairs and follow-up work, and track their performance on handling emissions over time.
“The intention here is to have a very scalable solution,” Qube’s chief operating officer Eric Wen
tells Global Voice of Gas (GVG). “When we started the business, we realised that there are millions of potential facilities and wellheads that could be monitored using low-cost continuous monitoring.”
That scalability is achieved through Qube’s use of standalone devices, powered by their own solar panels and batteries and with LTE or 3G connectivity, depending on where they are deployed. They are built to ensure harsh conditions, with a lifespan of more than five years. And they can be installed by experienced personnel within only 20 minutes.
There are many ways to spot emissions leaks, whether it is workers inspecting facilities on foot using optical gas imaging (OGI) cameras, sensors mounted on vehicles or drones, airplane flyovers or the use of satellites. While these techniques are important, emissions can be very variable and occur intermittently. Continuous monitoring can alert operators in real time to leaks that might
otherwise go undetected for potentially months between site inspections, and detect intermittent emissions that other techniques might miss.
“Emissions tend to follow the power law,” Wen explains. “90% of your emissions come from 10% of your assets and 90% of your volumes tend to come from 10% of your events. This is why continuous monitoring is really important – you can detect the biggest leaks earlier, and you can get a sense of how your emissions vary across sites at any given point in time.”
Qube’s story starts in 2018. It spent its first two years developing its products before entering the commercial phase at the end of 2021.
“What was missing in the market was low-cost, accurate continuous monitoring,” Wen says. “A lot of the continuous monitoring systems that were present at the time were laser-based – very expensive, very power hungry. So we developed a sensor that gets laser-level quality at a fraction of the cost. For the price of a typical smartphone, Qube provides quantified methane data 24 hours per day, 365 days per year.”
The company found its feet in the Canadian market, where there are more prevalent and progressive rules on methane emissions. It provided operators with a means of meeting these regulatory requirements at a low cost, Wen explains. Today, however, two-thirds of Qube’s customers are in the US.
So far, the driver behind adoption of Qube’s technology in the US has been operators acting on their own initiative to tackle their methane emissions.
“Firstly, operators have realised that finding and fixing methane leaks faster is a very cost-effective way of meeting their net-zero goals,” Wen says. “Secondly, there is a lot more publicity around methane emissions given the negative impact of the environment.”
Some companies have sought to improve their environmental social governance (ESG) ratings, while others have sought to differentiate their gas as cleaner using certification schemes established by MiQ and others. But moving forward, Wen believes adoption will be driven more by efforts to comply with the new methane rules that have been introduced by the Environmental Protection Agency (EPA).
Qube is one of a number of start-ups in the methane monitoring space to come out of Canada, and specifically Calgary, in recent years.
“Canada is a natural resource-based economy; we’re pretty forward thinking in terms of the deployment of technology. And with 70% of oil and gas production in Alberta, and a lot of the operators based in Calgary, you
create an ecosystem where customers and the developers of technology are very closely knit,” he says.
The country’s progressive regulations on methane emissions have also been a factor, opening up opportunities to companies such as Qube.
Canada also offers a supportive environment for startups, according to Wen, particularly those in the clean technology space. Qube notably secured its initial funding in the form of government grants.
Qube went on to obtain Series A financing in 2021 from SCF Ventures, the technology arm of US investor SCF Partners, among others. Last year it secured Series B financing from Houston-based Riverbend Energy Group, as well as Canadian energy infrastructure operator TC Energy, international venture fund Bain & Co. and NGIF Capital, set up by the Canadian Gas Association (CGA) to help finance cleantech innovation.
Beyond the financial support, backing from the oil and natural gas industry has leant credibility to Qube’s offering to clients and helped forge new connections.
While Qube already has more than 4,500 devices deployed for 80 clients, “this is only scratching the surface,” Wen says. The company sees big growth potential, particularly with the introduction of the new methane rules in the US. It also hopes to do more work outside of North America. It already has devices working in Australia, Southeast Asia, the Middle East and in Europe, though these operations are currently small in scale. The fact that some of its North American clients have assets elsewhere can act as a springboard for Qube’s international expansion, Wen says, as those clients want to deploy the same monitoring solutions across their international portfolios.
Looking ahead, while Qube is proud of its offering, it continues to invest in research and development. When it comes to hardware, the company wants to further drive costs down and improve reliability, with the help of feedback from field performance.
As for analytics, the focus is on improving quantification and localisation. Qube has its own testing facility where it releases gas at a certain location at a certain flow rate, and monitors this with its sensors, in order to fine-tune their accuracy. As for the dashboard, the aim is to help operators embed more of their emissions management within the system, and assist them in reporting their emissions to regulators, or for OGMP 2.0 purposes.
“Continuous monitoring can not only help operators detect emissions as soon as they occur but verify whether repairs have been done correctly,” Wen says.
ERIC WEN QUBE TECHNOLOGIES COOA Publication of the International Gas Union (IGU) in collaboration with Minoils Media Ltd.
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