Global Voice of Gas - Issue 2, Volume 3

BY THE INTERNATIONAL GAS UNION

This is Opportunity

Working with local and Indigenous companies, and thousands of highly-skilled British Columbians, we’re building our world-leading LNG export facility in Kitimat, in the traditional territory of the Haisla Nation.

The LNG Canada project is now more than 80% complete.

lngcanada.ca

Message from the President

Dear readers, welcome to the LNG2023 special issue of the Global Voice of Gas.

It has been amazing to see the rapid pace of change in the world over the past few years and the incredible agility with which the world has been adjusting to it. The gas industry has been at the forefront of agility in the energy sector, and LNG has played a crucial role to supply the life-saving flexibility to the global energy system, especially over the last 24 months.

One definitively positive change is that we are now firmly back in the face-to-face environment, and I am so glad to join colleagues from the CGA, GTI, and IIR in the warm welcome to Vancouver this July, as we are finally reaching the finish line of the amazing journey to LNG2023 in Canada.

I share the LNG2023 Executive Director’s view that this is an opportunity not just to shape the future of LNG and gas, but also to make a meaningful contribution to the future of energy and the planet. The timing for the biggest international meeting of the global LNG leaders and stakeholders could not be more critical.

Liquefied natural gas has already demonstrated its value as a vital fuel for energy security, and the demand for this security value of LNG will be strong, especially over the coming three-to-five years. The industry stands ready to deliver, and it is going to continue to respond to the signals from policy and the consumers to effectively plan supply, transport, and utilisation capabilities. Our gas industry is also strongly committed to continue upholding its value as an energy transition enabler, investing in decarbonisation technologies to reduce their costs and to look for innovation opportunities, both technical and commercial, to make decarbonisation good for the environment and for business.

Here again supportive policy will be crucial, as

the technologies in earlier stages of development still require significant de-risking and scaling capital. This can include new electrification technologies, integration of greater shares of renewables, carbon capture and storage, conversion to renewable fuels like hydrogen, and others. As an industry of engineers, we are confident in the abundance of opportunities. I therefore would like to encourage policymakers and investors to focus on the emissions reductions opportunities, with the largest achievable impact on emissions and avoid ideological debates, which only slow us all down. With fossil fuels still meeting 80% of the world’s growing energy demand, with coal and oil being the biggest, decarbonisation strategies that prohibit investment in natural gas are going to be of questionable effectiveness, since gas provides an immediate opportunity to cut emissions by up to half when replacing coal, and by a third when replacing oil. Natural gas is also more cost-effectively decarbonisable, including through the substitute with renewable biomethane and introduction of hydrogen into the gas networks. Replacing coal and oil with gas still presents some of the largest immediate emissions reduction opportunities available.

The gas industry will continue to drive toward decarbonisation, and we will continue to call for a joint effort to focus on the one common goal of a healthy planet and a sustainable energy future for all.

FEATURES

Li Yalan, IGU President

Editors’ Note

Welcome to the 12th issue of the Global Voice of Gas magazine, an International Gas Union publication, produced in collaboration with Natural Gas World (NGW).

This special edition issue is dedicated to LNG, on the occasion of the 20th edition of the world’s largest international LNG conference, LNG2023, taking place in Vancouver on July 10-13.

Energy prices have fallen significantly over the past six months, easing the tension in gas and energy markets and allowing consumers some long overdue relief. But this creates risk of complacency from falsely concluding that the supply crisis is over. This respite should be used to mobilise plans for supply and demand balancing to ensure that the winters ahead do not force the world into another series of energy shocks. Significant challenges will also remain, as developed and developing countries struggle to strike a balance between ensuring stable and affordable energy supply and fulfilling their climate ambitions. Through the crisis, natural gas, and LNG in particular, has demonstrated its critical role in providing the world the reliable and sustainable energy it needs. Looking ahead, the industry and policymakers alike should focus on how a more stable, cleaner and more prosperous future can be secured, and this will be a key theme at the upcoming conference in Vancouver.

In this issue, we are proud to include a feature written by Michael Stoppard, Andres Roja and Anusha De Silva, from S&P Global Commodity Insights on the classic prisoner’s dilemma that European LNG buyers face with regard to securing long-term supply now, potentially causing prices to fall in the late-2020s, versus side-stepping long-term offtake but risking losing leverage with suppliers. In our Decarbonising Energy: Innovation and Start-ups special feature in this issue, Tuomas Riski, CEO of Norsepower, discusses with Global Voice of Gas how the company’s Norsepower Rotor Sails technology harnesses the power of the wind to make shipping more fuel efficient and cleaner.

We are also pleased to present a feature written by Liu He, Senior Fellow, and Zhang Guosheng,

Professor, at The Research Institute of Exploration and Development (RIPED) of China National Petroleum Corporation, on the outlook for natural gas production and further market development in China. The feature projects how gas will play an increasingly important role in reducing China’s emissions and supporting its energy security, but stresses that there must be enhanced planning of the gas and energy systems, further reforms and greater market integration, to fully enable the fuel’s benefit.

Many LNG developers are looking towards carbon capture and storage (CCS) to ensure their continued licence to operate, and the added cost that this technology presents is another topic this issue focuses on. We also weigh up the possibilities for repurposing LNG infrastructure for hydrogen and ammonia, to make it future-proof, and how standard LNG can deliver emissions cuts across the world by replacing coal and supporting further renewables deployment. In addition, we look at the strong business case for Canada joining the global LNG market, as it advances a raft of new supply projects.

In an article brought to you by the International Gas Research Conference (IGRC2024), we explore how fuel oil is finally giving way to alternative, cleaner shipping fuels, and how momentum continues to build behind LNG as the most popular of these alternatives.

Finally, we bring you the traditional regional developments and updates section from the IGU Regional Coordinators. In this issue, IGU regional leads bring insight from the Americas, and South and Southeast Asia

We hope that this issue provides interesting insight and fruitful context for the timely discussions and critical debates at LNG2023, and we look forward to seeing many of you there!

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LNG2023 awaits you!

As the Executive Director of LNG2023, I am delighted to extend a warm invitation to you. This year, from July 10-13, we mark the 20th edition of the world’s largest triennial Liquefied Natural Gas (LNG) conference. We’re gathering in the heart of downtown Vancouver, at the Vancouver Convention Centre, a venue that vibrates with the same dynamic energy that fuels our industry. It’s a privilege to convene on the traditional lands of the First Nations of Canada’s Pacific Coast.

This collaboration between the International Gas Union, GTI Energy, and the International Institute of Refrigeration, hosted by the Canadian Gas Association, makes LNG2023 possible. We are particularly delighted to have QatarEnergy, the future host of our LNG2026 conference, as part of the team.

This gathering is as important, as it is timely; we’re not just discussing energy at this conference; we’re addressing the future of our planet. The gas sector’s vital role in providing affordable, reliable, and sustainable energy sources for modern life is our key focus. The diverse landscape of Vancouver serves as a symbol of the variety of perspectives we look forward to embrace in our discussions.

In Canada, natural gas is deeply ingrained into our great country’s social fabric. It meets 38% of our energy

needs, and by 2025, we’ll be stepping up as an LNG exporting nation. This transition is a proud and eagerly anticipated moment for us.

LNG2023 is a beacon of global connection after the challenging years of separation caused by the pandemic. We are expecting up to 15,000 delegates from over 85 countries, each contributing their unique viewpoint on energy’s future. This summer, we rekindle old friendships and foster new collaborations.

Our conference themes, “Fueling a More Stable Future”, “Fueling a Cleaner Future”, and “Fueling a More Prosperous Future”, capture our shared vision. We’re all on the same path, trying to strike a balance between global energy demand and sustainable supply.

Moving towards a greener future isn’t as simple as flipping a switch. It’s about navigating a path forward with education and collaboration as our guides. LNG, amidst the ups and downs of recent years, has shown itself to be the flexible fuel that the world truly needs. Its demand continues to rise, reflecting our growing ingenuity in using this resource sustainably.

In the end, we are the sum of our choices. The world needs wise choices now more than ever. That’s the essence of LNG2023. I eagerly anticipate welcoming you as we shape the future of energy together.

We’re not just discussing energy at this conference; we’re addressing the future of our planet.

MENELAOS (MEL) YDREOS, EXECUTIVE DIRECTOR, LNG2023

The IGU welcomes you to LNG2023

How good is it to be together, all in one place, with virtually the entire LNG industry. With four days of collaboration, learning, networking, and doing business, it may well be your most effective week all year. And, of course, all in the wonderful city of Vancouver.

This is also a great opportunity to meet the IGU team, whilst on site at LNG2023! We will be at the LNG2023 Exhibition floor in the IGU booth (B622). Come and see us, or contact the team to arrange a meeting. For events: Rodney.Cox@igu.org; for membership & collaboration opportunities: Tatiana. Khanberg@igu.org.

I also encourage you to visit www.lng2023.org for the full details on the programme, speakers, registrations, and all conference-related information.

A big thank you to Tim Egan, President and CEO of the Canadian Gas Association, our IGU Charter

Looking ahead to LNG2026 Doha

Member and host of LNG2023, as well as the event’s Executive Director, Mel Ydreos, for delivering a meaningful conference with a timely debate on LNG and its key role in delivering a sustainable energy future.

Even as we celebrate all things LNG2023 we are already looking to the future and are very pleased to announce IGU Charter Member, QatarEnergy as the host of LNG2026 in Doha.

In 2024 we are back in Canada for IGU’s International Gas Research Conference, IGRC2024.

And looking ahead to IGU’s flagship World Gas Conference, WGC2025 is coming to Beijing, for our first time in China.

Further details on all these upcoming IGU Flagship Events are in the articles below.

Thank you for supporting IGU’s flagship events and your time in Vancouver at LNG2023.

LNG2023 Delegates are welcome to join us at the “LNG2026 Welcome with QatarEnergy” reception on Wednesday, July 12, at 17:45 at the West Building Ballroom Foyer on Level 1. Hosted by QatarEnergy, this reception will take you on a journey to the upcoming host country, Qatar, with traditional food and dance performances. Get a sneak peek at what’s to come at LNG2026!

For more information on LNG2026 drop past the QatarEnergy stand B914 Hall: West Ballroom on Level 1

The 29th edition of the World Gas Conference, WGC2025, comes for the first time to Beijing at the China National Convention Centre Phase II, located in the Beijing Olympic Green Area. This facility was first designed to house the Main Media Centre for the Beijing 2022 Winter Olympics and is being refitted as a state of

the art venue, with WGC2025 the first event that uses the whole of the facility.

The WGC2025 team is onsite at LNG2023 at booth B622. Come and say hello to the WGC2025 team for details on the exhibition and sponsorship, or to ensure you receive the Call for Abstracts and delegate registration information when they are launched.

You can always contact the WGC2025 team at any time – email Jason Berman at JBerman@etf.com.au.

Presented By Host Partner:

RODNEY COX Director of Events, International Gas Union

A Few Words About the International Gas Union

As valued readers of the Global Voice of Gas, you already know about the magazine and are likely aware of the IGU flagship reports providing comprehensive analysis on the key gas industry and gas markets developments.

But did you know it is also possible to join the IGU and participate in the biggest global gas industry organisation as a Member of the IGU.

I thought that sharing a few details about the IGU organisation would be interesting for our non-member readers, considering if they could join.

Established in 1931, the IGU is the only longstanding international gas industry organisation whose membership covers the entire gas value chain, across more than 80 countries, representing 90% of the global gas market. Our Members are our foundation, our strength, and our purpose.

IGU Charter Members represent the gas industry of a given country, and these are generally the most representative gas entities, such as the national associations, major companies, or sometimes Ministry

or the regulator, and they are the voting members of the IGU Council, the IGU’s main governing body. The IGU also has Associate Members, who are commercial and non-commercial entities from all segments of the enormous gas value chain. There is no limit on the number of associate members by country or region, while there can only be one Charter Member per country. In sum, all IGU members are companies or organisations with a vested interest in the progress of the global gas industry helping deliver a secure and sustainable energy future.

The IGU is truly a unique network, with an unmatched collective global gas industry expertise. Our members work in every segment of the gas value chain, from the supply of natural and decarbonised gas, renewable gas and hydrogen, through their transmission and distribution, and all the way down to the point of use. Hence, “gas” in the IGU mandate includes many forms of gaseous fuels.

The IGU also has 11 thematic Committees and 3 Task Forces working on the most pressing topics facing

the sector today and into the future, and they play an important role shaping the technical program of our key global conferences. Being a part of the IGU is an opportunity for our Members’ employees to connect and collaborate with anywhere around 1,000 international gas and related industry professionals from our member groups and companies.

To achieve its purpose and advocate for the progress of the gas industry, the IGU works to promote transparency, innovation, public acceptance, and a well-functioning global gas market. We seek to collaborate with governmental agencies and multilateral organisations to demonstrate the economic, social and environmental benefits that gas can offer in the global energy mix.

The IGU also provides industry networking and collaboration opportunities and organises the most prestigious international gas events, including the World Gas Conference, the International Gas Research Conference, and of course the World LNG Conference series (the latter in partnership with our colleagues from

the GTI and IIR). The IGU Charter Members can apply to host these major international energy events, as the Canadian Gas Association has successfully done to bring you LNG2023 in Vancouver.

It is also important to stress that the IGU is committed to the success of the Paris Agreement and the energy transition, and that success will of course require decarbonising the natural gas supply at a fast pace. At the same time, our global membership makes us all too aware of the divergent energy and economic realities in different regions of the world, and the IGU emphasises that the energy transition will require realistic and achievable implementation planning, developed by local experts with knowledge of local challenges and possibilities.

If you would like to learn more about membership options and specific benefits,I invite you to visit this link, send us a note at Membership@igu.org, or come and see us at the IGU Booth in Vancouver at the LNG2023.

TATIANA KHANBERG, STRATEGIC COMMUNICATIONS AND MEMBERSHIP DIRECTOR, IGU

The IGU is truly a unique network, with an unmatched collective global gas industry expertise.

Call for Papers now open for IGRC2024, the IGU’s International Gas Research C onference.

With our industry looking ahead to both opportunities and challenges there has never been a more important role for research, development and innovation to play in maximising our future potential. The IGU’s International Gas Research Conference (IGRC2024 in Canada) provides the timely opportunity for our industry to bring together the best thinking on how we achieve this. IGRC2024 is where the latest research, leading practices and experiences will be shared – so whether you are an innovator, academic, research organisation or industry professional, we encourage you to submit an abstract paper, and be part of the dialogue that will shape the gas industry’s future.

Which of our six streams best matches your knowledge and interests?

Stream 1: Natural Gas 2.0

» Improvements in natural gas production, particularly in reducing the environmental footprint.

» Efficiency improvements in production, transport and distribution, storage, or utilisation.

» Electrification and hybridization of natural gas systems in upstream, midstream, and downstream.

» Carbon capture, utilisation, and storage applications.

» Solutions for decreased land impact or water use.

» Waste heat reduction and usage.

» New business models for production.

» Advances in LNG technologies.

» Innovations in Natural Gas use as transportation fuel.

Stream 2: Methane emissions reduction

» Advancements in sensor technology for methane detection.

» Advancements in satellite monitoring and measurement.

» Improved remote land and air remote detection (fixed wing, drones, robots, and robot dogs).

» Vehicle mounted detection.

» Reduction of methane emissions in gas infrastructure and end use application technologies.

Stream 3: Responsibly Sourced Gas (RSG) certification

» Measurement, registration, and reporting for reduced carbon intensity.

» Measurement, registration, and reporting for ESG.

» Methane credits.

» Life cycle assessments.

» Block chain certification.

» Low-emission LNG.

» Creating markets for certified RSG.

Stream 4: Renewable methane

» Biological or chemical production of renewable methane.

» Admixture and/or blending of renewable methane in

the gas grid.

» Direct use of renewable methane.

» Making the most of limited biogenic resources through increasing CH4 and CO2 yield.

» Optimization and purification approaches to facilitate injection and reduce risk mitigation, including methanation.

» Bio-LNG.

» Use of biogenic CO2

» Negative emissions accounting.

Stream 5: Hydrogen

» Further decreasing the climate impact of hydrogen production from natural gas.

» Mitigating the impact of hydrogen blending on the gas infrastructure.

» Injection of hydrogen in the gas grid: what are the implications and limits.

» End use applications using direct or blended hydrogen.

» Hydrogen leakage.

» Hydrogen storage in caverns, depleted gas fields or aquifers.

Stream 6: Digital transformation

» Gas operations optimization to integrate new gases.

» Accelerating training and assessment.

» Remote and centralised control centres and operations.

» Emerging energy businesses and services, including digital credentials for low emission gases, environmental assessment, and impact reduction, and end-users’ energy management systems.

» Assets management, optimisation, and automation, including LNG operations, and pipeline and equipment inspection.

» Digital twins.

» Cybersecurity implications of digital operations.

» Digital transformation strategies for the gas Industry.

» Other emerging solutions.

page including details on how to submit your paper abstract and the timeline.

North America

Energy security, affordability, and emission reductions remain top priorities for North America’s natural gas industry.

» In Canada, the US, and Mexico industry leaders are showcasing to decision-makers the foundational role of gas energy for the current and future economic well-being of our respective countries, and our allies around the world. Natural gas production in North America continues to hit record levels and the industry is aligned in its message on growing its ability to support domestic and global energy security and emission reduction goals while maintaining affordability for consumers, underscored by consistent month-over-month low commodity prices.

US natural gas production levels continue to reach record highs, propelling the nation to become the world’s largest natural gas producer and LNG exporter.

» New natural gas transport and LNG infrastructure continues to be built, increasing the country’s ability to produce and export even more.

» The Biden administration’s aggressive emissions reduction agenda, as embodied in the Inflation Reduction Act, has faced more scrutiny since Republicans gained a majority in the House of Representatives after the last midterm elections.

» The US government continues to shower public dollars on what can broadly be called an electrification agenda. Despite that, the gas market – because of its fundamental strengths – is doing well.

A US official’s hint in late 2022, that gas stoves might be banned due to claims

of health risks, opened a new front in America’s culture wars and unleashed a torrent of over-the-top headlines.

» US gas utilities are challenging the research behind the health risk claims, while also fighting the larger, more imminent threat of restrictions on new gas hookups being pushed by advocates who see total electrification as a necessary pathway to deliver on emission reduction targets. Gas industry advocates have pushed back, with 24 states – many with bipartisan support – passing “fuel choice” legislation preempting municipalities from banning natural gas use in buildings. Those states account for nearly one-third of US residential and commercial gas use. Similar legislation has been introduced in several other states.

» The industry also has notched victories in court, notably a ruling by the US Court of Appeals for the Ninth Circuit on April 17 overturning the Berkeley, California, municipal gas ban on the grounds that city officials overstepped their authority. The ruling was expected to be challenged, but experts say other bans may not be affected due to the ruling’s narrow focus on specifics of Berkeley’s law. It all points to a bigger battle over bans.

In Mexico, the Southeast Gateway project continues making progress and the federal government continues to show strong support for the development of new natural gas infrastructure, with a focus on increasing production and expanding pipeline networks to Mexico’s south, where gas shortages are common and scarcity drives up prices

» Domestic natural gas production has seen consistent growth, though the large majority of Mexico’s national gas demand is still met by imports from the US.

» Nearshoring is incentivising greater direct investment in manufacturing activities, and the government has funded large-scale infrastructure projects, like the development of the Transisthmic Corridor, the Dos Bocas Refinery, and the Mayan Train, all of which will increase the rate of growth for gas demand in the coming years.

» Industrial gas consumers, the power generation sector, and federal energy policy all recognise natural gas’ role in Mexico,

TIMOTHY EGAN CEO of the Canadian Gas Association and IGU Regional Coordinator

Where energies make tomorrow

with significant investments from state power utility CFE in technology and equipment to fuel-switch fuel oil in power generation for natural gas and decrease power prices and related emissions.

» The natural gas industry has maintained an open dialogue with federal authorities following the renegotiation of several midstream transport contracts, and several joint ventures to finance new transport and LNG export infrastructure have been announced over the past year.

» The emissions-reduction, price-point, and reliability benefits of Mexico’s natural gas supply are broadly recognised by most major political parties, and it is likely the following federal administration will continue capitalising on Mexico’s access to inexpensive US gas imports through expansions to the pipeline network and building out of LNG export facilities.

the industry is high, with both Canadian and US industries having record-high engagement at industry events this year.

» Building on that enthusiasm, CGA hosted a North American Natural Gas Summit in Calgary in March. The event is an important step in the effort to coordinate a broader public positioning exercise by the gas industry and its consumers in North America and will be followed by comparable events in Mexico (in 2024) and the US (in 2025).

» The growing global focus on gas makes North America’s hosting of LNG2023 in Vancouver in July all the more timely. The Canadian industry looks forward to welcoming the world and a robust conversation on the global opportunity for clean, affordable, reliable, and secure energy provided by LNG.

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» In March 2023, the Haisla Nation-led Cedar LNG project received federal approval marking a significant milestone to grow LNG exports from Canada. To build on that, the gas industry in Canada launched Energy for a Secure Future, a civil society initiative bringing together Canadian business leaders, Indigenous peoples, organisations, and experts to implement a new vision for Canada’s gas energy and infrastructure.

» LNG Canada’s Kitimat, BC project – on track to be operational in 2025 – continues to make significant progress.

» While the Canadian government has announced new tax credits for power generated from natural gas and a new “Hydrogen Investment Tax Credit,” which includes blue hydrogen, the overall government policy framework continues to be focused, like that of the Biden administration, on the electrification agenda, hindering Canada’s ability to capitalise as it might on the global LNG opportunity.

The North American IGU members are working to ensure greater coordination than has existed in the past. Interest in

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In Canada, the industry continues to see growing support and participation from indigenous communities.

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Argentina continues to work on debottlenecking domestic gas supply.

Argentina’s total gas consumption was 46.2 bcm in 2022, slightly less than 2021. LNG imports came to 2.3 bcm, versus 3.5 bcm in 2021, and imports from Bolivia amounted to 3.8 bcm, compared with 4.7 bcm.

With gross production of gas averaged almost 130 mcmpd in summer months, domestic gas supply in Argentina maintained its historical season range, in which demand declines were driven by milder temperatures.

The Neuquen basin is set to increase its transportation capacity by 11 mcmpd this winter with the launch of the President Néstor Kirchner gas pipeline in July. Compression improvements will increase the expansion capacity by 11 mcmpd in 2024 and by 2025, Stage 1 will be completed, adding an additional 7 mcmpd.

Gas production is forecast to increase by winter 2023. As further expansions to the pipeline system are undertaken, new auctions are expected to take place, boosting production in the Neuquén basin, replacing Bolivian and LNG imports and offsetting decline in other basins.

The available volume of Bolivian imports is volatile, with contracts expected to cover only 7-8 mcmpd of supply this winter, well below the average 13.5-14 mcmpd during 2022.

This year, Argentina has so far secured 44 LNG cargoes for around $2bn. The country has expanded LNG imports because it does not have enough transport capacity to supply gas from its main fields to areas with the highest demand.

Brazil is taking steps to reduce gas reinjection, freeing up more supply for

local industries – most notably for fertiliser

Brazil’s total gas consumption was 26.1 bcm in 2022, down from 35.65 bcm in 2021. Gas imports from Bolivia in 2022 came to 6.4 bcm, versus 7.3 bcm in 2021.

Lula´s administration is announcing changes, which

have not been completely defined yet, to the current energy policy. The government will seek to reduce gas reinjection in the pre-salt offshore associated oil and gas fields. Brazil is currently reinjecting volumes equivalent to twice the national consumption.

» The ministry of industrial development is creating a working group to assess how to fast-track the supply of domestic gas to the industries in Brazil. The group will be formed by representatives of the industry federations of Rio de Janeiro and São Paulo, the ministries of industrial development and mines and energy, Petrobras, independent producers and the National Petroleum, Gas and Biofuels Agency (ANP).

» Industry associations are putting pressure on the ministry of mines and energy to set out a policy for diverting some offshore gas that is currently reinjected into oil reservoirs for industrial use, to cut dependence on imported fertiliser in particular. Brazil currently covers 85% of its fertiliser consumption with imports.

» Petrobras will likely delay the process for privatising some of its assets, especially its refineries.

» Gas demand in the power sector has been subdued due to a favourable hydropower output and high LNG import prices.

» A recent report by Wood Mackenzie indicated that Bolivia’s natural gas exports to Brazil and Argentina might come to a halt due to the lack of investment and no new discoveries, implying that Bolivia might become an importer after 2030.

» China Classification Society (CCS), Singapore’s SDTR Marine (SDTR) and Shanghai’s Merchant Ship Design & Research Institute (SDARI) have jointly developed an 85,000-dwt ammonia-fuelled bulk carrier, CCS said on February 22.

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» Chile’s total gas consumption was 8.3 bcm in 2022. Around 84% of this volume was imported – almost half in LNG form and the remainder as pipeline supply from Argentina.

» In 2021 Argentina met 15% of total gas consumption in Chile, highlighting the country’s importance as a supplier. But gas from Argentina continues to be delivered under short-term contracts, with limited firm conditions. Most of the supply arrives in summer and there is less in winter. Therefore, LNG will continue playing an important role in Chilean energy diversification and security.

» There has been significant growth in natural gas consumption for power generation, even surpassing coal and renewable sources. On March 30 this year, the system generated 24% of the total demand with natural gas, leaving solar generation, hydroelectric, and coal behind. High gas use is the result of a lack of sufficient transmission capacity to fully utilise solar capacity in the north of the country and the increased availability of

» The reasons behind this can be attributed to two main factors: the lack of sufficient transmission capacity to fully utilise solar generation from the north of the country and the increased availability of Argentine gas.

» A major disruption to 2023 deliveries to GNL Mejillones LNG terminal in the country’s north, as a result of TotalEnergies defaulting on its long-term LNG supply contract with Engie, has been partially offset with the supply of alternative local and international spot cargoes.

Colombia boasts the highest gas coverage rate in Latin America, and wants to expand that coverage even further, while also using gas to decarbonise the transport sector.

» Colombia’s total gas consumption in 2022 was 29.5 bcm, supplied by local production. The Ecopetrol group is the main player in the upstream sector, with a market share of 80%.

Call for papers – now open!

Closes September 15, 2023

IGRC2024 is the next triannual global gathering of innovators, academics, research organizations and industry leaders where the latest research, leading practices and experiences will be shared. We encourage you to submit your paper abstracts and be part of the dialogue that will shape the gas industry's future.

Submissions covering the full industry value chain are accepted under the following six streams:

•Stream 1: Natural Gas 2.0

•Stream 2: Methane emissions reduction

•Stream 3: Responsibly Sourced Gas (RSG) certification

•Stream 4: Renewable methane

•Stream 5: Hydrogen

•Stream 6: Digital transformation

LNG will continue to play an important role in ensuring Chilean energy security, particularly in light of a significant growth in natural gas consumption in the power sector.

» Natural gas coverage in Colombia reaches more than 10.8mn residential users, benefitting around 36mn people. This represents the highest coverage rate in Latin America.

» The highest consumption is in the industrial sector (32%), followed by the residential sector (22%) and the power generation sector (21%).

» The SPEC regasification plant provides stability and back-up supply for the electrical grid.

» Colombia is committed to decarbonising the transport sector, and to date there are already more than 670,000 vehicles converted to compressed natural gas (CNG) and more than 4,400 cargo and passenger vehicles also using the fuel. This year more than 1,000 heavy-duty vehicles (buses and trucks) are also expected to be converted to CNG.

» Regarding public policy, the ministry of mines and energy presented the Just Energy Transition roadmap in May, which focuses on four pillars and reinforces the government’s message of positioning natural gas as a key fuel of the energy transition. It focuses on developing infrastructure for gas supply in order to substitute the use of firewood for cooking among rural and urban families.

Trinidad & Tobago needs more gas to cover demand at its petrochemical plants and Atlantic LNG trains. A potential deal to access gas from the Dragon Gas project in Venezuelan waters could be the answer.

» Trinidad & Tobago gas demand exceeds supply. The difference is not covered and so the resultant effect is that the petrochemical plants and Atlantic LNG trains do not run at maximum capacity (i.e. there is room to produce more LNG and petrochemical products if there was more gas supply). The country’s overall gas supply in 2022 was 27.8 bcm, with 47% supplied to LNG facilities and 53% to the domestic market, including for gas-fired power generation.

» The 2022 onshore upstream bidding round closed in January this year, with 16 bids submitted by eight companies.

The energy ministry continues its evaluation and awards are expected to be made by the fourth quarter of this year.

» Woodside Energy and Shell continue to progress the offshore Calypso and Manatee gas development projects respectively, targeting first supply post-2027.

» After a weak fourth quarter in 2022, the global demand for methanol is increasing, with many sectors of the market reporting gradual improvements in operating rates and economic optimism.

» Trinidad & Tobago signed a non-disclosure agreement with the Venezuelan government on March 14 concerning gas supply from the Venezuelan Dragon Gas project. The Dragon deal, if successful, will give Trinidad & Tobago access to gas from fields in Venezuela’s territorial waters.

» On November 29 last year, Trinidad & Tobago’s energy ministry launched “The Roadmap for a Green Hydrogen Economy in T&T” to evaluate the country’s potential to produce green hydrogen as a means of decarbonising the nation’s power and industrial sectors.

South & Southeast Asia

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

Southeast Asia continues to establish energy policies and roadmaps aimed at ensuring a just energy transition.

Natural gas as the cleanest fossil fuel provides stable and affordable energy for nations in South & Southeast Asia. The gas industry is growing fast and has a lot of potential in natural gas demand. ASEAN’s natural gas demand is expected to grow by up to 250% by 2040 compared to 2017 in the baseline scenario and financial institutions in the region are expected to continue supporting investment in natural gas infrastructure. Finding a balance between energy security, affordability and sustainability remains a top priority for the countries in the region. And they continue to hone their energy policies to better ensure this balance. Many of ASEAN’s 10 member states show a strong commitment towards achieving net zero, albeit with differing timeframes. Nevertheless, the policy environment generally favours a low-carbon energy future and the region remains on track to deliver a 23% share of renewables in the total primary energy supply by 2025. Hence, the role of gas will become more prominent to complement those renewables.

» Malaysia expects to complete its National Energy Transition Roadmap in June this year. It will set a long-term pathway towards achieving net-zero emissions as early as 2050. As a reference document, IRENA in collaboration with the Malaysian government released the Malaysia Energy Transition Outlook (METO) in March.

» Other policies relating to energy expected to be released this year in Malaysia include the Natural Gas Roadmap, the Hydrogen Economy and Technology Roadmap and the National Biomass Action Plan.

» Malaysia, Thailand and Cambodia will be putting together their long-term strategy plans in the Energy Efficiency and Conservation Act (EECA) this year, to regulate energy efficiency and conservation in the respective countries. The act will encourage consumers to adopt more efficient equipment and appliances, better manage their energy consumption and reduce wastage. Cambodia’s energy efficiency will establish strategies for upcoming developments and a reduction in energy consumption of at least 19% by 2023. Meanwhile Thailand’s Energy Efficiency Plan will boost energy conservation by 49,000 kilotonnes of oil equivalent (ktoe), from 30% in 2018 to 36% over the next 15 years.

» Countries in this region have scaled up energy funding to unleash sustainable investments for the energy transition. At the G20 2022 summit in November 2022, Indonesia launched the Energy Transition Mechanism (ETM) Country Platform to collect investments from public and private sectors, mobilise funding, and channel fiscal support for climate action. The platform has allocated $500mn and circulated over $4bn to close 2-GW of coal-fired power generation by 2040.

» Indonesia and Vietnam late last year signed a Just Energy Transition Partnership agreement to tackle climate change by reducing the use of fossil fuels and developing renewable energy sources. These investments will be used to phase out coal and expand renewable energy to meet 34% and 47% of power generation in Indonesia and Vietnam respectively by 2030.

nation’s inaugural carbon credit auction on March 16. Energy is a critical component of modern society, powering homes, businesses, and industries. But in South Asia, access to reliable, secure and affordable energy remains a significant challenge.

» India’s gas industry is undergoing significant changes as the government pushes for greater use of cleaner fuels and renewable energy sources. There has been a shift towards natural gas with the government taking several measures such as launching the Pradhan Mantri Urja Ganga pipeline project, which aims to connect Eastern India to the national gas grid. The government has also developed several LNG terminals to expand gas supply. Previously, cooking natural gas was only available in the country’s north and west. With a 40% viability gap allowing the nation in this region to access lower prices for CNG and piped cooking gas, the pipeline will extend access to far-off areas including eastern states.

» Pakistan’s government has taken several measures to address the challenges facing the gas industry, including

ensuring a stable supply of gas and promoting the use of renewable energy sources. In November last year, the United Nations Economic and Social Commission for Asia and the Pacific (UNESCAP), the Private Power and Infrastructure Board (PPIB), and the Sustainable Development Policy Institute (SDPI) launched the SDG 7 Roadmap for Pakistan aimed at supporting the government in developing policy measures to achieve the SDG 7 targets. The roadmap suggested the country support greater energy efficiency and expand the share of renewable energy in total final energy consumption to 23.5% in 2030.

» Bangladesh drafted a new Integrated Energy and Power Master Plan (IEPMP) for the 2024-2050 period, to ensure an affordable, sustainable and secure energy supply. Under the draft plan, gas consumption by the energy sector will grow between 160% and 360% to generate 30% of power by 2050. Imports of LNG are projected to grow to 49 MT. With the expected installation of two more privately-owned offshore units and an onshore LNG terminal, the draft plan estimates that about half of the required investment for power generation will go to the gas sector.

» Malaysia’s government has recently lifted the ban on exports of renewable energy, as part of a policy review to spur growth. The government is also raising its 2050 renewable energy capacity target to 70% of the total mix, versus a previous target of 40%.

» In a similar vein, the Ministry of Finance and Monetary Authority of Singapore (MAS) announced the launch of the Finance for Net Zero (FiNZ) Action Plan to mobilise financing to accelerate the net-zero transition in Singapore and elsewhere in Asia. These funds will support expanded investment, lending, insurance, and related services to progressively decarbonise areas such as power generation, buildings, and transportation.

» Meanwhile, Malaysia established a carbon market this year when its Bursa Carbon Exchange successfully carried out the

Global Voice of Gas speaks with Jason Kearns,

Why is Enbridge participating in LNG 2023?

Why is Enbridge the partner of choice for global LNG projects?

Director

LNG Development, Enbridge Inc.

We believe natural gas and LNG have a key role to play in a sustainable energy future. Natural gas is core to the energy transition; to ensure global energy security, achieve net-zero emissions by 2050, and alleviate energy poverty in developing countries.

With less than half the carbon intensity as coal, natural gas has been the single biggest factor in reducing emissions in the U.S. by 20% since 2005. As new coal power continues to be added to the global energy system, LNG can have a similar impact on global emissions—both to displace coal and support renewable power by providing constant, reliable energy source. Enbridge is a strong advocate of LNG, which is why we are a proud sponsor of LNG 2023.

Canada has been slow to act on LNG—is this the right place to host a global LNG conference?

There are few countries as well positioned as Canada to meet the world’s energy needs. We have vast energy resources that are already being produced responsibly, sustainably and to the highest standards concerning people and the environment.

Our energy producers and infrastructure companies—including Enbridge—are second-to-none, and Canada’s environmental regulations are among the most stringent in the world.

In BC, we can produce LNG with a lower carbon intensity than anywhere else in the world by using the province’s abundant hydroelectricity resources to power operations. Not to mention that if Canada really wants to combat climate change, we must set our sights on the 98.5% of global emissions outside of Canada. Canada can make the greatest impact through LNG.

Enbridge has world-class knowledge and experience in energy infrastructure development and operation— from planning, permitting, community alignment, Indigenous engagement, construction, financing, operations and through to market delivery.

have a key role to play in a sustainable energy future. Natural gas is core to the energy transition; to meet growing global energy demand, achieve net-zero emissions by 2050, and alleviate energy poverty in developing countries. ”

—Jason Kearns, Director, LNG Development

What is Enbridge’s experience in LNG?

We have experience developing LNG facilities and operating several natural gas storage facilities supporting LNG exports across Canada and the U.S. Importantly, Enbridge brings to any partnership considerable financial resources, with stable cash flows year after year. We own/operate an extensive ecosystem of pipelines, storage, export terminals and renewable projects in North America and Europe, and we have expertise integrating low-emissions technologies, such as carbon capture and storage, into our value chains. That’s what Enbridge brings.

In the U.S., Enbridge’s natural gas system runs along the U.S. Gulf coast making it an ideal conduit to support growing LNG exports in the area. We currently provide service for 15% of the export capacity at the Gulf Coast through four LNG facilities operating in the region and are poised to serve at least three more based on executed Precedent Agreements.

In Canada, we are a 30% owner of Woodfibre LNG. Our partner on this project, Pacific Energy, is working with our engineering contractor to do site preparation with major construction work scheduled to begin this year. The cool thing with this project is it’s not only going to be net zero on its first day of operation (which very few projects are), but it

has also committed to being net zero during the construction stage of the project by using carbon credit offsets that involve partnerships with local Indigenous Nations. That’s a groundbreaking approach and should serve as a model for others to use. The project will be in-service in 2027.

One of the reasons Enbridge was interested in the project in the first place was because of input and stewardship from the Indigenous Nations, including Sḵwxwú7mesh Úxwumixw (the Squamish Nation). The Squamish Nation is an environmental regulator on the project. It’s a role that was established through the first Indigenous-led environmental assessment in Canada.∙

“We believe natural gas and LNG

> An Enbridge employee carries out routine maintenance work in Lake Charles, LA. on the company’s Texas Eastern natural gas transmission system, Enbridge transports 20% of natural gas consumed in the U.S.

LNG plant developers face added CCS cost challenge

LNG project costs have shown volatility over time and industry is seeking to overcome new challenges in efforts to reduce them. These challenges encompass not just rising raw material, labour and financial costs, but the LNG sector’s embrace of low-carbon initiatives to reduce the industry’s environmental footprint.

LNG plant costs rose in the period 2010-2014, driven in large part by the expansion and high project construction demand in Australia. Subsequently, there was a significant fall in both upstream and liquefaction plant unit costs, as the focus of LNG plant construction moved to the US.

In addition to innovation with small-to-mid-scale liquefaction trains, US LNG benefited from very different upstream conditions as a result of the country’s extensive shale gas development. Projects in some cases could simply plug into the extensive US gas network, a huge

difference from Australia’s often remote offshore gas resources or its foray into coal seam gas. However, liquefaction plant unit costs also saw a fairly consistent decline, aided by another US-specific factor –the existence of brownfield sites housing idle regasification terminals. Much of the infrastructure for new US LNG plants was already in place.

As charted by the Oxford Institute for Energy Studies report LNG Plant Cost Reduction 2014-2018, the combined upstream and liquefaction unit cost of US LNG projects fell with the construction of Sabine Pass Trains 1-4 to under $600/TPA, vastly cheaper than the earlier Australian LNG plants, where costs ranged from $2,400/TPA to more than $4,000/TPA.

Floating LNG also entered the scene, offering a competitive option for remote offshore fields, which would otherwise have incurred large costs in bringing gas to shore.

Carbon capture and storage is gaining favour as a means of LNG plant emissions control. It will add significantly to costs at a time of general inflation, but developers appear willing to shoulder the burden – on the premise that costs fall with wider deployment and technology improvements.

ROSS MCCRACKEN

Disease and war

Step forward another five years and the picture has changed yet again. The coronavirus pandemic wrought havoc with supply chains worldwide, and Russia’s war with Ukraine has added inflationary pressures, as well as sending European demand for LNG through the roof.

This has created the expectation that LNG spot prices will remain elevated, supporting the business case for the construction of new LNG supply capacity. The question now is whether developers can keep their cost base under control.

Even before emissions control is considered, the situation can be challenging:

• The cost of capital has been on an upward trend. Central banks worldwide have been raising interest rates in an attempt to contain inflation. The US Federal Reserve’s federal funds rate had jumped from near zero in March 2022 to a range of 4.755.00% in April 2023.

• Steel prices have been very volatile, rising close to $2,000/T in September 2021 for US hot-rolled coil. They are currently just over $1,000/T, leaving them 30% higher than in the 2015-2020 period. Cement prices in March this year were 36% higher than at the end of 2018.

• Labour costs have also been rising. In the US, wage inflation has not kept pace with consumer prices, but has nonetheless been increasing by a rate in excess of 6% in the period from May 2022 to January 2023.

All-electric drive trains – a no regrets option?

LNG developers are adding a focus to reduce their greenhouse gas emissions. The two principal means of addressing carbon emissions are all-electric drive trains and CCS.

Electric drive trains have a higher initial investment cost than traditional gas turbines used to drive compressors directly, but the advantages can soon roll in. Savings potentially result from more reliable operation, lower maintenance costs, increased shaft power efficiency, better emissions control and lower gas consumption, which allows more gas to be exported as LNG.

The key determining factor for the emissions outcomes from using electric drive trains at LNG facilities

is the source of the electricity. For example, if the electricity can be sourced from renewable sources, then the emissions reductions can really start to mount.

This is the route LNG Canada has taken in its first phase of construction, sourcing renewable power from utility B.C. Hydro. However, a second-phase expansion is expected to use gas-fired generation as there is insufficient electricity transmission capacity to the remote project location.

As LNG Canada CEO Jason Klein said, “If the power was there today, it would be a pretty straightforward decision.”

The same problem is faced by all developers – is sufficient renewable electricity available at or near the site? And, even if it is, this doesn’t mean it will be allocated to LNG.

Norway’s state oil and gas company Equinor has run into problems with its plan to electrify the Hammerfest LNG plant at Melkøya. It wants to use power from Norway’s national grid to replace the use of gas. Norway’s power system is dominated by hydro generation, with an increasing component now supplied by wind power. Thermal generation makes up as little as 2% of the country’s electricity generation, making it one of the world’s lowest carbon power systems.

However, Norway’s parliament in April ordered the company to reassess the options for CCS as an alternative. Opposition to the electrification plan stems from concerns that the plant’s electricity consumption will drive power prices higher and reduce the availability of low carbon power for other industrial developments related to the energy transition. The impact of new

power line construction on indigenous Sami reindeer herding was also a concern.

CCS is the pricier option

Equinor says CCS is the more expensive option although not for reasons which apply generically to all LNG plants. The problem is not the cost of the carbon capture, but integrating the capture unit with the plant, which will require a 170-day shutdown and deferred gas exports. Equinor’s assessment also suggests the need for a new CO2 pipeline, well and CO2 reservoir.

It estimates that adding CCS at the Hammerfest LNG plant would cost 37bn kroner ($3.5bn), of which the capture plant would account for 30%, plant integration including offshore compression 53%, and transport and storage costs 17%.

It also estimates that raw material and supply chain inflation mean the cost would be some 30% higher today than when the initial assessment was made in 2019.

CCS is gaining favour, but costs need to fall

The main sources of carbon emissions from LNG projects are upstream reservoir CO2, emissions from compression and emissions from on-site power generation.

A 5 MTPA LNG plant requires around 185 MW of power capacity for mechanical drive and about 45 MW for power generation. This implies a carbon capture plant with capacity to capture about 1 MTPA CO2, – a size similar to the Boundary Dam coal-fired CCS project in Canada, which cost around C$1.5bn ($1.1bn) and has not been extended to the sites’ other coal units.

While CCS costs are expected to fall, there is little question that pioneering projects, such as Boundary Dam, are expensive. The cost of Chevron’s CCS project at its Gorgon LNG project in Australia has increased to more than A$3.1bn ($2.0bn) and has so far been struggling to meet its storage targets.

As a result, CCS has been thought of as an expensive, often too expensive, option. However, International Energy Agency (IEA) analysis highlights that there is no single cost for CCS, and that CCS can be effectively retrofitted to existing industrial facilities, such as LNG plants, with costs lower for newbuild construction, where CCS can be part of the initial design.

In some cases, storing CO2 captured from the feed gas is the best option, while in others it may be postcombustion capture, or both. Almost all LNG projects

remove CO2 from the feed-in gas source before use. Capturing carbon post-combustion from flue stream gas is more expensive.

Multiple factors will affect individual project costs, for example the proximity of an injection site. The concentration of the CO2 stream is a significant factor and the CO2 streams from LNG plants and natural gas processing are relatively pure, putting CCS for these applications at the lowest end of the cost scale. The IEA puts the cost range for capture at $15-25/T CO2 for concentrated CO2 streams, compared with $40-120/T for more dilute carbon streams.

Policy also plays a big role and US LNG developers have welcomed the recent passage of the Inflation Reduction Act, which increased the 45Q tax credit for capturing and storing carbon. This looks set to spur a range of CCS projects in US gas producing regions, notably the US Gulf Coast. A number of US companies have announced plans for CCS operations at their LNG plants, including Cheniere Energy, NextDecade, Sempra Energy and Venture Global.

It is also notable that all of these companies are active in searching for improved CCS technologies. CCS costs are expected to fall with wider development and greater experience. They need to.

The bottom line is that LNG developers are willing to shoulder an increase in cost in order to put effective carbon emissions controls in place, but not at any price. They are betting that just as they managed to reduce upstream and LNG plant unit costs in the 2014-2018 period, similarly cost containment can be achieved for CCS in the period up to 2030.

Policy also plays a big role and US LNG developers have welcomed the recent passage of the Inflation Reduction Act, which increased the 45Q tax credit for capturing and storing carbon.

The bottom line is that LNG developers are willing to shoulder an increase in cost in order to put effective carbon emissions controls in place, but not at any price.

Canadian LNG poised to join global stage

There is a strong business case for Canada to join the global LNG market as demonstrated by Canada’s largest LNG export terminal, LNG Canada, nearing completion.

Learn more about Canada’s LNG investments at LNG2023 in Vancouver, where the country’s LNG leaders will participate in the conference sessions and be present in the large exhibition.

DALE LUNAN

In the summer of 2022, German Chancellor Olaf Scholz visited Canada, pointing to Canada’s vast natural gas reserves and urging the Federal Government to support LNG export projects to contribute to Germany’s future energy needs.

After meeting with Canadian Prime Minister Justin Trudeau, the two leaders signed a Joint Declaration of Intent, committing the two countries to collaborate in the export of clean Canadian hydrogen to Germany. In turn, later in November, QatarEnergy and ConocoPhillips signed a 15-year agreement to supply LNG to Germany.

While developing LNG on Canada’s east coast – days closer to Europe than any US Gulf Coast export terminal – remains a challenge, LNG on Canada’s west coast

remains vibrant, with the 14 MTPA LNG Canada project now more than 80% complete and three smaller projects with support from First Nations at varying stages of postor pre-FID development.

The LNG Canada project CEO, Jason Klein, will sit down with Canadian Gas Association (CGA) CEO Timothy Egan in a leadership dialogue session on the first day of LNG2023 to discuss the project’s progress, which is set to deliver its first cargoes in 2025. Klein will also provide insight to the project’s key successes and its contribution to global energy security and emissions reductions.

A spokesman for LNG Canada tells Global Voice of Gas (GVG) 196 of 215 modules for phase one of the project have been received, including gas processing units

The site of the planned Woodfibre LNG facility in Howe Sound. Source: Woodfibre LNG

and certain buildings and substations. Nine modules are en route to the LNG Canada site on the shores of the Douglas Channel near Kitimat, BC, while another ten are being prepared for ocean transport.

All large modules from the Qingdao fabrication yard have been received, with the project’s final 19 modules to come from the Zhuhai fabrication yard in China.

LNG Canada and the three other projects, through operational and process innovations and access to renewable electricity from the BC Hydro grid system, will produce LNG with the lowest carbon emissions profile, setting a new global LNG emissions standard.

Woodfibre LNG

The 2.1 MTPA Woodfibre LNG facility at Swiy’at, near Squamish, north of Vancouver, is expected to begin construction in September. Liquefaction facilities will be shore-based, with 250,000 cubic metres of floating storage on two converted LNG carriers and a floating workforce accommodation facility.

In March, Woodfibre LNG announced a “tangible plan” to be net-zero by the time it makes its first exports in 2027. This fast-tracked timeline exceeds the federal requirement to be net zero by 2050, while providing benefits to local First Nations, British Columbians, and Canadians.

Woodfibre LNG’s Roadmap to Net Zero also follows the Province of British Columbia government’s announcement of a new Energy Action Framework, which requires proposed LNG facilities in or entering the environmental assessment process to develop and submit a credible plan to be net zero by 2030.

That roadmap will build on the already low emissions profile of the project, which will use electric compressors in the liquefaction process and incorporate offsets drawn from two nearby nature-based offset projects.

“This roadmap will see Woodfibre LNG be the first LNG export facility in the world to achieve net-zero and includes commitments to be net-zero both through the construction stage of the project and during operations,” Woodfibre LNG said.

Woodfibre, owned 70% by Singapore’s RGE Group through its Pacific Energy subsidiary and 30% by Canadian midstream infrastructure company Enbridge, also has significant First Nation support, and is the first major industrial project in Canada to receive environmental approval from an indigenous group. The Squamish First Nation, on whose traditional territory the

project will be built, performed its own environmental assessment, alongside a joint federal-provincial review, and issued an environmental certificate in 2018.

That First Nation support, CEO Christine Kennedy tells GVG, is critical to the success of any Canadian LNG project.

“Recent circumstances around the world have highlighted energy vulnerability for our trading partners,” she says. “it is up to all of us to show genuine, meaningful partnerships with the indigenous government whose territory we work in and to show how we can do projects like this in the context of current government policy aspirations – how we minimise carbon emissions, how we ensure that issues and concerns are addressed.”

Woodfibre’s modules are being built in a Chinese fabrication yard owned by McDermott International, its main contractor, Pacific Energy executive vice president Ron Bailey tells GVG. The project has five major modules and some smaller ones, he says, and all the parts will be pre-tested in China before being shipped to the project site in Howe Sound.

“We’ll be doing much of the pre-conditioning in China,” he says. “Our site is quite challenging from a space standpoint, and we want to get as much done before we bring modules to site.”

Woodfibre LNG also has a significant volume – 70% – of its offtake secured under a pair of binding sale and purchase agreements with BP, Bailey says, with a third SPA being negotiated to cover a portion of the remaining 30%.

“We’re looking to get as much as we can out of this plant,” he says. “You never contract fully because you don’t want to be over contracted, so there will be some spot volumes and we’ll look to see where those can land.”

Cedar LNG

A short distance up the Douglas Channel from LNG Canada is the site of the 3 MTPA Cedar LNG project, the first LNG facility in the world with a significant First Nation ownership position. Haisla Nation, on whose traditional territory both LNG Canada and Cedar LNG are located, owns 50% of the project, in partnership with Pembina Pipeline, a major Canadian energy infrastructure company.

Federal and provincial environmental approvals for the project were received in mid-March, and a final investment decision (FID) on the C$3bn project

is expected by the end of Q3 2023, Stu Taylor, senior vice president, marketing and new ventures for Pembina Pipeline tells GVG

“We’ve got a lot of work – we have the regulatory side, we have our commercial side, we have our engineering side and we have our finance path,” he says. “As things go, we’ve got a lot of work to do in a short period of time, but we remain optimistic of that Q3 FID.”

Taylor says Cedar LNG is “really close” to announcing preliminary offtake agreements, but in the meantime has executed a memorandum of understanding with Montney producer ARC Resources for a 20-year liquefaction services agreement for about 200 mmcfpd of natural gas, or about 1.5 MTPA of LNG.

“ARC’s asset quality, leading ESG performance and financial strength, are important attributes in an LNG partner and will help drive our project forward,” Cedar LNG CEO Doug Arnell says.

Like Woodfibre, Cedar LNG will be powered off the BC grid, but unlike Woodfibre, Cedar will be a floating LNG facility, with a single vessel supporting both liquefaction facilities and up to 250,000 cubic metres of LNG storage.

Feed gas will be supplied to Cedar LNG through an 8.5 km pipeline connecting to the CGL pipeline near the LNG Canada terminal. First permits from the BC Energy Regulator have been received for the pipeline, which will deliver about 400 mmcfpd of natural gas to Cedar LNG.

Ksi Lisims LNG

About 140 air km north of Kitimat lies Pearse Island, and on the northern tip of that island, not too far from the BCAlaska border, is where the Nisga’a Nation, Rockies LNG Partners and Houston-based Western LNG want to build the 12 MTPA Ksi Lisims floating LNG project.

Ksi Lisims LNG received a 40-year natural gas export licence from the Canada Energy Regulator (CER) in December 2022, providing for maximum annual exports of 22.4 bcm and term exports of nearly 780 bcm.

The project proponents filed their initial project description with the BC Environmental Assessment Office (EAO) and the Impact Assessment Agency of Canada (IAAC) in the summer of 2021. Under a substitution process, the EAO will conduct the environmental review of the project on behalf of the federal government,

beginning with the preparation of an environmental assessment. That process is just getting underway, and a decision on an environmental assessment certificate is not likely until 2024 at the earliest.

Ksi Lisims LNG will be powered by electricity, making it one of the lowest emitting, large scale LNG production facilities in the world, Western LNG CEO Davis Thames tells GVG. It also has ambitious net-zero plans.

“Through the development of nature-based offsets, the project is working to become net-zero, and we’re aiming to achieve that milestone a full two decades before the federal government’s 2050 target,” he says. “Our work with government on electrical transmission improvements also stands to hugely benefit clean energy development in northwest BC.”

The Nisga’a Nation is one of only a handful of BC First Nations with a modern treaty with the provincial and federal governments, and as such is self-governed, which provides for a “uniquely collaborative” approach to industrial developments, Thames says.

“Together, we’ve created an exciting partnership that adds tremendous strength, certainty, and expertise to our project,” he says. “It’s an innovative governance model that stems from our core belief that everyone should have the opportunity to improve their lives, and our partnership does that by providing clean, secure, stable, and responsible energy to global markets while planting a seed of prosperity for the Nisga’a Nation and indigenous people of Canada’s northwest.”

For Rockies LNG, a consortium of six western Canadian natural gas producers together producing about 3 bcfpd, or 20% of total Canadian production, Ksi Lisim LNG represents an opportunity to diversify away from traditional North America markets in favour of more lucrative markets in Asia, which are out of reach of most Canadian producers without access to liquefaction and export facilities, CEO Charlotte Raggett tells GVG

“The Montney and Duvernay formations are the main source of the natural gas that the Rockies LNG partners plan to export through the new Canadian west coast LNG terminal,” she says. “These are prolific fields, but their distance from the main gas-consuming regions of North America means that the product often sells at a discount – receiving full value for the produced resources matters to all Canadians.”

Another key benefit, Raggett says, is the opportunity to contribute to the global climate change solutions. Drawing on technological innovation, higher efficiency

and Canada’s strict regulatory limits o fugitive emissions and flaring, Canadian natural gas is less carbon-intensive than gas from most other producing regions, she says.

“Pairing this with a net-zero liquefaction facility means that exporting LNG from Canada can significantly reduce global greenhouse gas emissions by displacing higher emitting fuels, or LNG from more carbonintensive supply regions,” she says. “Northern BC’s relative proximity to Asian markets, when compared with the US Gulf Coast, also reduces transportation costs, energy consumption and shipping emissions.”

The environmental benefits that all three of these Canadian LNG projects will bring to the world are confirmed by a Wood Mackenzie report in November 2022 which showed that Canadian LNG exported to northeast Asia to displace coal use would reduce emissions by about 188 MTPA of CO2, or about 29% of Canada’s annual emissions.

That’s enough of a business case, the consultancy says, to leave the door open for even more Canadian LNG to Asia.

“There are still promises for Canadian projects, especially with the changing global market dynamics,” says Dulles Wang, director of Wood Mackenzie’s Americas gas and LNG research team. “From the west coast, the shorter shipping time to Asia compared to the US Gulf Coast offers logistical, economic and emissions advantages.”

LNGCanada Refridgeration Module

An alternative future for LNG infrastructure

The conversion of LNG infrastructure to handle hydrogen holds promise, but it also presents some significant technical and

of Kobe, although others are planned in South Korea and Australia.

However, US company Chart Industries says that its integrated pre-cooled single mixed refrigerant mid-scale modular liquefaction technology could be used to liquefy hydrogen with some adjustments. Moreover, it estimates that it would be at least 50% cheaper to convert existing LNG infrastructure to liquefy hydrogen than to build dedicated new hydrogen liquefaction projects.

Some LNG producers, such as Cheniere Energy and Sempra Energy, have already expressed an interest in entering the nascent market for internationally-traded hydrogen.

Liquefying hydrogen requires chilling it to -253°C, significantly lower than LNG’s 161.5°C, a factor expected to add to both liquefaction and vessel costs. Moreover, liquefying natural gas consumes less than 10% of its energy, but this proportion increases to about a third for hydrogen. At 3.5 kWh/m3 hydrogen is less dense than natural gas (11.4 kWh/m3), so the same volume would contain far less energy, meaning that more carriers would be needed.

This could make the cost of seaborne trade in hydrogen challenging to bear. The International Renewable Energy Agency, for example, thinks that trade in hydrogen by 2050 will be roughly equally divided between pipeline delivery and ammonia carriers. Ammonia is corrosive and toxic, but has lower thermal insulation requirements than LNG as it becomes liquid at only -33°C.

Cost estimates uncertain

NEIL FORD

LNG’s role in the energy transition remains in the balance. Security of supply concerns have solidified its bridging position, and the fuel remains essential for the reduction of coal-fired generation, notably in Asia, and as a stabilising generation source for variable renewables. However, to safeguard its longer-term role, developers, both on the export and import side, are assessing the integration and conversion possibilities for lower-carbon liquified gases such as hydrogen and ammonia.

These efforts aim to address concerns that new LNG import infrastructure – which is being rapidly deployed in Europe in the wake of Russia’s war in Ukraine – will be stranded or perpetuate the use of unabated natural gas. Converting LNG infrastructure for hydrogen and/ or ammonia use could future-proof new LNG investment

needed today and reduce the costs of the energy transition by efficiently re-using existing assets.

Conversion possibilities

The main focus for LNG infrastructure centres on the possibility of converting existing LNG export and import terminals and vessels to handle hydrogen and ammonia shipments.

In liquid form both hydrogen and LNG projects need cryogenic equipment, but the International Energy Agency says that the conversion of existing or planned LNG infrastructure is “technically challenging” and “requires replacement or drastic modification of most of the equipment”. At present, there is only one small prototype liquid hydrogen import terminal – at the Japanese port

The lack of existing conversion, liquefaction or regasification projects means that it is difficult to estimate costs. However, a study by the Fraunhofer Institute for Systems and Innovation published in November 2022 on behalf of the European Climate Foundation, estimated that about 70% of LNG import terminal investment could be used within a converted ammonia terminal, falling to 50% for conversion to liquid hydrogen, based on the cost share of the LNG tank.

The Fraunhofer Institute recommended that LNG import terminals be designed at the outset to be easier to convert to hydrogen or ammonia, including by building storage tanks out of compatible materials such as special stainless steel.

This is particularly important as storage tanks are the most expensive element of LNG import terminals.

Moreover, “additional thermal insulation of the tank is required or a higher boil-off has to be accepted” on liquid hydrogen conversion, the institute said.

Japan’s IHI Corporation is considering converting its LNG import terminals and storage facilities to handle ammonia sometime between 2025 and 2030. IHI aims to use ammonia as a thermal power plant feedstock, describing it as “a carbon neutral alternative to coal and gas-fired power plants because its combustion emissions are free of carbon dioxide”. It added: “Converting LNG facilities should drive ammonia uptake by slashing costs and ensuring effective land usage.”

Pipelines currently used for natural gas transport would also have to be converted to handle the different temperatures and pressures of hydrogen and ammonia. Fittings and valves are usually designed for specific operating conditions and so must be technically sealed to handle hydrogen, as hydrogen molecules are smaller than those of methane, or indeed than any other molecule, and leaked hydrogen would fuel climate change, as well as pose safety concerns.

Control valves have to be recalibrated to limit the hydrogen leakage rate, while helium can be used to test for potential leaks. Connecting parts can also be welded together and checked via x-ray radiation. A fracturemechanical inspection of the steel is needed in hydrogen pipelines, but not for natural gas pipelines, as hydrogen has a 20-30 times higher crack growth rate, according to the Fraunhofer Institute.

Dutch natural gas infrastructure operator Gasunie recommends using only high alloy chromium nickel steel to manufacture hydrogen pipelines to avoid hydrogen embrittlement, increasing costs slightly in comparison with natural gas pipelines. Pipelines also have to be kept very clean, such as by using dry ice, to avoid hydrogen contamination.

Finally, pipeline flow velocity has to be increased as hydrogen and ammonia are less dense than natural gas. Natural gas pipelines have a pressure level of 70-100 bar depending on age, but hydrogen pipelines need to be up to 100 bar.

Ammonia technologies tried and tested

Current enthusiasm for ammonia is based on using it as a fuel, particularly in shipping, although it is currently mainly marketed as fertiliser. However, it could also be converted back into hydrogen for use as a motor fuel, in heating and in steel production and other industrial

economic challenges. While different pathways are being explored, the possibility of using hydrogen-derivative ammonia is also being assessed as a potentially more practical and cheaper option.

applications. Converting hydrogen to ammonia in the export country and back again in the intended market would require investment in cracker equipment, which would require more investment and consume more energy.

Ammonia is easier to liquefy and has a liquid energy density partway between that of LNG and hydrogen. There is already some seaborne trade in ammonia. The Fraunhofer Institute and BNEF have concluded that conversion of LNG terminals into ammonia terminals is technically and financially feasible, with BNEF estimating 6-20% additional investment to achieve ammonia retrofitting.

In a report on converting LNG import terminals to handle ammonia, Black & Veatch said that storage tanks can be modified to hold ammonia, although they would have lower working capacities. In addition, it recommended the boil-off gas (BOG) system be fully evaluated to identify the proper compressor configuration to avoid inefficient BOG compressor operation. Finally, it said that the instrumentation and measuring devices should “be evaluated in detail to ensure their functionality with ammonia”, with some components replaced.

According to the Ammonia Energy Association, ammonia can be transported by pipeline at half the cost

DESIGN ®

of natural gas because of the smaller pipeline diameter required. By comparison, it estimates hydrogen pipeline transportation costs at double those of natural gas and so four times those of ammonia pipelines. Although there is currently no European ammonia pipeline network, the US network already extends to over 4,800 km and carries 2 MTPA, mainly for the fertiliser industry. As such, ammonia use at industrial scale is tried and tested.

Moreover, the technical and economic challenges posed by converting LNG infrastructure to hydrogen and ammonia use have to be seen in the context of both the high cost of hydrogen production by electrolysis using renewable power and the need it would create for additional renewable generation capacity. Emissions from producing hydrogen from natural gas can be addressed through carbon capture and storage and at a lower cost than current electrolysis technologies.

As a result, how the future production and distribution of low carbon gases evolves is highly dependent on the economic cost trajectories of numerous, often competing, technologies. But given its scale and the experience of liquid gas handling, the LNG industry is well placed to play a major role, leveraging existing assets to create new supply chains based on existing infrastructure investments.

The LNG industry is well placed to play a major role, leveraging existing assets to create new supply chains based on existing infrastructure investments.

To Buy or not to Buy? Europe’s Quandary over LNG

‘To be or not to be? That is the question. Whether ‘tis nobler in the mind to suffer the slings and arrows of outrageous fortune, or to take arms against a sea of troubles, and, by opposing, end them?

- Hamlet, Shakespeare

Europe is in a quandary about whether to sign up longterm LNG contracts or to depend increasingly on spot purchases and portfolio supplies. Thus far European buyers have been relatively reluctant to sign long-term LNG contracts. And as a result of their reticence, it is the so-called ‘aggregators’ or portfolio players who are currently underwriting many of the long-term LNG offtake contracts needed to underpin liquefaction investments. Europe faces the proverbial prisoner’s dilemma: If too many European players underwrite more long-term supply, it could tip the global LNG market to oversupply in the late-2020s, which would cause prices to drop and leave those very contracts out of the money. However, if Europe avoids contracting for more long-term offtake, aggregators will potentially have growing leverage over European buyers. The dilemma is more acute since there is a trade-off to be made between contracting for shorter or for longer tenures. If Europeans do not wish to take on long-term commitment given expectations of declining demand for natural gas, they could negotiate shorter-

term deals with the aggregators — but that comes at a mark-up.

It has been striking that Europe’s direct role in the recent resurgence in global LNG contracting has been relatively minor despite the Russian–Ukrainian crisis. Rather, Asian buyers and aggregators (consisting of IOGCs and traders) have been the biggest participants signing up for offtake capacity since 2021.

More recently, the G7 discussions regarding a possible halt or ban on Russian gas imports to Europe, including LNG, have added greater urgency to the question of whether Europe should increase its direct long-term offtake of non-Russian LNG.

At the heart of this discussion is Europe’s challenge to meet its longer-term decarbonisation goals while ensuring security of energy supply. Given Europe’s aggressive decarbonisation plans, European buyers are uncertain about future demand and are therefore hesitant to make long-term LNG offtake commitments. Additionally, European utilities face a lack of legal clarity regarding

MICHAEL STOPPARD, GLOBAL GAS STRATEGY LEAD AND SPECIAL ADVISOR, S&P GLOBAL COMMODITY INSIGHTS

ANDRES ROJA, RESEARCH AND ANALYSIS ASSOCIATE DIRECTOR, S&P GLOBAL COMMODITY INSIGHTS

ANUSHA DE SILVA, ASSOCIATE DIRECTOR, NORTH AMERICA GAS, POWER AND ENERGY FUTURES, S&P GLOBAL COMMODITY INSIGHTS

Data compiled Jun. 05, 2023. Pre-FID at ttime of contract signing. Source: S&P Global Commodity Insights. 2023. © S&P Global.

their residual contractual commitments to take Russian pipeline gas, which is further discouraging Europe from signing up for long-term LNG supplies.

European buyers account for just 10% of the 96.5 MTPA signed globally in pre-FID firm offtake — comprising sale and purchase agreements (SPAs) and liquefaction tolling agreements (LTAs) — since the start of 2021, based on assumed destination. By comparison, Asian buyers make up 44%. However, portfolio buyers with multiple assumed destinations also account for 44%, indicating that these volumes can become available as needed to Europe or other markets over time (see figure 1).

For projects within the United States, which has led the recent global contracting rebound from the supply side, Asian end-users make up nearly 40% of the 61.6 MTPA in firm offtake (SPAs) contracted by third parties for pre-FID US projects (at the time of signing) since the start of 2021. IOCs and trading firms together account for a further 30%. European end users represent 19%, which is a material share, but is half that of Asian end users (see figure 2).

Moreover, if we focus on more recent deals since the start of the Russia–Ukraine crisis, aggregators took the biggest share signed since the start of 2022, accounting for 35% of US pre-FID projects’ firm contract signings (see figure 3).

This strong demand for US supply is supported by the liquid US natural gas market, favorable price differentials at Henry Hub versus markets in Europe and Asia, and the flexible destination contracting offered by US project developers.

Data compiled Jun. 05, 2023. Pre-FID at ttime of contract signing. Source: S&P Global Commodity Insights. 2023. © S&P Global.

Europe takes the plunge

Some European players have taken the plunge. They have contracted LNG from four US export projects since the start of 2021: Venture Global’s CP2 LNG and Plaquemines LNG, Sempra’s Port Arthur LNG, and NextDecade’s Rio Grande LNG. All these deals are for FOB delivery, which means that the offtakers must arrange shipping and have the flexibility to deliver those volumes to their destination.

By opting for FOB supply, new market entrants are having to make a splash into LNG tanker newbuilds. Moving into shipping is a major step in terms of both financial commitment and operational skill-set. Also, the sector may have strong economies of scale difficult for a buyer to exploit. Take as an illustrative example, EnBW’s 2 MTPA of offtake from its Plaquemines LNG

and CP2 LNG SPAs, which will require long-term charter agreements for four tankers to service these contracts. RWE’s 2.25 MTPA of offtake will require up to three tankers. These shipping arrangements are sufficient to cover delivery to Europe but not necessarily sufficient by themselves to support switching opportunistically to distant Asian markets. More established market participants, such as Engie, are utilising their existing fleets and adding to it in order to service their various offtake agreements.

Chartering and operating a fleet of LNG tanker will not make sense for all buyers, or even be affordable.

The evolving US LNG model: FOB to DES?

Meanwhile US LNG project developers also are looking to cut out the aggregators by moving into shipping. This dynamic may reflect developers’ ambitions to offer Delivered Ex-Ship (DES) LNG contracts to buyers who are not interested or are unable to take a shipping position. This offering could help secure further SPA signings and differentiate some US Gulf Coast LNG projects from others. It could unlock new buyers in Europe reluctant to assume the shipping commitments. In the past, we have seen some project developers such as Cheniere expand across the LNG value chain and take positions in shipping and regasification terminals, becoming fully integrated. Additionally, project developers can use surplus production volumes that are not assigned to long-term offtakers to take advantage of market opportunities.

Shipping gives the seller a significant level of optionality, which in a growing spot LNG market can increase trade margins substantially. This dynamic became quite evident during the run-up in spot LNG prices during the second half of 2022, when having access to shipping options gave FOB buyers the

flexibility to seek the highest paying market. LNG project developers were able to benefit from the incredibly high spot LNG prices during 2022, due to their shipping fleet. Considering the four US projects for which European buyers signed pre-FID firm offtake in 2021–23, the potential peak export volumes surpass announced nameplate capacity by nearly 18 MTPA.

• Venture Global has five 200,000-cbm vessels on order, which equates to an estimated 3–3.2 MTPA (assuming a 50/50 split in deliveries between Northeast Asia and Northwest Europe). That surpasses the company’s requirement to fulfil its only announced DES contract to date, a 1.2 MTPA DES SPA with Sinopec. This situation may indicate that Venture Global plans to sell volumes for its own account. This strategy is a departure from the other US Gulf Coast project developers which so far are more narrowly focused.

• Sempra Infrastructure, in contrast, has no announced new ship-build orders or charters associated with its Port Arthur LNG project, which has signed only FOB deals to date.

• NextDecade’s Rio Grande LNG project has signed one DES contract to date — a 1 MMtpa SPA with Guangdong Energy Group — out of 10.8 MTPA in firm offtake contracts. Where disclosed, the project’s other offtake contracts are FOB.

Conclusion: The battle for midstream control

Aggregators are performing an important role. They provide the long-term underpinning to enable new FIDs of LNG projects. However, both project developers and buyers are wondering whether to rely upon them or whether to consider taking on an extended role themselves to avoid the ‘slings and arrows’ of volatile spot markets.

Figure 1: Global pre-FID firm offtake contracts signed: 2021-23 to date by assumed destination

Figure 2: US LNG pre-FID offtake contracts signed since 2021 by buyer type

Figure 3: US LNG pre-FID offtake contracts signed since 2022 by buyer type

At the heart of this discussion is Europe’s challenge to meet its longerterm decarbonisation goals while ensuring security of energy supply.

LNG as shipping fuel: a future-proof investment?

Fuel oil is finally giving way to cleaner alternatives in shipping, and momentum continues to build behind LNG as the most popular of these alternatives.

JOSEPH MURPHY

This article is brought to you by the International Gas Research Conference (IGRC2024), the International Gas Union’s flagship Gas Innovation Conference, taking place in May 2024 in Banff, Alberta, in Canada. International innovations in gas and related technologies will underpin IGRC2024. Subscribe to join here to get updates on call for abstracts, conference programme and registration.

Shipping has traditionally been considered a relatively conservative industry, which treads carefully when investing in new modes of operation. Understandably so, as the investments made today will be with the operators for many years into the future, and need careful evaluation. But in recent years, the industry has undergone dramatic accelerated changes as shipowners adopt cleaner alternatives to fuel oil to tackle their emissions in reaction to stricter regulations and increased customer and investor pressure to deliver meaningful reductions in greenhouse emissions and air pollution. The landmark piece of regulation for air quality improvement was the International Maritime Organisation (IMO) 2020 requirement that the upper limit of sulphur content in shipping fuel should be lowered from 3.5%

to 0.5%. IMO 2020 gave shipowners a choice – continue using fuel oil but with a lower sulphur content, invest in exhaust gas cleaning systems or switch to alternative, cleaner fuels. (sulphur is the key contributor to air pollution, contributing to the exhaust of the toxic sulphur oxide (SOx) and particulate matter (PM)). By far, LNG, which releases no SOx, has been the most popular of these alternatives.

The following year, the IMO introduced additional requirements aimed at reducing the carbon intensity of shipping by 40% by 2030 versus the 2008 level.

Of the 275 newbuilds capable of running on alternative fuels that were ordered from yards last year, 222, or 81%, were LNG-fuelled, according to Norwegian classification society DNV.

In addition to the practical elimination of air polluting emittants to meet the IMO Sulphur regulation, LNGfuelled engines can reduce overall greenhouse gas emissions – primarily CO2, methane and nitrous oxide – on a well-to-wake basis versus oil-fired engines by 20-30% for two-stroke slow-speed engines and 11-21% for fourstroke medium-speed engines, a 2021 analysis by ESG lifecycle specialist Sphere estimates.

Other, fuels such as hydrogen and ammonia can offer even greater environmental advantages on the GHG front in the future, but these are technologies still being commercialised. LNG provides a valuable immediate solution, because it is already available and production can be scaled relatively fast, while major infrastructure for the supply and bunkering already exists. And this infrastructure is growing at a quick pace. According to shipping services specialist Clarksons, 185 ports worldwide were capable of bunkering vessels with LNG in January 2023, up from 141 a year earlier. And a further 50 ports are due to join them by 2025.

Despite its advantages, though, the use of LNG as a bunkering fuel has faced criticism. The main argument against its adoption is that doing so locks in hydrocarbons in shipping for longer, and that moving from fuel oil to LNG to the likes of hydrogen, ammonia and methanol will take more investment than leapfrogging straight to the latter options.

However, most infrastructure used now for LNG can be repurposed in the future for bio-LNG and synthetic LNG cost-effectively, providing an accessible future-proofing for investments made today. A study published in October last year by the Maritime Energy and Sustainable Development Centre of Excellence (MESD CoE) at Nanyang Technology University (NTU), Singapore, estimated that pure bio-LNG could be used to meet 3% of shipping fuel demand by 2030, and 13% by 2050, taking into consideration fuel availability, cost, lifecycle emissions and logistics. And if blended in a 20% ratio to standard LNG, those shares rise to 16% and 63% respectively.

“Our research concludes that bio-LNG, produced from sustainable biomass resources, has the potential to meet a significant proportion of future shipping energy demand,” associate professor Jasmine Lam at MESD CoE commented on the report. “The findings show that bio-LNG is among the cheapest sustainable biofuels and

can potentially offer significant cost advantages over electrofuels by 2050.”

A 2020 study by CE Delft, commissioned by SEALNG, calculated that the global maximum sustainable supply of bio-LNG far exceeds the forecast demands of the shipping sector in both 2030 and 2050, but also suggested that enough could be produced in its lowest output scenario.

The CE Delft study estimated the current cost of biomethane at $19-49 per mmBtu when anaerobic digestion is used, and $24-63 per mmBtu when gasification is used, but projected that this would fall to $15-21 and $13 respectively by 2050, as a result of upscaling and further development of gasification technologies.

As for synthetic e-LNG, availability will be dependent on how quickly renewable electricity capacity is expanded, and how much of that capacity is spare after grid needs are satisfied. But the same can be said of other electrofuels such as e-methanol and e-ammonia. The bulk of the cost of e-LNG, e-methanol and e-ammonia is associated with renewable hydrogen production costs, putting them on a fairly level playing field in terms of affordability. Estimates for the future cost of synthetic methane vary significantly, according to CE Delft, at anywhere between $23 and $110 per mmBtu in 2030, and $15-60 in 2060.

Innovations in biomethane and synthetic methane production, particularly with regards to the latter, can help drive down costs further. And this will further strengthen the case for these fuels as a means of combating shipping emissions, therefore future-proofing the investments made in the LNG bunkering chain today.

At the same time, much work is taking place all across the gas supply chain to analyse how to adapt its infrastructure to also support other types of low and zero carbon gas (e.g. hydrogen, ammonia) and gaseous mixtures.

These topics will be addressed at length in the IGRC2024 Conference, and we encourage experts from all over the global gas chain and the broader energy community to submit their innovative projects and ideas to the ongoing Call for Papers, which is open until DATE.

The gas industry welcomes change and encourages bold ideas to be showcased at the International Gas Union’s Tri-Annual International Gas Research and Innovation Conference in Canada next year.

How LNG can deliver global emissions cuts

CHARLES ELLINAS

LNG has a critical role to play in the global energy mix until at least 2050 and likely beyond. With global energy markets shaken by the Russia-Ukraine conflict, interest in LNG as a secure and highly flexible energy source has grown further. This ever-increasing demand is outpacing available supply and is feeding a massive expansion in LNG facilities, both for liquefaction and regasification.

A plethora of scenario-based assessments (see figure 1) show global natural gas demand, including LNG can vary over a wide range, from 1 to 6 tcm in 2050. But broadly, these scenarios can be divided into two categories:

• Those that show how things could evolve if current trends continue. In effect, these are forecasts based on where the world was in 2022 and where these known trends and policies could lead, without assuming a possible outcome.

• Those that show how the world must move to achieve net-zero by 2050. They start with a desired outcome, limiting global warming to 1.5°C by 2100 and achieving net-zero emissions by 2050, and work backwards to the realities of 2022. In effect, they are backcasts, attempting to determine what needs to be done to achieve the end result

Broadly, forecasts show gas demand by 2050 will vary in the range of between 3.5 and 6.0 tcm. The backcast range is 1.0-2.5 tcm.

Of course, neither of these two types is right or wrong or predict what may actually happen. Over the short-tomedium term, though, forecast-type scenarios are likely to be more correct. These show gas demand will continue exceeding 4 tcm in 2040, similar to current levels.

But at some stage, the world is expected to switch

The goal of the energy transition can best be achieved by combining LNG and gas with renewables in order to ditch coal.

Figure 1: Natural gas demand to 2050 according to scenario-based assessments

from where it appears to be headed towards a lowercarbon future. When this happens natural gas demand will lose market share, but will not disappear. It will still play an important role.

Why is this important? Gas – and LNG – is shown by most credible scenarios to play an important role in global energy demand all the way to 2050 and beyond. It continues to be used by industry, but also as a fuel for heat and to support power generation as intermittent renewables take an increasing share of the load.

Natural gas – and LNG – is preferable to coal and oil as it produces much less emissions. About 40-50% less CO2 than coal and 30% less than oil. It does not emit particulates and emits insignificant amounts of other harmful substances in comparison to coal and oil.

LNG is essential for energy transition

With global energy demand rising, the goal of the energy transition is to deliver reliable energy while reducing emissions. This can be best achieved by combining LNG and gas with renewables, with gas/LNG replacing coal. With energy security propelled to the forefront as a result of the Russia-Ukraine conflict, the world is increasing the share of LNG vis-a-vis piped gas, with its share expected to more than double by 2040.

Solar and wind energy generation systems are intermittent, generating electricity only when the sun is shining or the wind is blowing. There is a lack of commercially viable options to store large amounts of electricity for long periods of time to compensate for cloudy and windless periods. As a result, as the contribution to energy from variable renewables increases, so does the need for natural gas and LNG.

Power generation based on natural gas offers the reliability, flexibility and increased dispatchability –ability to control output – that complements intermittent renewable energy power generation, especially when it replaces coal.

In addition, the technologies required to completely replace all uses of fossil fuels in other sectors, such as industry, transport and heating, are still decades away.

As long as fossil fuels are needed, switching from oil and coal to gas and LNG, where possible, is the most effective and immediate way to minimise greenhouse gas (GHG) emissions (see figure 2). With nearly 40% of electricity globally still generated using coal, there is ample opportunity to reduce emissions by switching to natural gas and LNG. The G7 energy ministers placed particular emphasis on the phase-out of coal from power generation at their meeting in Japan on April 16.

They reaffirmed their “commitment to achieve a fully or predominantly decarbonized power sector by 2035, and prioritising concrete and timely steps towards the goal of accelerating the phase-out of domestic unabated coal power generation.”

The case for LNG can be strengthened further when combined with carbon capture and storage (CCS) to manage emissions. For these reasons, LNG is essential to providing reliable, flexible and stable energy supplies during energy transition and to the drive to reduce emissions.

LNG as a marine fuel

With the marine industry under pressure to reduce emissions, LNG is becoming increasingly important in shipping, as it emits about 25% less CO2 than conventional marine fuels in providing the same amount of propulsion power. This has been recognised in recent years, with the adoption of LNG as fuel increasing, especially in newbuild ships. This helps meet regulatory requirements, reduce emissions and improve air quality. With less than ten years to achieve the target to reduce GHG emissions by 40% by 2040, set by the International Maritime Organisation (IMO), LNG is becoming the fuel of choice to support decarbonisation. Tackling LNG’s

emissions footprint will be important to ensure its role in shipping. This requires the ability to track and optimise emissions across the supply chain.

Addressing methane emissions

Emissions of methane during oil and gas production and transportation contribute between one fifth and one eighth of the methane emissions from human activity, and methane is a serious contributor to climate change.

Methane is 28 to 36 times more potent than CO2 over 100 years, and 80 times more over 25 years. Driving down global emissions of methane represents a great opportunity to reduce the short-term climate warming.

Natural gas and LNG are clean fuels that can serve as partners to renewables during transition, but if there are methane leakages and emissions this claim is challenged. Minimising these should be a first order priority for all companies. Gas and LNG can be part of the solution only if they deal with methane emissions effectively.

The European Commission’s methane strategy aims to increase the regulatory pressure and requirements to monitor, report, and verify methane emissions to enable effective compliance with reduction targets.

The G7 energy ministers too placed particular importance on this. They said “We will work with the relevant stakeholders to develop an internationally aligned approach for measurement, monitoring, reporting, and verification of methane and other GHG emissions to create an international market that minimises GHG emissions across oil, gas, and coal value chains, including by minimising flaring and venting, and adopting best available leak detection and repair solutions and standards. This internationally aligned approach would aim to improve the accuracy, availability, and transparency of emissions data at the cargo, portfolio, operator, jurisdiction and basin level, including consideration of accepted protocols and tools such as independent verification that can support robust data collection and reporting. We will also support the development of policies, measures, and industry efforts to reduce methane and other GHG emissions from fossil energy Re: IGRC2024 presence at LNG2023 production, consumption, and international trade.”

Around 150 countries have also now joined the Global Methane Pledge, which aims to reduce methane emissions from all human activity by 30% from 2020 levels by 2030.

United StatesChinaEuropeIndiaRest of the World

Figure 2: CO2 savings from coal-to-gas switching in selected regions (2010-2018)

Canadian LNG:

Energy security, emissions reduction and Indigenous opportunity

The world needs more liquefied natural gas (LNG), and Canada has the resources to help.

Canada can supply reliable, responsibly produced, low-emissions LNG to Asia and beyond, strengthening world energy security and improving the lives of Canadians, including Indigenous Peoples, for decades to come.

“The world is waiting for Canada,” said Yamanouchi Kanji, Japan’s ambassador to Canada.

“Canada can and should play a very important role to support the energy situation not only in Japan and South Korea, but the world.”

Looming LNG shortage

Global LNG demand increased to 397 million tonnes in 2022, about 16 million tonnes more than 2021, according to Shell’s latest industry outlook. France, the U.K., the Netherlands, Spain, Belgium and Italy led the growth. Europe’s demand continues to grow as governments scramble to reduce reliance on energy imports from Russia. Germany alone has six new floating LNG storage and regasification terminals that are to come online by the end of 2023.

Shell’s analysts expect LNG to become a “pillar of energy security” in Europe going forward.

Meanwhile, demand in Asia will continue to rise as an alternative to coal in emerging economies. Without sufficient investment in new LNG projects, a shortage is expected before the end of this decade.

Total world LNG demand is expected to reach 700 million tonnes by 2040, a more than 75 per cent increase from 2022.

“Starting in 2027, we see there’s going to be a global supply/demand gap that is probably going to grow to 120 million tonnes per annum and about 150 million tonnes per annum by 2035,” said Matthias Bloennigen, Wood Mackenzie’s director of Americas upstream consulting.

“Developing western Canadian LNG would be helpful to alleviate the LNG demand that’s going to develop in the world.”

Indigenous leadership: Everyone wins

Indigenous communities are leading the future of Canada’s enormous LNG potential, with ownership positions in major proposed projects like Cedar LNG, Ksi Lisims LNG, and the Coastal GasLink pipeline when it is completed this year.

Everyone wins with the expansion of Canadian LNG development, said Karen Ogen, CEO of the First Nations LNG Alliance. There can be less international reliance on less responsible producers like Russia, and a reduction in the use of coal that will lower greenhouse gas emissions.

“Indigenous people are in support of major projects,” said Ogen, former elected chief of the Wet’suwet’en First Nation. “We must do this responsibly, continuing to make sure that we have the highest environmental standards.”

Of key importance to her is an increase in employment opportunities and the ability to effectively address social issues in Indigenous communities. LNG development benefits Indigenous communities and the world, said Crystal Smith, elected chief councillor of the Haisla Nation. The community is a 50 per cent owner of Cedar LNG, which would be the first Indigenousled LNG project in the world.

“Our territory is not in a bubble and protected from what is happening in Asia and India with coal burning,” she said. “Cedar is not only important from a Haisla perspective, [but from] a global perspective.”

Reducing emissions

Natural gas produces half the emissions of coal-fired power, according to the International Energy Agency (IEA). It is also a dependable baseload fuel that can offset the intermittent nature of renewables to fortify the reliability of energy systems.

LNG from Canada could reduce emissions in Asia by 188 million tonnes of CO2 equivalent per year – or the annual impact of taking 41 million cars off the road, according to Wood Mackenzie.

“It’s like taking all of the cars in Canada away, if we were able to build all of those projects,” Bloennigen said.

“It reduces emissions globally, so it’s for the good of everyone.”

Reducing climate impact

A 2020 study by Wood Mackenzie found Canadian LNG exports could reduce net emissions in Asia by 188 million tonnes per year through 2050 — the annual equivalent of removing:

100% of cars off Canada’s roads

Nearly 3x B.C.’s total emissions in 2020

29% of Canadian emissions

188 million people flying Vancouver to London

Canadian LNG is expected to have among the world’s lowest emissions per tonne, thanks to:

Colder climate making supercooled liquefaction easier

Shorter shipping distances to Asia & Europe compared to the U.S. Gulf Coast

With responsibly produced, low-emissions LNG, Canada can help meet growing demand, improve energy security, and help fight climate change. By replacing less environmentally friendly energy like coal with LNG, we could remove 188 million tonnes of carbon emissions every year through 2050.

Canada can lead the LNG industry with faster shipping times from our coasts, Indigenousled projects, hydroelectricity, and lower emissions from natural gas production.

Leading methane emissions reduction by upstream natural gas producers

Use of low-emission hydroelectricity

See how we’re charting our course at MadeTheCanadianWay.ca/LNG

The industry is addressing its methane problem, responding to the pressure placed on it with practical and promising initiatives and commitments. Beyond individual company targets, a number of voluntary industry initiatives have been formed. One example is the Oil & Gas Climate Initiative (OGCI), whose participants pledged in 2018 to cut their methane emissions intensity to 0.25% by 2025. When they surpassed that target in 2020, they raised their ambition to 0.2% by mid-decade.

There are also various voluntary gas certification initiatives in play, such as MiQ and Project Canary, which reward companies for addressing their methane emissions.

Low-carbon LNG

Since Shell delivered the first “carbon-neutral” LNG cargo to Tokyo Gas in 2019, there has been rapid growth in “low-carbon” LNG deals worldwide, driven mostly by end-users.

Low-carbon LNG allows buyers and sellers to counterbalance LNG emissions through carbon credits to offset emissions from the LNG supply chain, such as reforestation and renewable energy projects. But this trade is facing scepticism and could benefit from greater transparency and consistency, which can limit its value as a solution to emissions from the LNG industry, despite its appeal.

Carbon pricing is another factor that drives emissions reduction in LNG processes. This puts pressure on LNG companies to strike a balance between costs and emissions intensity.

Legislation, shareholder requirements and project

financing terms increasingly require that LNG cargoes include extensive information about the CO2 emissions associated with their production and delivery.

This makes it important to reduce the CO2 intensity of gas operations. New greenfield projects can achieve this by incorporating energy efficient equipment, facilities that use clean electricity, lowering emissions of pipeline operations with electrification for compressor stations and improving efficiencies of liquefaction operations with efficient turbines and compressors, and use of CCS. For example, the Qatar LNG expansion project includes CCS and boil-off gas recovery systems.

It is estimated that life-cycle emissions for an average LNG cargo – including upstream production, liquefaction, shipping, regasification, and combustion – is 250,000 T of CO2 equivalent. Increasingly, with lower-carbon footprint set to have an advantage in the marketing of LNG, in an effort to improve measuring and reporting of the carbonfootprint of LNG cargoes, producers and suppliers are including emissions reporting within contracts and commercial processes.

As the need for LNG grows and pressure on companies to reduce their environmental and carbon footprint increases, so will the attractiveness of lowcarbon LNG, enabling LNG to realise its full potential in the global drive to reduce emissions.

As the need for LNG grows and pressure on companies to reduce their environmental and carbon footprint increases, so will the attractiveness of lowcarbon LNG, enabling LNG to realise its full potential in the global drive to reduce emissions.

As the need for LNG grows and pressure on companies to reduce their environmental and carbon footprint increases, so will the attractiveness of low-carbon LNG.

“The Caribbean Case for LNG”

can make these questions impossible to answer – but you don’t have to go at it alone.

S&P Global Commodity Insights has integrated research and solutions to help you navigate the leagues ahead in the natural gas and LNG markets. Our insights span from real-time news, to outlooks out to 2050; from granular pipeline data, to global trade flow fundamentals. Use our data platforms to explore infrastructure developments, compare assets and develop long-term strategy. And, with benchmark price assessments, negotiate with the confidence that only true market value can bring

Where

There is a pragmatic case for incorporating LNG as part of the energy transition in the Caribbean. While sustainable energy has well-defined financial, social, environmental and economic benefits, the region faces significant challenges in making a transition to renewables. Not all energy transitions look the same -one size does NOT fit all. Small Caribbean islands cannot adopt wholesale a standardised model of transition to renewables, as they all have different geographical characteristics and economic circumstances.

While new renewable energy installations may be less costly than imported fossil fuel options, when the cost of energy storage is taken into consideration, the value proposition vanishes. While the use of rechargeable batteries has great future potential, costs have not yet fallen to the level that would make batteries viable for power supply throughout the night. Countries need dispatchable power sources that:

• are controllable (i.e. the generation source can operate to its maximum capacity, or anywhere in between, depending on the needs of the system);

• are firm (i.e. there is a high confidence that the generation capacity is available as needed); and

• have the required flexibility (i.e. power generation can ramp capacity up and down as needed to fulfil supply requirements).

Simply put, the need for dispatchable power and consistently supplied and stable energy at night, along

with the cost of new infrastructure and technical capability/capacity issues, limits the economic viability of renewable power generation.

While some countries can potentially utilise continuous renewables such as geothermal energy or hydropower, not all countries have that advantage, only having access to non-continuous renewables.

This is where LNG comes in. CARICOM countries that want to eliminate the use of heavy fuel oil (HFO) and diesel but lack options such as geothermal and hydropower can choose natural gas as LNG to achieve lower emissions and cleaner power. Using LNG can extend the life of existing infrastructure at affordable and (through contracts) predictable costs. Moreover, LNG does not present the storage challenges of nondispatchable energy sources.

Trinidad and Tobago is uniquely poised by virtue of its location and infrastructure to continue to export LNG to both large markets, and eventually, to small-scale markets. Even for Caribbean countries with geothermal and hydro resources, where 100% renewable power generation may be eventually feasible, natural gas can still play a role in the transition. For other net fuel importers, natural gas in the form of LNG can be a cheaper, cleaner substitute than the diesel and HFO currently used, at least until battery storage becomes competitive for sustained night-time supply. For these countries, that time is still far away.

What lies ahead for natural gas in China

Natural gas will play an increasingly important role in reducing China’s emissions and guaranteeing its energy security, but to fully enable this benefit, there must be enhanced planning of the gas and energy systems, further reforms and greater market integration.

time, however, as a result of the COVID-19 pandemic.

The supply outlook

China has an abundance of various types of natural gas resources, meaning there is great potential to further increase reserves and production. The outlook for long-term production is determined by the Natural Gas Production & Supply Prediction System, an analysis tool developed by CNPC, which considers different types of resources and multiple scenarios. This provides a basis for national energy and natural gas industry development planning.

According to this analysis, conventional natural gas production will peak around 2030, at 200-220 bcm. Global upstream practices put the share of proven gas reserves in well-developed basins at 30-60%. Chinese coal-bed methane (CBM) production continues to grow slowly and is on track to reach 10-15 bcm by the end of the decade. If there is a debottlenecking of development technologies, it could reach 15-20 bcm. Shale gas production should reach 40-50 bcm in 2030 and 60-80 bcm in the longer term. All told, Chinese natural gas production is forecast to reach 270 bcm in 2030 and be maintained at around 300 bcm in the long term.

and it is expected to take 30 years to reach peak the CO2 emissions before 2030 and another 30 years to reach carbon neutrality. As one of the most important green and low-carbon energy sources, natural gas will be positioned as the country’s main energy source, and the sector’s development under China’s 13th Five-Year Plan has been a remarkable achievement. Growth in natural gas consumption has been rapid with significantly increasing gasification rates. Natural gas market reform, increased and more diversified imports and greater storage capacity all lay a solid foundation for the further development of gas as the main energy source during the current 14th Five-Year Plan period.

LNG: the key contributor to gas in China

NATIONAL PETROLEUM CORPORATION

China’s natural gas reserves have continued to grow at a peak rate over the past decade, with proven reserves increasing each year on average by 960 bcm. Domestic natural gas production too is increasing fast, rising on average by 10 bcm each year, over the last six years. In 2022, it reached 220 bcm. At present, the natural gas reserves to production ratio is above 30, meaning there is a firm foundation for further acceleration in production growth. Unconventional gas reserves will play a central role in future production increases.

The urgent demand for cleaner energy has driven the rapid growth in Chinese natural gas consumption,

primarily to replace coal, which has been the backbone of the economy for decades. Between 2008 and 2021, demand increased from 81.3 bcm to 372.6 bcm, growing at an average annual rate of 12.4%. Growth stagnated in 2015 and 2016 as a result of a weaker global economy and lower oil prices, but in 2017, Chinese gas demand once more returned to rapid growth, ushering in a second golden era for gas in the country amid stronger economic performance and a series of favourable national policies. Rising coal and crude oil prices were also a contributing factor. Between 2017 and 2021, annual absolute growth exceeded 30 bcm. In 2022, consumption fell for the first

The critical role of gas in China

Accelerating the development of natural gas is a realistic way of ensuring that CO2 emissions peak before 2030 – a goal that has been set as part of China’s carbon neutral roadmap. At the top of the decarbonisation agenda will be restricting coal consumption and achieving a peak in coal emissions as quickly as possible. Gas-fired power generation is expected to play a key role in achieving this, in light of its significantly lower CO2 emissions per unit of 798 g per kWh. China is expected to install 400 GW of gas-fired power generation by 2060, and the emissions of these plants can be further lowered through the deployment of carbon capture and storage (CCS).

Coal-to-gas switching began in China in the year 2000,

As a result of soaring spot prices, huge market fluctuations and sluggish economic growth, China’s LNG imports in 2022 decreased by about 15.5 MT year/year – a sharp decline of nearly 20%. In March 2023, LNG imports rose 16% yr/yr, breaking the 14-month declining streak. However, due to weak market fundamentals and the still relatively high spot price, a double-digit growth for the full year is still highly uncertain. Most of this growth will come from new long-term contracted volumes. The tight market environment of high spot LNG prices is likely to lead to buyers seeking a greater share of term supply in their portfolios. According to S&P Global, China’s LNG demand is projected to grow to 85 MT in 2025 and 120 MT in 2030.

The way forward

1. Strengthening top-level design and advancing the natural gas chain

China’s natural gas industry is still in the early stage, albeit of very rapid development, which is characterised by fast-growing production, import volumes, consumption, pipeline transmission capacity, storage and other industrial chain elements, as well as the gradual expansion of applications. The corresponding pricing

LIU HE SENIOR FELLOW, THE RESEARCH INSTITUTE OF EXPLORATION AND DEVELOPMENT (RIPED) OF CHINA

NATIONAL PETROLEUM CORPORATION

ZHANG GUOSHENG PROFESSOR, THE RESEARCH INSTITUTE OF EXPLORATION AND DEVELOPMENT (RIPED) OF CHINA

The urgent demand for cleaner energy has driven the rapid growth in Chinese natural gas consumption.

mechanisms, laws and regulations are being determined, implemented and piloted in regions. The future gas industry is expected to be built as highly flexible and prosperous.

In light of the above, China’s natural gas industry planning should be a matter of national energy security strategy, with a greater focus on its top-level design. An overall and systematic plan will be formed to guide production, imports, supply, storage, price mechanisms and consumption, to ensure a rational market economy.

2. Reforming the pricing mechanism and balancing profits across the natural gas chain

The natural gas price is affected by the transmission cost and the discount value in different regions. Particularly in recent years, during the season of peak gas consumption, the current market discount mechanism has exacerbated market disorder during the “gas shortage” period. Upstream producers, on the one hand, have faced the pressure of ensuring secure supply, and on the other hand, have struggled with lower profits. Meanwhile, the pipeline and sales sectors in the midstream and downstream have enjoyed a larger proportion of profits due to the low degree of market opening and insufficient competition, while earning dividends from rapidly growing consumption. Moreover, regional monopolies and the bundling operation mode of urban distribution networks and government pricing mechanisms has led to decoupling of upstream and downstream prices. Due to the current mismatch between upstream supply cost and the downstream sale price, plus different subsidy mechanisms for various users, the downstream regional operating enterprises have hindered the upstream operators from developing supply rationally.

The effective solution is to deepen the reforms

for the whole industrial value chain by streamlining administration, delegating more powers to upstream and downstream enterprises, and improving regulations and optimising services relying on the national pipeline network company PipeChina. Upstream operators should be encouraged to produce more and replenish their reserves by optimising profit distribution and giving them stronger bargaining power, and the downstream market should be improved by opening it up to competition.

3. Expanding the natural gas system

At present, natural gas supply in China is characterised by near-source consumption. Domestic natural gas mainly flows in western production areas, while imported pipeline gas is distributed along those pipelines, with priority of supply given to areas such as Beijing, Tianjin, the Yangtze River Delta and the Pearl River Delta. In coastal areas far away from gas production areas, consumption growth mainly depends on the expansion of LNG imports. There are insufficient gas interconnections, and so regional market separation is still prominent. From a macro industrial development view, energy strategy should focus on fully integrating systems for domestic gas, imported pipeline gas and imported LNG supply with other midstream and downstream infrastructure. This can enable the development of more natural gas hubs and trading centers throughout the country, to create a more dynamic system linking production and supply sources to end-users. A national gas network should be developed that is similar in scope to the smart state power grid, where gas is supported by other energy sources and new technologies such as big data and artificial intelligence are deployed.

From a macro industrial development view, energy strategy should focus on fully integrating systems for domestic gas, imported pipeline gas and imported LNG supply with other midstream and downstream infrastructure.

Canadian natural gas key to a clean, secure energy future

Natural gas has a critical role to play in meeting the world’s energy demands – and Canada is poised to be the ideal provider, bolstering energy security and lowering emissions across the globe. Not only does Canada have an immense, low-cost resource base, but our energy industry is currently producing among the lowest GHGand methane-intense natural gas on the planet. And with our commitment to continuously improving our environmental performance in all areas, Canadian natural gas will only become cleaner.

Canadian upstream natural gas producers have already made tremendous strides on the environmental front. At Tourmaline, Canada’s largest natural gas producer, we are proud to be a leader in sustainability –a role evidenced by our recent achievements. We have reduced scope 1 emissions intensity by 41% since 2013 while increasing production by 490%. We have also reduced our methane emissions intensity by 26% between 2018 and 2020 and are now targeting a 55% reduction by 2027, using 2020 as a benchmark. Tourmaline also recovers and reuses more than 95% of water used in completions and we plan to eliminate the use of fresh water throughout our core gas operations. Conserving and protecting land is also a priority. Among other initiatives, we minimize surface impact by drilling multi-well pads rather than single-well pads, expanding existing facilities rather than building new sites, and paralleling existing pipeline rights-of-way whenever possible.

The efforts that Tourmaline and our peers have been making to produce the most environmentally and socially responsible natural gas possible have catapulted Canada into the very top tier of climate sustainability rankings among major gas exporters, according to the MIT Green Future Index, which ranks countries on their progress and commitment toward building a low-carbon future. Similarly, Canada’s LNG facilities will have world-leading emissions intensities. Canada is also home to the Natural Gas Innovation Fund Emissions Testing Centre, a firstof-its-kind initiative providing cleantech start-ups the

ability to test and validate emissions- measurement and -reducing technologies for the energy industry. These projects have served as models to the world. But Canada is a world leader in another critical aspect: economic reconciliation with First Nations. At Tourmaline, for example, we aim to go above and beyond as we strive to achieve our goal of shared prosperity. We continuously engage with all First Nations, Inuit, and Métis whose traditional territories may be impacted by our operations in Alberta and British Columbia; we endeavor to hire Indigenous vendors, contractors and partners who work in the communities in which we operate; and we are investing in the next generation of Indigenous leaders by offering scholarships for students from Alberta and British Columbia pursuing post-secondary education anywhere across Canada.

In Canada, Indigenous involvement in all natural gas initiatives, from production to export, is a priority. Indeed, many First Nations communities hold significant ownership in Canada’s upcoming LNG projects and are helping to spearhead their development. Our industry is committed to building prosperity and working hand in hand with Indigenous communities to ensure Canada’s energy opportunity benefits everyone.

For these reasons and more, Canada is the ideal partner for a secure energy future – and Tourmaline is the ideal producer for the growing, global natural gas and LNG market. We are dedicated to responsibly developing Canada’s world-class assets and producing energy North Americans and international citizens can feel proud to use. Because in addition to selling our low-emission natural gas in Canada and the United States, in 2023 Tourmaline began supplying LNG internationally through a unique cross-border marketing arrangement with Cheniere Energy, the leading producer and exporter of LNG in the United States. As we look to the future, we are excited about Canada’s natural gas – and we are eager to share it with the world

McDermott is one of the most experienced and innovative EPC firms serving the market and a world leader for e-drive and NetZero LNG facilities. Our unrivaled design and build expertise spans the entire LNG value chain, from state-of-the-art liquefaction facilities, to cutting-edge storage and distribution terminals.

Norsepower: an innovative solution to decarbonising shipping

Tuomas Riski, CEO of Norsepower, discusses with Global Voice of Gas how Norsepower Rotor Sails harness the power of the wind to make shipping more fuel efficient and cleaner.

JOSEPH MURPHY TUOMAS RISKI, CEO OF NORSEPOWER

Take us through Norsepower’s story since its founding in late 2012. What is its mission statement?

Like every good business, Norsepower exists to solve a problem. In Norsepower’s case, it’s how to costeffectively decarbonise shipping.

From decades of competitive sailing in my spare time, I knew how vital it is to have proven, trusted, and safe solutions to operate effectively. And, now that the maritime industry is facing its biggest environmental challenge in generations, it’s important that the technologies to drive this can deliver on their promises.

After a conversation with Norsepower’s founding team, including Professor Dr H.C Kai Levander, who raised the notion of modernising the Flettner rotor technology, I saw the potential to viably adapt this technology for the global shipping community and make a genuine impact.

We have a clear vision: mission is to use our technology to reduce the environmental impact of

shipping. And right now, we’re delivering on this vision to save fuel – and the planet - with ambitions to achieve this one fleet at a time. We’re also passionate about proving our word with hard evidence to give ship and cargo owners confidence in their choices. Since our physical installations began in 2014 we have amassed a bank of performance data which we are proud to say have been verified by respected bodies such as ABB, NAPA, and Chalmers University.

How did Norsepower develop its clean Rotor Sail Solution technology and how does it work?

The Flettner rotor was first devised in the 1920s. Its capabilities were showcased in 1926 when a vessel used only Flettner rotors to cross the Atlantic.

Our Norsepower Rotor SailTM has given this concept a modern spin – literally. In fact, the Magnus effect – the same principle curve on the football during motion –underpins the product. For instance, when wind meets

the spinning installation, the air flow accelerates on one side of the Norsepower Rotor Sail and decelerates on the opposite side.

When wind conditions are favourable, the captain can throttle back main engines, and the rotor sail can pick up the slack, saving fuel and reducing emissions while providing the power needed to maintain speed and voyage time. A variable electric drive system, powered by the ship’s low-voltage network, rotates this.

So, the Norsepower Rotor Sails are modernised versions of the Flettner Rotor with several patented special features which ensure their durability, safety, and maintenance costs. Add to this a comprehensive aftersales support package underpinned by the hardworking team spread globally and the effective use of data and insights, and you have a solution that meets the commercial and environmental needs of modern shipping.

Let’s talk in numbers how Norsepower’s technology can reduce emissions from the shipping industry and generate other benefits?

Norsepower Rotor Sails provide a reliable, easyto-operate auxiliary wind propulsion system with a proven savings record. We have saved 5,500+ T of fuel, resulting in 17,400+ T of CO2 reduction, with these figures receiving confirmation from third parties, including ABB, NAPA, and VTT.

Furthermore, Norsepower Rotor Sails can typically produce 5-20% average fuel savings. Under the right weather conditions, one customer has reported savings of up to 70%. These aren’t just carbon savings – it’s important to note that it can drastically reduce harmful emissions such as SOx, NOx, and particulate matter from ships. This is achieved as the solution directly replaces the main propulsion power from fossil fuels. Beyond the fantastic emissions reduction potential, the system is highly automated to minimise the crew’s additional workload and maximise efficiency. Meanwhile, a clear and important benefit is that leading classification societies, including LR, confirm that it is robust, durable and safe to use onboard a vessel.

What about its applications for LNG shipping (LNGfuelled ships, LNG bunkering ships, LNG carriers)?

The Norsepower Rotor Sail product is suitable for most LNG-fuelled vessel types ranging from tankers, bulkers, cruise vessels, RoRos, RoPax vessels, general cargo vessels, and ferries with over 30,000 vessels on the

water today that can benefit from the technology. The genius of our product is that the only requirements for Norsepower Rotor Sail installation are deck space for the installation of the foundation, and electrical power connection to the ship’s electrical grid, and therefore, as long as we have a willing customer, we can make this work.

In fact, we would argue that we are an immediate solution for some of LNG shipping’s challenges. For example, LNG carriers pose unique challenges as many use their cargo as a fuel source while cargo shrinks as it travels due to inevitable boil-off, making it vital to travel quicker. By retrofitting LNG carriers with Norsepower Rotor Sails, we can enable LNG carriers to travel faster while maintaining fuel consumption at the current rate, with the product reducing fuel consumption depending on the route and conditions.

Meanwhile, Norsepower is working with Dalian Shipbuilding Industry Co. Ltd. to deliver single Rotor Sails onboard two newbuild LNG-powered, windassisted CO2 carriers commissioned by the Northern Lights JV. Following calculations, Norsepower estimates the Norsepower Rotor Sails will reduce the fuel and CO emissions from each vessel by approximately 5%. The Norsepower Rotor Sails will be delivered in 2023, and following further building, both the 130m long ships, each with a cargo size of 7,500m delivered in 2024.

What are some key case studies to demonstrate the value of Norsepower’s technology?

Norsepower stands out among our competitors because we have over 100,000 hours, demonstrating our product’s ability to reduce emissions by 20-25% or even more as opposed to being still on the drawing board in some instances.

One particular example is the RoRo SC Connector, Sea-Cargo, where we retrofitted two of Norsepower’s largest 35m tall Rotor Sails. The Norsepower Rotor Sails onboard SC Connector are the world’s first tilting Rotor Sails enabling vessels to pass under bridges.

As a result of our successful installation, the SC Connector saved 13.5 tons of fuel within a week, with an overall fuel saving of 20-25%. In fact, due to the great weather conditions on the route, the vessel can enjoy emissions reductions of up to 70%. But don’t just take our word for it as the captain of the vessel declares regarding the Norsepower Rotor Sail: “I have absolutely no doubt that this technology is working.”

BUILDING VISIBILITY OF GAS AND GAS FOCUSED TECHNOLOGY AS A PERMANENT AND GROWING PART OF THE GLOBAL ENERGY MIX

Natural gas can continue to play its significant economic and environmental role in the global energy mix for decades to come, offering clean, secure, and affordable energy for global citizens.The extent to which the industry demonstrates and effectively communicates the key role of gas in a sustainable energy future, against the backdrop of a groundswell of anxiety about climate change, environmental, economic security, and political risks will determine theextent of its continuing success.

Gas Pathways is being developed with a view to becoming the authoritative, credible, and fact-based national and international communications platform amplifying the innovation agenda around gas energy –and gas energy infrastructure; demonstrating that the natural gas sector is focused about making affordable energy available to all, and about maximizing resiliency in energy delivery.

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Global Voice of Gas

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