The article below by Peter Stewart was published on Interfax’s Gas Daily Briefing on 7 August. Peter is the founder and owner of Resource Economist Ltd, a training company. He worked as chief energy analyst with Interfax since 2012, and is an external consultant at the company.
Skills gap challenges oil and gas majors
As new graduates thumb through job listings after their university graduation ceremonies, fewer of those with advanced digital and engineering skills are looking to the oil and gas sector for employment.
That risks problems ahead. Skills shortages have recurred in the gas and LNG sector in recent years as projects have become more complex. But the need to mesh the use of fossil fuels with intermittent renewables and demand-side management in the power sector will throw up huge technological challenges in the near-future.
In its Energy Barometer 2019 survey, issued in July, the Energy Institute identified that a more flexible energy system would be required to meet future energy needs.
Digitalisation is seen as vital for integrating intermittent renewable energy sources such as solar and wind into a system that has traditionally been powered by coal and gas. Data analytics, big data, and digital connectivity skills were seen as priorities by many of those who responded to the survey.
But Airswift, a recruitment company specialising in the oil and gas sector, points out a growing demand for similar skills in other sectors.
“This isn’t just a problem for oil and gas,” it said in a web post. “Europe alone is going to need 346,000 more data scientists by 2020, according to IBM’s The Quant Crunch report, and 28% of all digital jobs by that point will require specialist data science skills”.
Upskilling
In the UK, the Offshore Petroleum Industry Training Organization (OPITO) – an industry-owned association – issued a report in May outlining the need to upskill the existing oil and gas workforce in key sectors including data science, data analytics, artificial intelligence, machine learning, robotics, material science, remote operations and cyber-security.
Other areas that OPITO says need an injection of talent are change management, control of change, project management and the social aspects of change. The UK Oil & Gas Authority’s plan to sustain oil and gas production on the UK Continental Shelf also emphasises big data and artificial intelligence. The OPITO report, Workforce Dynamics: The Skills Landscape 2019-2025, highlights the need for a more flexible, multi-skilled and technology-enabled workforce.
It is estimated the UK oil and gas industry will have to attract 25,000 new people by 2025 even though – because of staff attrition and retirement – the overall workforce will drop to 155,000 from 170,000 in 2018. Around 4,500 of the new jobs will be in roles that do not yet exist.
With 80% of people currently working in oil and gas still expected to be in their jobs in 2025, OPITO believes that upskilling will be key to meeting the demand. One of the biggest problems faced by the oil and gas majors is that many millennials entering the market see the oil and gas sector as being on the wrong side of the climate debate, with an uncertain future because of Paris agreement commitments.
The recruitment websites of the big oil and gas companies typically feature images of a diverse workforce with an emphasis on renewable energy and alternative-fuel vehicles.
Diversity in the sector is a key challenge. Only 25% of the UK oil and gas workforce is female. Gender balance is seen as crucial to attracting those with the best skills, but progress remains slow. Although the proportion of women in the industry is expected to rise to 30% by 2025, many at the top are unhappy.
Appalling. Absolutely awful
“The oil and gas industry is appalling. Absolutely awful. It’s pretty much the worst sector for diversity in terms of gender and ethnicity,” Steve Holliday, the former head of National Grid, was quoted as saying in Oil & Gas UK’s online magazine, Wireline.
But the problem of skills shortages extends beyond the UK. The Global Energy Talent Index (GETI) – published by Airswift and Energy Jobline in March this year – said cuts to graduate recruitment and apprenticeships when oil and gas prices plunged in 2015 and 2016 had also created engineering skills shortages for the sector, and salaries were rising as a result.
The report cited the Permian Basin, where companies are struggling to fill their workforce needs, as a warning sign for the industry. “Even higher salaries aren’t attracting the professionals needed,” the report said. Nearly half of those who responded to the GETI survey said they were worried about an impending talent crisis, with 40% believing a skills crisis existed already and an additional 28% expecting it within the next five years – particularly in Europe, Asia and South America.
Green Careers: What are the Opportunities? When and Where?
Green Careers Week was held between 7th and 12th November 2022. Peter provided an overview of green jobs in the UK energy sector as well as some specific opportunities in the fields of heating and transport.
This inaugural event was supported by prestigious partners from around the UK, including the Royal Society and the Met Office. The goal of the event was to raise awareness among teachers and young people of career opportunities that will result from the emerging technologies that are being driven by the Energy Transition.
Young people are passionate about taking action on climate change; surveys suggest that nearly two-thirds of them are ‘worried’ or ‘extremely worried’ about the climate crisis. The conference organizers want to highlight the amazing career pathways they can follow for a sustainable future.
Peter Stewart
Founder, Resource Economist
Peter worked for more than 30 years as an energy and commodities analyst, before becoming a work and careers coach. He has served on the Managing Council of the British Institute of Energy Economics, and has written widely about the challenges facing the energy workforce.
We interviewed Mike Burns at CTEC Energy in Newhaven Port. The gasifier project converts plastics and biomass into electricity and heat with significantly lower emissions than a traditional incinerator.
The latest Energy Journal from the International Association of Energy Economics has landed on my doormat with a loud thud. The latest issue is 312 pages long.
In Volume 41, Number 6, I was struck by the paper Are Energy Executives Rewarded For Luck? by Lucas Davis and Catherine Hausman, which looks at executive compensation data from 78 major US oil and gas companies over nearly a quarter of a century. The short answer seems to be “yes” : the paper finds that executive compensation rises with increasing oil prices more than it falls with decreasing oil prices. The paper concludes with a discussion of different executive compensation mechanisms that could be adopted, drawn from the wider literature.
The other paper that grabbed my attention was that on Locational Investment Signals by Anselm Eicke, Tarun Khanna and Lion Hirth. The paper looks at the locational factors affecting investment in power systems. The scope is wide, with analyses from Australia, Chile, France, Germany, India, Mexico, Norway, Sweden, UK and the USA. I haven’t read this piece in depth yet, but I feel that locational factors are underestimated in the literature, so i am looking forward to reviewing this in more detail.
There is plenty of other good material in the latest issue. Yes, I do still get it by post, but that’s the way I like to read things. For those who want the latest edition online, you can click on the link below (only available for IAEE members).
The BIEE’s Oxford Conference is a biennial research conference that seeks to understand the drivers of change in energy, both positive and negative. The conference is aimed at energy analysts, researchers, strategy and policy thinkers from all backgrounds, including industry, academia and research organisations, government, the finance community, NGOs and consultancies. BIEE conferences are renowned for the quality of their speakers, for their open, productive discussion and debate and for the diverse range of participants. It is the mix of people and perspectives that makes this conference distinctive.
‘The conference is a fantastic opportunity and melting pot for people in the energy industry, from government from academia from other research organisations. One of the real advantages and one of the special features of the BIEE conference is it’s a place where all of those energy interested people come together. They learn from each other they spark off each other and they build new networks and new coalitions to help drive the energy sector forward.’
Professor Matthew Leach
Conference Theme
This research conference will focus on building the foundations and policies of the low carbon transition aimed at achieving a net zero carbon society in a way that is fair and just. It will address how we live, work and travel, and how policy, infrastructure and the private sector can respond to enable the transformation of heat, transport and industry.
Now we have all been impacted by Covid-19, it is clear that how we recover from this public health crisis will reshape how we tackle the climate change crisis. In the immediate term, there has been a sharp fall in economic activity and emissions. But the long-term impact depends on how low-carbon investments are affected, and whether opportunities are taken to reinforce some of the (positive, for the environment) behaviour changes that have been observed in lock-down (such as increased remote working and cycling) or to tackle some of the potentially negative impacts (reduced use of public transport).
The conference will consider how the transition has been impacted by the COVID-19 pandemic, how economic recovery plans might accelerate the transition, and if governments are backing up the rhetoric in delivering plans for a green recovery. It will look at international perspectives and what can be learnt from the experiences of other countries and market sectors.
COP26
The conference was originally scheduled for 24th September 2019 but was postponed due to the Covid-19 epidemic and the need for social distancing. The conference will now be taking place seven months before the important UN Climate Change Conference, COP26, which is being held in Glasgow in November 2021.
It will also follow the publication of the CCC’s Sixth Carbon Budget in December 2020 which will set the path to the UK’s new net-zero emissions target in 2050, as the first carbon budget to be set into law following that commitment.
Over the course of the year, to demonstrate that it is serious about net-zero, the Government will need to commit to this pathway and firm up its policy plans. The Government will be considering how to achieve the societal transformation required for net-zero which is precisely the focus of the BIEE conference.
For further information please click on the link below:
The 3-day course Crude Oil Valuation and Pricing explains how oil refiners select the crude oils to use in their systems from among the 600 plus crude oil streams that are available globally. Beginning with a review of the chemistry of crude oil, and explaining the various quality parameters of different types of crude oil, this course provides a framework for understanding how refiners evaluate different grades of oil within their overall refining slate. The course goes on to explain the different systems currently used for pricing oil around the world, including the operation of the main benchmark grades of Brent (BFOET), Oman/Dubai and WTI crude.
Course details:
The 3-day course Crude Oil Valuation and Pricing explains how oil refiners select the crude oils to use in their systems from among the 600 plus crude oil streams that are available globally. Beginning with a review of the chemistry of crude oil, and explaining the various quality parameters of different types of crude oil, this course provides a framework for understanding how refiners evaluate different grades of oil within their overall refining slate. The course goes on to explain the different systems currently used for pricing oil around the world, including the operation of the main benchmark grades of Brent (BFOE), Oman/Dubai and WTI crude.
Who should attend?
This course will appeal to producers of crude oil, in particular those seeking to market new grades of oil; market analysts and economists evaluating the different grades of oil available in the market; bankers and investment analysts financing the development of new streams of crude oil; lawyers and accounts involved in the valuation of crude oils; marketers of crude oils; refiners looking to diversify their crude slates.
Key objectives:
The crude oil valuation and pricing course aims to provide attendees with a full understanding of the key crude oil qualities; how these affect refining values; refiners’ approach to selecting crude oils; basic calculation tools such as GPW and refining margin; the use of LP models; use of pricing benchmarks and differentials; assessment methodologies of Platts, Argus and their competitors; use of futures contracts; and basic risk management tools.
A panoply of fuels, from algae to hydrogen, have been identified as potential technologies that can solve the twin goals of meeting the energy needs of an expanding world population while also mitigating climate change and ensuring that future generations can live comfortably.
The big problem with all of these is achieving the scale needed to provide energy for billions of people. It’s all very well to experiment in a lab, but the real challenge of energy is not just to produce it, but to do at scale and economically. This is the case with hydrogen.
Some of the new fuels being developed have been pioneered by large oil and gas companies, raising a real question mark over whether the research and development money being spent is “greenwash”. Algae is an example.
The commodities used to produce future fuels also have alternative uses, raising the prospect of potential competition between supply chains. Biofuels are a good example; using crops to make energy is viable, but not if people are left without food.
Future fuels… Just because it works in the laboratory doesn’t mean that a technology can be scaled up to meet the world’s burgeoning energy demand.
Going Electric
The biggest advances in low carbon energy have been made in the field of electricity. Transport and heat lag far behind.
E-mobility has been talked about for many years, but the portion of the world’s vehicle stock that uses electricity is tiny. Despite the many TV adverts in the west providing racy images of electric vehicles, less than 1% of the vehicles on the road are electric, and most of those in use are hybrids — which means that much of the time they will be using fossil fuels part of the time.
Using electricity is only a low carbon solution, moreover, if the fuels used to generate electricity are low carbon. Charging an electric vehicle using electricity that is generated from coal simply shifts the problem of carbon emissions from the vehicle to the power station.
For the same reason, heating is also a hard-to-decarbonise sector. Replacing a gas boiler with electric heating doesn’t reduce emissions if the electricity is being generated by burning gas. Similarly, while hydrogen boilers will help, if the hydrogen used is derived from fossil fuels rather than electrolysis, the climate benefits are negligible.
Don’t be fooled by the idea that electricity is “greener” than other sources of energy! If it’s generated from fossil fuels, there is little benefit in using it. The carbon saving comes when the power is made from renewable sources such as wind or solar,
Despite the above caveats, a revolution is underway. Electric bikes and scooters have started to proliferate in urban areas, and the range of electric vehicles is gradually improving. Innovative car finance schemes are making EVs viable options for many, rather than the wealthy few. It is still hard to see EVs making inroads in developing countries, but electricity grids are expanding globally and this could provide a tipping point for a more widespreads use of electric vehicles in emerging markets.
Smart Technology
Smart technology refers to a range of technologies that allow energy to be used more intelligently.
For most people, that means a smart meter in the home. If you live in Western Europe, it’s likely that your electricity provider will have supplied one of these already. The reality is, these machines are not very smart. They give you a reading on how much power your are using at any particular time, but not much more.
The real value of Smart Technology comes through when tracking energy use is combined with new systems that can work intelligently together. These are often referred to as “grid edge” technologies. “The grid edge is the hottest area in energy today,” I was told at a conference.
These technologies range from Apps on your phone that allow you to monitor the power going through your home on a room-by-room or even a device-by-device basis, to auotmation procedures that allow you to contract with your electricity supplier to feed electricity back into the grid when you are not using it.
When these are combined with EVs, there is potential for theworld’s car fleet to become a giant battery that can supply electricity back into homes or to companies when renewable systems are under pressure. This could potentially solve the problem of the intermittency of energy sources such as wind or solar power.
Smart meters really aren’t always that smart. The one installed by my power supplier did very little more than blinking at me. I could get a few details about how much energy I had used by pressing some buttons, but nothing that gave me ideas about how to save power or reduce my carbon footprint.
Energy Storage
In the last decade, energy storage has evolved from dysfunctional batteries to large-scale techologies such as pumped water storage and mega batteries designed by entrepreneurs like Elon Musk that provide viable alternatives to wind and solar for power generation. The cost of batteries and of energy storage is also falling rapidly.
The range of car batteries is also gradually being extended, and a range of materials such as selenium have been identified that can be used with standard lithium and cobalt batteries to boost their range and their longevity. These could also potentially resolve the resource constraint around soem of the materials used in batteries, which have limited reserves and are concentrated in only a few countries.
Despite that, the problems around the intermittency of renewables remain, and none of the batteries developed so far as as cost-effective as fossil fuels for back-up power generation.
Energy storage technologies are improving, but are still typically not as cost-effective as using fossil fuels.
Nuclear Horizons
The nuclear industry has suffered from multiple deadly accidents over the eyars, and it remains an extremely expensive form of energy.
The already-tarnished reputation of nuclear power suffered another setback after the Fukushima incident in Japan in 2011. Most of the nuclear reactors in the world today are ageing, and many countries have balked at the cost of building new reactors, particularly given public opposition and the safety risks.
For many people, there is a gut reaction against nuclear from the association with nuclear weapons. The infamous nuclear attack on Hiroshima and Nagasaki by the United States at the end of World War II is sufficent for many to reject the peaceful use of nuclear power.
That said, countries such as France have operated theri nuclear industry with few mishaps. Around 75% of the electricity generated in France is made using nuclear reactors. And significant advances in nuclear fusion are expected in the coming decade.
The renowned environmentalist James Lovelock advocated the use of nuclear energy in his book The Return of Gaia, and even some environmental campaigners see the potential for using nuclear energy to reduce carbon emissions.
Always controversial
The link between nuclear energy and nuclear weapons remains a stumbling block for the widespread expansion of nuclear power. But even for some environmentalists, it is seen as a potential way to reduce harmful carbon emissions.
Carbon Capture
Rather like future fuels such as algae, Carbon Capture (Use and Storage) has been seen both as a potential solution to the problem of climate change and as yet another source of hot air and greenwash.
The reality is that despite decades of promises, there are no examples of successful implementations of CCUS that are of a large enough scale to make any conceivable difference to carbon emissions.
The oil industry has “donated” $1 billion for research into scaling up the multiple pilot projects that have been attempted. But even some of the proponents of CCUS (such as myself) are beginning to wonder if this is just a gesture.
The story goes that, if CCUS can be developed at scale, it will allow fuels such as oil and gas and even coal to continue to be used without damaging the environment. But it is beginning to sound like the oil and gas companies are just kicking the can down the road.
The reality is that CCUS faces many challenges, the most critical of which is, Who will pay? Shell’s CCS venture at Peterhead in Scotland was scuppered when the Tory government that had supported it pulled out at the last minute. But the pilot schemes have also met with public opposition, based on a lack of knowledge of what will happen to the sequestered emissions in the future.
A suspicion of greenwash and multiple challenges
It’s still difficult to tell whether CCUS has a future, or whether it will be another example of the ball being kicked down the road to justify continued investment in fossil fuels.
Earth’s climate is changing, and science suggests that this is almost certainly due to human activities, notably due to the rise in greenhouse gas (GHG) emissions from the burning of fossil fuels.
Despite growing public concern, however, the amount of coal, oil and gas being used continues to rise, and the concentration of carbon dioxide in the atmosphere has reached levels that are close to the levels that most scientists believe will have a serious impact on life on planet earth. Depending on what actions are taken, the level of emissions could double by 2050. Widespread public protests, particularly in advanced western economies, reflect many people’s despair that not enough is being done to slow global warming.
Progress has been made, but it remains limited. This is doubly worrying given that the greenhouse effect has been known about for around a century, and that it is in part anthropogenic (associated with human activity) has been regarded as scientific fact since the 1960s.
The Paris Agreement, drafted in December 2015 and ratified a year later, finally set out pathways to mitigate global warming for the 197 countries that signed up. Since then, the United States has said that it will pull out of the agreement. Two steps forward, one giant leap back by the country that led the world in building a consensus that had been impossible to reach in the earlier rounds of talks which led to the Kyoto and Copenhagen agreements.
Building a consensus for action on the Paris framework is proving more difficult than building a consensus of intent.
Despite signing up to Paris, resource dependent countries such as Russia and Saudi Arabia have been reluctant to translate words into deeds. Environmental activism has become inextricably muddled up with other issues such as human rights and democracy, resulting in a backlash as liberalism has given way to authoritarian populism in countries such as Brazil and the US. The waters have been muddied further by the competing agendas of rich countries, whose development has been fuelled by oil, gas and coal for the last century or more, and poor countries who want to fund their own economic development by exploiting these resources.
Climate Realities
The scientific consensus is that climate change is real, and that it is happening now.
Mindsets
For the last century, energy has been delivered under a centralised system run by powerful companies or state-run institutions.
Energy for mobility has typically been dominated by private enterprise. The Rockefeller fuels monopoly was broken up in the 1920s, creating a model of competing oligopolies that became a template for the capitalist system. The companies that operated the refineries that made the petrol also dominated other transport fuels for airplanes and ships, and petroleum commodities such as petrochemicals and fertilizers. In the 1960s and after, national oil and energy companies emerged, but these typically operate independently even though they are state run.
The state-owned model prevailed in the early years of growth in the power sector, and state control is prevalent in the utilities such as water, gas and communications that operate as natural monopolies. The split between capitalist and communist models after World War II led to a debate about the role of private enterprise, and many countries in the west, including the United States, most European and many Asian companies, have deregulated and/or privatised their utility sectors.
Both the fuels and utility sectors have operated top-down business models with centralised decision-making and where economies of scale dominated business models.
Mindsets
Minsets reflect a way of seeing the world, a kind of prism that determines the visible spectrum. As the energy transition progresses, old ways of thinking are being eroded by new challenges.
The advent of renewable energy was disruptive to the status quo. New technologies such as energy storage are both a threat and an opportunity to the oligopolies who have dominated the energy sector. Meanwhile, the prospect that fossil fuels will be phased out by the end of the present century has led coal, oil and gas companies to reinvent themselves. Faced with this existentiasl threat, radical restructuring is seen by many energy companies as a strategy for survival.
Strength is only one of the aspects of the will, and when dissociated from the others, it can be, and often is, ineffectual or harmful to oneself and other people… In order to go somewhere, one does not proceed by walking in a straight line across open country or by climbing over buildings. One rather studies a roadmap and uses existing roads, which although not in a straight line, can lead one to his (her) destination with the least amount of effort.
Roberto Assagioli
Author of the Act of Will,Founder of Psychosynthesis
Future Leadership
These disruptive changes in the energy landscape require a different mindset from 21st century leaders of energy companies.
In his book Reiventing organisations,
Rather than a CEO working with the board of directors to implement plans that can be rolled out in tiered levels across an organisation, leadership is gradually evolving as a creative process that stimulates and catalyses change at a local level and where decisions from the bottom up are integrated and synthesised.
Of course, there is no single recipe. The disruptive nature of change means that these trends in leadership are emergent and fragmented. The model of organised chaos that has led to such spectacular growth among technology companies can provide only a partial template for the energy sector where the importance of safety is a powerful driver of standardised procedures,
But as the delivery of energy becomes more distributed, and communities have a bigger voice in the forms of energy that serve their local area, energy leaders are becoming more adaptive and flexible. The 20th century model of leaders as deal makers, wielding influence in secret and behind closed doors, is giving way to a new model in which leaders communicate and embody a creative vision.
Companies are changing. It is only in the last 2-3 years that I have heard an executive at the oil company Shell use the word “passion”. The verdict is still out on whether this reflects a change in DNA or a passing management fad.
Times are changing
Traditional leadership models are evolving in the face of disruptive change in the energy landscape.
Business Models
The challenge of leadership is closely related to the issue of what business models are required to run an industry on the scale required to meet world energy needs while still meeting the goal of combatting climate change.
For much of the last century, the energy system oscillated between the twin poles of the “free market” and government “regulation”. These opposed modes of operating reflected divergent narratives. The free market ideology has a story that pits heroic individuals and their corporate correlatives against the suffocating machinations of bureaucracy and the state. Government regulation, in contrast, sees itself as a responsible counterbalancing mechanism that protects individual against the depredations of corporate greed.
These ideological extremes became embedded during the Cold War with individual libertarianism and corporate capitalim opposed to State domination and Communism.
Since then, the yawning gulf between the two ideologies has narrowed. Companies have demanded clear regulation from governments even if it is stringent, provided that the playing field is level. Financial institutions and funds have pressured the big oil and energy companies to do more on climate change. Governments have supported innovation and entrepreneurship as vehicles for the Green Economy.
The old shibboleth of the State vs the Individual, the heart of the adolescent novels of Ayn Rand, has been modulated by the common need for a sustainable future. Although populist governments have tried to revive the old dichotomies, the realities of a world that is volatile, uncertain, complex and ambiguous make simple solutions and mantras increasingly irrelevant.
Re-envisioning the future
In the VUCA world, the old dichotomies break down: right vs left, State vs individual, “us” vs “them” feel increasingly irrelevant.
Frederick Laloux in his book Reinventing Organisations has suggested an evolutionary path for business from centralised Robber baron organisations, which he characterises by the colour red, through more devolved creative companies (orange) to companies that actively pursue goals for the benefit of society (green) and eventually to companies that are driven by self-governing groups that have a sense of shared purpose and community (teal).
It is still unclear whether the future for energy companies is orange, green or teal, but it’s fairly clear that the model of aggressive corporate competition is under challenge. Activist shareholders require the companies in which they invest to have high ethical standards, and are willing to push this agenda at AGMs and in public forums. meanwhile, social media have brought a spotlight on any activities that cut corners with Ciorporate Social Responsibility.
As a result, business models are changing. Greater disclosure, more transparency and community engagement are essential.
Meanwhile, populist governments have tried to trun back the clock, particualrly on anti-corruption and money-laundering. The future direction is unclear at this stage.
Complexity and Synthesis
For at least the last 35 years, it’s been a central dogma of energy pricing that markets can allocate resources more efficiently than mandated pricing systems. Even before the oil exporters’ cartel OPEC switched to market-related pricing, however, commodities have changed hands based on market principles.
The mechanisms used in the pricing of oil, and related commodities such as gas, assume that prices will adjust any imbalances between supply and demand. For example, a sudden shortage of supply caused by a geopolitical event will result – almost immediately – in a price spike that will encourage oil producers to pump more oil onto the market.
The trouble with this approach is that, while the commodity is in abundant supply, there is no economic incentive for potential competitors to develop to deal with future shortages.
The problem has been solved by subsidies, which underpinned the early growth of renewables. This led many governments to subsidise fossil fuels at the consumer level, leading to an uneven playing field.
An Uneven Playing Field
Subsidies have led to an uneven playing field with crippling economic costs. But while cheap energy encourages wasteful consumption, the fact that energy is essential to life makes subsidy removal painful and controversial.
The carbon markets are a different story. The European Union’s Emissions Trading System has been set up as a model for the pricing of “regulated” commodities, but for most of the period since it was incepted in 2005 the carbon price has been below that required to ensure a transition from heavily-polluting fuels to clean energy.
The Paris Agreement highlights the “important role” for providing incentives for carbon reduction through domestic policies and carbon pricing.
Carbon pricing has three main objectives: to penalise emitters of greenhouse gases; to encourage the transition to cleaner fuels; and to fund investment in carbon disposal. Three main methods have been devised by governments to achieve these goals: emissions caps; market-based mechanisms, such as the EU emissions trading system (ETS); and carbon taxes, including carbon price floors.
The vast majority of countries that have committed to carbon pricing in their Intended Nationally Determined Contributions (INDCs) – submitted to COP21 – have favoured market-based measures rather than carbon taxes. The World Bank estimated in 2016 that around 61% of global emissions would be covered by such schemes, including emissions from China, the United States, India, Brazil and the EU.
The trouble with these schemes is that, to date, they have failed to deliver the certainty needed to encourage low-carbon investment or carbon abatement on a large scale. Since its inception in 2005, the EU ETS has failed to deliver a high enough price either to encourage a switch from coal to gas in power generation, or – as it was intended to do – to fund carbon capture and storage (CCS) projects that would allow carbon disposal.
Many of the INDC commitments favouring the market approach are conditional, and tied to unspecified levels of financial and technological support. It seems unlikely these would meaningfully contribute to emissions reduction within the next decade, with the possible exception of China’s nascent National Emissions Trading Scheme.
Adaptation
Much less publicised than the Nationally Determined Contributions to mitigating climate change are the national plans for adaptation to the consequences for a changing climate. Given our projections that, even if we manage a transition from fossil fuels over the next 25-30 years, the earth’s climate will still warm by 3 degrees C, putting in place “common purpose” plans to adjust to the consequences of the temperature rise is essential.
The high-level consequences of global warming are well-known: iconic photographs of melting ice caps have popularised these so that they become a series of vignettes, each of which has a strong emotional resonance.
The trouble with the emotional appeal of such images, largely popularised by climate lobby groups to whip up resentment against corporations, is that they offer no solutions when they become realities. The emotional charge of an image is great at creating a sympathetic response but does not provide any engineering or economic solutions to the dangers it portrays. A picture paints a thousand words but does not create a consensus on what to do. Moreover the nationalistic approach to mitigating climate change makes a global response to adapting unlikely. The gradualness of the problem is also likely to create a slower response; the boiling frog dilemma means that the prompt and pre-emptive action required is not likely to materialise.
The consequences of climate change of 3 degrees C are likely to be as follows:
Rising sea levels
More extreme weather
Widespread desertification
Disappearance of snow
Changes in ocean currents
Each of these high-level changes will have specific consequences related to it, although these will vary from region to region.
The assumption has been that adaptation to climate change will only be needed if there is a planetary failure to deal with the challenge of mitigating the onset of climate change. The reality is that the need for both mitigation and adaptation will accelerate together, and that there will be competition demands from both challenges.
Adaptation
It’s realistic to envisage that global warming of 2-3 degrees C will occur over the next few decades. This will have enormous impact but the effects of climate change will be experienced unevenly around the world. Some poorer countries will be decimated; some richer countries may actually benefit.
The world’s energy system is going through a profound transition from fossil fuels to low carbon and renewable resources. Many people believe that the risk of climate change is not being addressed quickly enough, and that the switch from fossil fuels such as coal, oil and gas is happening too slowly.
Most companies and even governments think about the energy transition in techno-economic terms. They argue about what technologies to put in place, the potential costs and who will pay. But for most people it is more basic: they want access to energy at a reasonable price, but they also to live on a planet that has a future.
The energy transition is not a single thing. Decarbonizing heating and cooling is a very different challenge to switching the world’s car fleet from gasoline and diesel to low carbon alternatives. It helps to break down the problem into manageable chunks, and then see the synergies between the different pathways.
For the last century, the energy industry has harnessed sophisticated technologies to deliver energy from centralised hubs to billions of people. That top-down model is now changing. Disruptive new technologies are emerging that will transform the energy landscape, giving more power and choice to communities and individuals.
For the transitions to be sustainable, radical transformations in leadership, business models and systems are urgently needed. Uncertainties cannot be used as an excuse to delay taking action. We believe that everyone needs to have a voice in the energy system of the future. A visionary approach that treats individuals with respect, rather than as costs and externalities.
I have worked in the energy industry for more than 30 years, as a journalist, consultant and analyst. I offer training and consulting on the impact of new energy on oil and gas use. I believe that the future of energy will be decided by people rather than technology and offer training and coaching on strategy and leadership in the new era of energy transition.
Fuels used in heating have gradually evolved from solid fuels such as coal, to liquid fuels such as kerosene and heating oil, to gaseous fuels such as LPGs and natural gas.
The equipment used to burn the fuels has moved in tandem. My grandmother’s house had kerosene stoves in each room, and there was a coal fire in the living room. The use of energy to provide in home is known as residential, and for shiops and offices it is generally called commercial heating. Sometimes you will see the term ‘space heating’ to differentiate between heating to keep warm and to heat water for cooking.
The use of coal gave way in the 1970s and 1980s to central heating, where a central boiler powered by gas or electricity would heat the water in radiators to provide heating for the home. Many older homes, particualrly in germany and parts of the UK, have large tanks which are filled up with gasoil (also known as heating oil) during the year, and that provides the fuel to keep a house warm. Nowadays, natural gas is now most commonly used in homes in Europe as the boiler fuel, although electrical equipmentn may also be used, for instance electric bar heaters in the UK or electric-powered portable oil or fan heaters, as well as the kotasu in Japan.
The picture for commercial properties is broadly similar to the residential picture, although larger factories may find significant economies of scale that can be integrated with their production processes.
Blowing Hot and Cold
As global warming accelerates, and people become more affluent in emerging markest, the balance between heating and cooling needs is changing.
Many homes in poorer countries do not have central heating, and so use local installations such as LPG, kerosene or paraffin stoves to keep warm, and for cooking. The use of firewood and coal is also common in less affluent countries in northern Asia. El;etcric heating is generally expensive, but may often be found in poorer homes which cannot afford to install more efficient central systems. In the former Soviet Union, many homes were heated using waste heat from industrial facilities, and this form of heating remains fairly widespread.
A notable trend for the future is the increasing use of electricity for cooling, particularly in countries that have been too poor to afford such luxuries. Air-conditioning is common in the United States and the Middle East, but is being installed more frequently in homes in Europe, South America and Asia. Electric fans have been used in tropical regions for cooling for many years, and their use is also growing. This trend is likely to be accelerated by global warming.
The intensity of the heat source required has become a notable field of research. While intense heat is required to cook, less intensive sources can be used to warm water or to keep homes warm. Tapping geothermal energy through the use of heat pumps has become popular in some countries, although it remains an expensive option.
Mobility and Transport
Few people know that the first road vehicles were powered by alcohol and natural gas. Alcohol went out of use in the United States in the 1920s when prohibition came in. The growth of petrol (gasoline) and diesel as a fuel soared the the 1940s and 1950s as passenger use became more popular, and as long-haul trucking became the norm. Nowadays, 1 in 11 barrels of oil is used by the American motorist, and transportation use accounts for nealry two thirds of all oil demand.
Transport is regarded as a hard-to-decarbonise option because the vehicle stock turns over fairly slowly. Most cars are on the road for at least 15 years, and while decisions on the make-up of commercial-vehicle fleets are usually based on economics, the choice of passenger vehicle is dictated mostly by brand image and psychology. People who have driven a liquid-fuelled car for most of their lives are often loathe to experiment.
The main Alternative Fuelled Vehicles (AFVs) use either gas or electricity.
The AFVs that use gas are usually termed Natural Gas Vehicles (NGVs) and the fuels they use may be either Liquefied Natural gas (LNG), Compressed Natural Gas (CNG) or Liquefied Petroleum Gas (LPG). Large trucks often use LNG as their fuel, while passenger cars and vans most often use LPG or CNG as an alternative to petrol or diesel.
The use of electric power in transport is mainly confined to passenger cars, usually at the top end of the price range, and for short-haul driving in giolf carts, trolley buses and so on. The types of electric vehicle (EV) include pure EVs and a panoply of different hybrid electric vehicles (HEVs), which have electric batteries but can also use gasoline or sometimes diesel.
On your bike
Like many people during the Covid-19 lockldown, I bought an electric bike and have not regretted it for an instant. My ventures can be followed on my blog at https://easywheeling.com. The lockdown led to a surge in sales of electric bikes across Europe, as people with time on their hands opted for e-mobility for leisure. Many came out of lockdown with a renewed commitment to achieveing a sustainable lifestyle.
Manufacturing and Freight
The use of energy in manufacturing is determined partly by the type of goods being manufactured, and also by the location of factories and manufacturing plants and their proximity to different sources of energy.
Power sources can be incredibly flexible. In the 1700s, wind and water were widely used to drive mills that would do everything from grinding down grain to making cloth. Nowadays, the energy-intensity of fossil fuels means that coal, oil, gas and fossil-fuel derivatives such as petroleum coke are most widely used in manufacturing. This is particularly the case in large-scale energy intensive industries such as metal smelting.
Electricity is also used in smaller factories, but it is generally more costly than bulk fuels. The size of the factory and economies of scale are always a consideration. In ceramics, for example, gas may be used for larger kilns, while electricity would be used typically for studio ceramics. This same pattern is seen across the manufacturing sector. Decisions need to weigh not only the current cost of fuels but also their future costs. Considerable research may be required when deciding on fuel selection.
Heavy Duty
Fuel decisions for manufacturing depend largely on the scale of the factory and how intensive the form of energy that is required. Decisions can affect long-term profitability, and need to be carefully considered.
Freight
As well as manufacturing the goods, energy is also consumed in delivering the goods to storage locations and their end-use markets. The type of energy consumed depends on the facilities used for transport.
Ships and barges are often used for bulky products that would be expensive to move by road. These typically use heavy fuel oil, diesel or gasoil. In the past, thse have used the power of wind, and this has occasionally made a resurgence. Electricity and gas are also occasionally used.
Trucks and lorries are also commonly used. These mostly use diesel, although ion some parts of the world gasoline is more commonly used. The idea of using gas in various forms has become more popular, but still not achieved critical scale (see above).
Airplanes are also commonly used to carry smaller items of freight. Most planes use aviation kerosene as their fuel.
An interesting development for the future relates to the location of the manufacture. The traditional pattern has been to make goods where it is cheapest, and then transport them to the markets where they will be consumed. The development of three-dimensional plastics could be a game-changer, as it would allow goods to be manufactured using computers and to minimise the freight required to reach market.
Electricity
Most people’s image of the power sector comes from the pylons that are used to transport electricity around the country, or perhaps of the wind farms and solar panels that you drive past on the motorway.
It’s difficult from this to conceptualise the scale of the power generated around the world. At any instant, the world consumes an amount of electric energy that is equivalent to that released by tens of thousands of nuclear explosions. This electricity has to be generated on a continuing basis because electricity is a flow, and it cannot be stored (although technologies are being developed to do this).
Electricity generation is either from fossil fuels, increasing natural gas, or from renewables such as wind, solar and geothermal energy.
The transmission and distribution of electricity involves a gradual stepping-down of the load carried in the lines until finally, when it reaches you home, it is relatively safe to use.
Industry also uses significant amounts of electricity, but this may be delivered more intensively as three-phase power.
The future is electric
Whether the electricity you use is low carbon depends on the fuels used to generate it. These range from coal and oi to lower carbon fossil fuels such as natural gas to zero-carbon renewable sources such as wind or solar.
Did you know how much carbon is emitted by a single search on Google? There’s an interesting factoid that goes the rounds that a single search uses enough power to fuel a light bulb for an hour. This turns out not to be true see https://fullfact.org/environment/google-search/ but may people are unaware of the scale of energy use by the Internet. As the Internet of Things gets bigger, the use of power by technology firms will increase.
Food and Agriculture
The world’s population is forecast to rise from 7.5 billion people currently to as many as 10 billion by 2050. This growing population is likely to be more wealthy than past generations and, for much of history, that has correlated with higher food consumption.
The climate toll of large-scale agriculture is clear. The amount of methane created by farm animals used for meat, the impact on biodiversity from pesticides used to improve crop yields, and the deforestation that results from clearing large swathes of countryside to make land available for agriculture have all been widely noted.
More recently, however, there has been a growing awareness that food and energy issues cannot be separated.
The linkages were first exposed when the use of grains and sugar in biofuels resulted in fears of shortages of these foods for nutrition,
Biofuels are seen as valuable for meeting climate targets because, the theory goes, the crops used have already extracted the CO2 from the air, so it can be emitted without any overall climate impact. This has been the justification of European Union rules on bio-content in fuels, but it was only belatedly that these were accompanied by standards of sustainability and certification of the crops used.
Food and Energy Supply Chains in Conflict
Food and energy could end up competing for space. Biofuel requirements for fossil fuels are well intentioned, but the competing demands for grains and sugars from the food and energy sectors could become problematic.
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Waste Disposal
As the world’s population grows, more waste is produced. Waste disposal is critical to ensure that the environment for human habitation is hygienic and safe, but also to avoid biodiversity loss.
Although carbon has had a higher profile in recent years, the pollution from energy production includes a range of pollutive by-products, from sulphur and nitrogen oxides (SOx and NOx) to particulate matter (PM) and shloro-fluor carbons (CFCs) that can damage the ozone layer. There are always tradeoffs between making energy and curbing its harmful effects.
Pollution control is part of a bigger issue of how waste from a multitude of human activities can be disposed of safely and with the minimum damage to the environment. In many cases, the problem is not what we do or use, but how we get rid of it.
Recycling everyday garbage from household activity involves most people placing their used bottles and cans in a recycling bin. But that doesn’t solve the problem if the recycled products are shipped off to a foreign country where they may simply be burnt or jettisoned into the biosphere. That simply exports the problem.
Demonizing certain activities does not help. For example, plastics are durable and have the potential to be used to reduce carbon emissions. But disposal of plastics has become a major hazard to marine systems.
Don't breathe too deeply
Air pollution and carbon emissions are both problematic for the environment. But in Asia, air quality issues are of much more concern for most people than the long-term risk of climate change.
A Methodological Approach
The issues around waste and hygiene are hugely divisive. It is fraught with issues of wealth, class and privilege. Social groups often demonize each other without self-scrutiny. As the populist right has become more dominant, this is often expressed in overt racist tones — Trump’s references to the Covid-19 virus as the Chinese virus are a case in point.
Many people take the approach of turning a blind eye. It it’s not visible, it’s not a problem. Exporting waste to poor countriers in Africa and Asia is common-place, and this has also been proposed as a solution for the disposal of nuclear waste. Organised crime has often got involved in the waste business because it is profitable and because there is limited oversight of those involved. Usually that’s because people would rather not know what goes on.
A methodological approach is required to measure the various impacts of waste disposal. Just as fossil fuels and renewables have been evaluated using the yard-stick of life-cycle analysis, a holistic approach to waste disposal that would provide objective metrics about who is affected is required. Above all, there needs to be transparency among the companies and institutions involved in waste disposal. Local councils cannot hide behind the promises of their contractors, but should actively monitor their activities.
Energy Efficiency
Improving your own carbon footprint is obviously a positive step, and much can be done by simply improving energy efficiency, particularly where grants are available from local or central government.
But it’s also human nature to do nothing when you see other people doing nothing. And it’s just as much a human failing to feel smug about your own contribution and to disdain others who you perceive to not be doing as much as you.
Energy Efficiency
Energy efficiency can be measured easily, and improvements are often not nearly as costly as people think.
Energy efficiency is not just about improving how your boiler works. Enormous energy savings can be made by businesses, by managing the activities of employees in the heating and illumination of offices, but also by monitoring energy use in manufacturing processes, particularly those that are energy intensive such as ceramics or metal-smelting.
Societal Change
Improving your own carbon footprint is obviously a positive step, and much can be done by simply improving energy efficiency, particularly where grants are available from local or central government.
But it’s also human nature to do nothing when you see other people doing nothing. And it’s just as much a human failing to feel smug about your own contribution and to disdain others who you perceive to not be doing as much as you.
Energy Efficiency
Energy efficiency can be measured easily, and improvements are often not nearly as costly as people think.
I have worked as a reporter and market analyst with some of the biggest information providers in the energy sector: Standard & Poors Platts, Reuters (now Refinitiv) and the Russian business data and technology business Interfax. I have also worked as a consultant with governments in Europe, the Americas, Africa and Asia; along with some of the biggest oil, gas and power companies in the world. Throughout this time, I have had a panoply of interesting economists, engineers and journalists from all over the world as colleagues and friends. I don’t know of any industry with a more diverse range of cultures, and the industry is gradually becoming more diverse in terms of gender, personality and ethnicity.
Reflecting on my career, I was struck by how little of my time was spent engaging with the people and communities who were affected by the energy industry. We would all talk with the people who had the money: the investors, the bankers, the upstream, midstream and downstream companies who were involved in the projects; the traders and brokers; and their advisors, from lawyers and consultants, to tax specialists and diplomats. But the only contact with local groups as a journalist was almost always through environmental pressure groups who purported to represent their views. And as a consultant, communities were only consulted by specialists conducting the environmental impact assessments (EIA), negotiating local content rules and policies, and higher beings responsible for corporate social responsibility (CSR).
Beyond technology
It struck me that this was indefensible. The energy industry should be there to serve the goals of these communities; ultimately, it is the public that pays their bills. It’s obvious to me now that people and communities should be engaged with at every stage of a project, and throughout the energy value chain from production and generation to the end use in the home or office, not just when a problem blows up or there is a scandal.
The dichotomy we currently face, between a public who wants to “Save the Planet” and an energy professional class which assumes it knows what is in the public interest, results directly from this disintermediation. A huge amount of mutual suspicion exists between these two camps.
In 2012, when I set up Resource Economist, I had envisaged a training company that would be capable of providing expert knowledge to customers from within the energy industry, and to outsiders in government, environmental organisations and local communities who want to cut through the jargon and get to grips with the real issues. I felt this would play to my strength as a journalist, which was to explain things in a simple and clear way, as well as an analyst and consultant, which was to provide an unbiased expert view.
Nowadays, I feel this was at one level too ambitious, and at another level, not ambitious enough.
Too ambitious, because most people have their minds already made up, depending on which camp they are in. The camps reflected were the binary categories of good/bad, pro-industry/pro-environment, protest/collude, etc.
Not ambitious enough, because it sought simply to explain the industry through training courses in neutral terms, rather than to engage actively with the disparate communities that made up the energy sector as a whole, and to understand their motivation(s).
I have tried to refocus this website on the people who are responsible for the Energy Transition, from fossil fuels to cleaner sustainable forms of energy. In 2014, I began a series of interviews for the British Institute of Energy Economics, meeting with some of the most able and inspiring people in the energy sector, from government, community groups, CEOs of large companies, academics, start-up tech firms and a spectrum of others. Brief clips from many of these interviews are available on the BIEE website www.biee.org/videos.
Milestones
There are two other milestones I should mention.
In 2019, I flew to Vancouver in British Columbia, Canada for a major gas conference in which I met members of the First Nations who had recently formed an alliance in support of the building of an LNG plant. The Wet’suwet’en First Nation were at the heart of this, reaching an agreement with Shell and a group of other investors that allowed the project and a gas pipeline to supply it to go ahead. The decision was hugely controversial. Shell and many in the gas industry saw it as a watershed, pouring out press releases extolling its virtues, while environmentalists reacted with dismay, and launched a furious and highly coordinated assault on those who had supported the project. The Wet’suwet’en were split.
I will do a separate post on what I learned (about myself as much as anything) from this dispute, but in short, it reflected a lack of communication that I believe mirrors the dichotomies mentioned above between “the industry” and “the environmental lobby”. I put these in inverted commas because in reality neither is as monolithic as it first seems, and a common dialogue between the two should be possible.
In August 2020, I bought an electric bike. After the Covid-19 crisis started, I spent the six months in lockdown rethinking where I wanted to take my career, and writing the draft of a book to be called Sustainable Transitions in Energy. The bike idea came to me about midway through writing this tome, which I realised would become one of many doorstopper tomes that everyone feels is worthy and no-one actually reads. My e-bike journey is at a very early stage (see the separate blog on easywheeling.com) but I thought it was important to take a stand by trying to go electric.
The Covid-19 crisis persuaded everyone I knew that they had been right all along ! It was like the mirror in the fairytale that told you only what you wanted to hear.
Aspirant Greens saw the collapse of the fossil fuel house of cards as energy demand plummeted and renewables took over. Meanwhile, the oil and gas industry retrenched as it always does, shedding staff to deal with prices that were half what they had enjoyed before the crash, but confident that market mechanisms would see a revival of oil and gas demand over time.
My goal now is, as it was at the start, to explain the industry inside and out, to the best of my ability. But I want to do this through talking with people, not about technologies, but what motivates them — that mysterious thing called “purpose” that reflects our humanity, and makes us so much more than the statistical noise that economists use in their model. I am deeply aligned with Kate Raworth’s Doughnut Economics, and I see the energy industry as a vehicle serving the needs and (often irrational) choices of people and communities.
This website is more extensive than I had originally planned, but it’s not because I have teams of people working for me. I have just drawn on the many materials I put out during my career as a journalist and analyst. But I hope it conveys my passion for the subject. Inevitably, because of the bias towards the large-scale players, it will take a while to develop my focus on people and communities. But it will happen over time. As well as delivering high-quality courses for energy professionals, I am determined to engage as much with communities, schools and even individuals, and to share what I have learned over the last thirty years so that everyone is better informed, I hope I will visit some of you on my electric bike.
Training and Mentoring
Resource Economist provides training, coaching and mentoring services for companies involved in energy and natural resources.
Catalytic Learning
Resource Economist training courses cover all aspects of crude oil, refined products, natural gas and LNG, energy market fundamentals, power fuels and new energy. We specialize in delivering courses on market analysis, valuation and pricing, trading, forecasting and risk management.
Our courses involve delegates from the start in an active and participatory learning experience. Rather than the doctor-patient approach used by many training organizations, Resource Economist uses active learning methods based on coaching to maximize the knowledge and skills of delegates.
We recognize and actively harness the experience of all participants in the courses, creating a learning space that allows delegates to take risks and stretch their skills.
We work closely with companies to structure learning programmes that use their own in-house expertise to disseminate knowledge and skills. We do this through training videos, recorded interviews and written materials based on meetings with staff.
Coaching and mentoring
Resource Economist maintains contacts with experienced people across the energy sector who can coach and mentor individuals and teams.
Peter is a qualified executive coach and holds a PG Cert from Middlesex University in Psychosynthesis Leadership Coaching. He has provided mentoring to colleagues throughout his career, and is an enthusiastic advocate of using coaching as a way to motivate staff, as individuals and in teams.
Although they are often regarded as interchangeable, coaching and mentoring are actually quite different. Mentoring typically involves someone with experience passing on domain expertise, often as a way to supplement class-room knowledge with first-hand practical experience. Coaching typically is focussed more on attitudes than knowledge. A coach will seek to help an individual (or a team) to find answers from within. The focus is not so much on objective facts but on subjective realities, mindsets and feelings.
Finding the best way to help your staff or colleagues maximize their potential is one of the most important but also the most difficult challenges faced by companies. There is no single answer. Please call us to discuss your requirement.
Research and Consulting
Resource Economist provides top-class research on the key issues driving the energy and natural resource markets, with a particular focus on the interface between traditional fossil fuels and new energies such as wind, solar and geothermal.
Resource Economist is a corporate member of the British Institute of Energy Economics, and Peter has been a member of the BIEE Council since 2014 and has worked on a number of BIEE committees seeking members and sponsors, and organising the annual research and policy conferences in Oxford and London.
Resource Economist publishes research studies, white papers and briefings on energy pricing, data transparency, people and skills in the energy sector, and governance issues related to the development of energy and natural resources.
Peter has been an energy analyst for more than 30 years, and is a frequent speaker at industry events on oil and gas, as well as more recently on the energy transition. He provides advisory services as an associate at third-party consulting firms.
Rather than the doctor-patient approach used by many training organizations, Resource Economist uses active learning methods based on coaching to maximize the knowledge and skills of delegates.
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A coach will seek to help an individual (or a team) to find answers from within. The focus is not so much on objective facts but on subjective realities, mindsets and feelings
Peter is a qualified executive coach and holds a PG Cert from Middlesex University in Psychosynthesis Leadership Coaching. He has provided mentoring to colleagues throughout his career, and is an enthusiastic advocate of using coaching as a way to motivate staff, as individuals and in teams.
We interviewed Mike Burns at CTEC Energy in Newhaven Port. The gasifier project converts plastics and biomass into electricity and heat with significantly lower emissions than a traditional incinerator.
The latest Energy Journal from the International Association of Energy Economics has landed on my doormat with a loud thud. The latest issue is 312 pages long. In Volume 41, Number 6, I was struck by the paper Are Energy Executives Rewarded For Luck? by Lucas Davis...
The BIEE’s bi-annual research conference will be held on March 30-31, 2021. The conference will focus on building the foundations and policies of the low carbon transition aimed at achieving a net zero carbon society in a way that is fair and just. It will address how we live, work and travel, and how policy, infrastructure and the private sector can respond to enable the transformation of heat, transport and industry.
The energy transition will involve a shift from the fossil fuels that have been used for the last three centuries to low carbon fuel sources such as renewables. The scale of the transition will be unprecedented. The world population will rise from 7.5 billion people to nearly 10 billion by 2050, and this population growth looks likely to be accompanied by increased urbanisation. The challenge of meeting this demand growth while meeting climate targets is immense.
We interviewed Mike Burns at CTEC Energy in Newhaven Port. The gasifier project converts plastics and biomass into electricity and heat with significantly lower emissions than a traditional incinerator.
Coal: Abundant and Cheap
Coal accounts for around a quarter of all energy produced globally. Its main use is for power generation, although it is also used in homes for winter heating, especially in poorer countries. The main advantage of coal is that it is abundant and easy to transport. Coal is usually sold on the open market in US dollars per tonne, although pricing can also be based on its calorific value, which varies greatly across the different grades of coal. These range from poor quality grades such as lignite that produce relatively little energy to high density grades such as anthracite which are more costly and often have specialist uses.
COAL
Coal is a widely available solid fuel. It can be transported cheaply and is used for power generation, in industry and manufacturing, as well as for home heating.
The Hidden Costs
Many power companies use coal to fuel their power generation plants because it is cheap. Reserves of coal are found all round the world, and the amount of coal under the earth far exceeds the reserve of oil and gas. Coal is much less subject to the geopolitical pressures that lead to such intense volatility in oil and gas prices. But there are hidden costs. Coal is a much more pollutive energy source than oil and gas, although because it is mainly used for power generation in developed countries, it often escapes the attention of environmentalists. In many lesser developed countries, particularly in South and South East Asia, coal is still used in the home and has an enormous health impact, causing diseases from bronchitis to cancers.
Coal: Percentage of primary Energy Demand24%24%
Oil: A Slow Twilight
Oil makes up around one third of global energy demand, mainly because it is so widely used in transport. Almost all the 1.5 billion cars on the roads are driven by Internal Combustion Engines (ICE) and fuelled by gasoline or diesel. Meanwhile, almost all commercial and military airplanes use kerosene for fuel, most lorries and heavy duty trucks use diesel or gas, and the bulk of the world’s shipping fleet uses either diesel or a heavier grade of oil known as fuel oil. While Electric Vehicles are starting to flood the market in wealthy developed countries, cost remains a problem and EV growth has been unspectacular in the poorer countries of South and South East Asia, Latin America and Africa. In the US and Middle East, cheap oil, image and brand issues, as well as range anxiety mean that most people still prefer gasoline-fuelled cars for the time being.
Crude Oil and Refined Products
Oil has powered the modern age, but at a cost. Oil powers cars, planes, ships and trucks, and most manufactured goods from packaging to paper contain petrochemicals derived from oil.
Gas: Solution or Problem?
Gas has emerged as a strong growth area, given its cleaner carbon profile compared to other fossil fuels. Natural gas comprises primarily methane, and can be liquefied and transported in special ships as Liquefied Natural Gas or LNG. But two other forms of gas could play a role in the energy transition: propane and butane can be liquefied to make Liquefied petroleum Gas, or LPG, and both fuels are increasingly used in lower income and developing countries, and have a much lower carbon footprint than diesel and heavy fuel oil which they tend to replace. Meanwhile, ethane is used in some countries as a petrochemical feedstock. Methane, ethane, propane and butane are all hydrocarbon fuels, although it’s also possible to make methane as a bio-gas, for instance by using waste materials.
Natural Gas and NGLs
As demand for lower carbon fuels increases, methane and other gases have emerged as alternatives to liquid fuels. But they still emit harmful hydrocarbons into the atmosphere.
Renewables and Scale
Renewables include a range of energy sources including solar power, onshore and offshore wind, tidal and wave power, geothermal energy, biofuels including biomass, biogases and algae, and in some narratives hydropower is included. All of these energy sources have the potential to generate electricity, but the problem faced by all of them is scale and cost. Building renewable energy on the scale required to meet the energy needs of the growing world population in a way that is cost effective is a huge challenge. So far, solar and wind are emerging as the clear winners. Costs have been reduced significantly as the industry has scaled up. But the sun does not always shine, and the wind does not always blow. The problem of intermittency requires that backup energy sources — from energy storage or low carbon gases — are available.
Renewables
Renewable energy is widely seen as a panacea for climate change. Breakneck growth has proved their viability, but scaling up to replace the approximately 80% of energy that derives from fossil fuels will be an enormous challenge.
From Little Seeds
Only 5% of the world’s energy comes from renewable sources like solar and wind power, but that’s a significant increase from just 2% at the start of the last decade (2010). The share of renewables in overall primary energy demand varies greatly by geographical region, from negligible amounts in Russia and the CIS to around 10% of the total in Europe and the Americas. China was the world’s biggest investor in renewable energy in recent years, and renewables now account for nearly 5% of the energy used in the world’s most populous country. Whether this will continue to grow will be influenced heavily by politics: the Paris Agreement in 2015 followed a historic alignment of Chinese and US interests, but this is now threatened by the trade war between the two superpowers. The trajectory of economic growth after the Covid-19 virus and global lockdowns is also at stake.
Hydropower
The kinetic energy of water stored in reservoirs behind dams can be used to turn turbines for electricity generation. But there is a tension between the use of water for drinking and health, and the use of water for producing energy. Water is essential for life. The bulk of the world’s 7.5 billion people live in cities located on rivers or by the sea, and depend on water for sanitation, sewerage and nutrition. But water is also used in many of the processes used to produce oil and gas, including the controversial process known as “fracking” in which water is blasted into shale to release the oil and gas it contains. Water is also used intensively in petroleum refining.
Energy and Water
Making energy requires huge amounts of water. Transporting water requires huge amounts of energy. There is no simple solution to the energy vs water conundrum, but advances are being made.
The geopolitics of water
Geopolitical tensions in the 20th century were dominated by access to oil. In the 21st century, water is emerging as the most likely cause of war between countries. Water is a gift of nature, but the rivers and lakes that are created by the water cycle often span national boundaries. The use of water and related resources is frequently contested, and few treaties exist defining the rights and obligations on the use of water between countries. Most recently, Egypt and Ethiopia came close to conflict over plans to dam the Nile river, which Egypt believes will take a toll on its agricultural output. The delicate web that links human society with nature reflects the interconnection of all life. Water use is often taken for granted, but one community’s use of water may have a critical impact on other communities.
Minerals and New Energy
Many of the metals and minerals needed to make advanced batteries are found in only a few countries, some of which are in war zones and some with unenviable human rights records.
Lithium and cobalt, the main elements used in electric vehicle batteries, are found in relatively few countries and reserves will become depleted as the EV fleet grows.
Mining communities offer suffer from the intensive development of resources, particularly when working conditions are unsafe and jobs are poorly paid.
The use of workforces from outside the indigenous communities can also lead to disease and sexual exploitation.
Resource Costs
As new battery and energy storage technologies are developed, resource pressures will be felt along the value chain.
An Interconnected World
This section on energy and resources has emphasised throughout that there is no simple solution that will “save the planet”. Meeting the scale of global energy needs is a huge challenge, and every solution has pros and cons. There is no silver bullet. This is not a recipe to do nothing, but it reflects the reality that systemic change has potential consequences that need to be thought through carefully. All eco-systems are interconnected, just as are all human beings: as the poet John Donne put it, “No man is an island / Entire of self”. No man (or woman) exists in a bubble; we all have an impact on each other. Rather than providing blanket solutions, Resource Economist believes that specific pathways should be selected depending on local resources and needs.
The article below was carried in the December 2018 edition of Power Fuels Tracker, an Interfax publication of which I was editor. Most of the content is still (sadly) relevant.
By Peter Stewart, Interfax Chief Energy Analyst “Don’t divide the skin while it’s still on the bear.” The 20,000-plus delegates and negotiators attending the COP24 climate summit in the Polish city of Katowice on 3-14 December, 2018 – the third such conference to be held since the 2015 Paris agreement – would do well to bear this Polish proverb in mind.
The Paris agreement, which aims to limit global warning to 1.5C, has been signed by 197 countries and ratified by 184. Significant progress has been made on defining what the agreement means for individual nations. But tangible results, in terms of concrete new steps to slow climate change, have been lacking.
At Katowice, the dialogue will enter a political phase that will provide guidance and a framework for nations to implement the Paris agreement. That will mean reviewing progress to date, fleshing out the actions needed to implement the agreement’s work programme and formulating these in a rulebook.
The UN Framework Convention on Climate Change has outlined some of the key issues that will need to be resolved in Katowice. These include how emissions will be mitigated as part of nationally determined contributions (NDCs); drawing up the transparency framework for action and support; how developed countries will provide finance; making a ‘global stocktake’ on the efforts countries have made to mitigate climate change; the development of cooperative approaches, such as a new market mechanism; and the creation of shared timeframes for countries to submit and/or update their NDCs.
The trouble with this strategy is that it provides a recipe for further talks about talks rather than creating immediate action to limit climate change.
There are two risks in this approach. The first is that momentum could be lost – support from governments and the public for action on climate change could wane unless there is clear evidence that the international consensus is resulting in firm action. The second is that, rather like the prospects for emerging technologies such as algal fuels and carbon capture and storage (CCS), the promise of future benefits could become an ever-receding mirage. While it may be reassuring to hear that action will perhaps be taken in the future, this provides no guarantee that any actual steps are being taken to limit climate change.
The political consensus behind the Paris agreement was always fragile, and the impetus for a deal happened largely because of a consensus between the United States and China – albeit as a result of different drivers. The US is one of the world’s major polluters, but while former President Barack Obama backed the deal in 2015, his successor Donald Trump has withdrawn his support. Brazil has also stepped back. There is now a risk that those who only want to pay lip service to the deal can stall indefinitely. Protest groups such as Extinction Rebellion in the UK have started to take direct action to drive climate change higher up the political agenda because they feel governments are being too slow.
The stakes are high. They were raised even higher in October, when the latest International Panel on Climate Change report described the catastrophic results of a temperature rise of above 1.5C. The Paris agreement committed nations to limiting global warming to 2C above pre-industrial levels, but also committed them to pursue efforts to limit the rise to 1.5C.
Immediate action is required to limit fossil fuel consumption if the more ambitious target is to be met. However, this does not yet appear to be high on the agenda at Katowice. The aim at COP24 is to secure agreement on three declarations, to be adopted either by heads of state or at a ministerial level. These cover forests, electric vehicles and the ‘just transition’ – a policy to ensure that the shift to green energy does not hurt the workers and communities that rely on outmoded industries such as coal. A high-level dialogue on climate finance will also take place.
Meanwhile, the Talanoa dialogue – which was launched at COP23 under the presidency of the Republic of Fiji – will end. Based on the Pacific concept of ‘talanoa’ – storytelling that leads to consensus-building and decision-making – the dialogue aims to ensure that countries enhance their NDCs by 2020 by allowing non-state actors to submit ideas. But there is a risk that the consensus resulting from the dialogue will be a fiction, rather than firm commitments for action.
Katowice itself is a kind of microcosm of the environmental challenges that will dominate the discussions. The town became wealthy in the 19th century from mining coal from the nearby mountains. In the Soviet era, heavy industry such as steel manufacturing was developed, resulting in severe urban pollution. Although it is now developing renewable energy, Poland has resisted steps to curtail its coal industry because it is supported by a powerful political lobby. Many NDCs identify ‘clean coal’ as a preferred way to meet their climate targets. Poland could blaze a trail by tightening controls on stack emissions, and by embracing CCS and related technologies as priority investments. Or it could act now by setting a schedule for shutting down older coal plants.
The International Renewable Energy Association IRENA released a major report on the potential for green hydrogen in September 2019. The report is available for download using the button under the photo of the report cover to the left.
The International Energy Agency IEA released a major report on the potential for hydrogen in June 2019. The report is available for download using the button under the photo of the report cover to the left.
Energy Policy Conference: Getting Serious About Net Zero
The British Institute of Energy Economics held its annual policy conference on 23 September 2019 at the BEIS conference centre near Victoria Station in London. Peter was part of the coordinating committee for the event and conducted a series of speaker interviews during it. For further details about the conference please click here.
Just on my way back from Gastech 2019 where I hosted a panel on new dimensions in LNG supply. Sarah Bairstow at Mexico Pacific LNG, Anton Oussov at KPMG and Jason Bennett at Baker Botts. Some interesting views on project economics, the links between ethane and methane, and new suppliers in Russia, Mexico, the United States and Canada.
Peter Stewart spoke on behalf of Interfax at the Gastech conference in Houston, held 17-19 September. Interfax highlighted Global Gas Analytics and Natural Gas Insight publications.
Peter Stewart spoke on behalf of Interfax at the European Autumn Gas Conference in Paris, which was held 5-7 November. Interfax was a sponsor of the conference and highlighted their Global Gas Analytics and Natural Gas Insight publications. Peter is a frequent speaker at energy conferences and contributed to discussions at the FLAME and Gastech conferences earlier in 2019, in Amsterdam and Houston respectively.
The article below was carried in the 29 November, 2018 edition of Interfax’s Natural Gas Daily publication. The Interfax Gas Analytics service provides daily, weekly and monthly analysis of natural gas and LNG markets.
By Peter Stewart, Interfax Chief Energy Analyst, Managing Director Interfax Europe Ltd
The UK government shows no sign of incentivising the creation of more gas storage capacity, despite calls to provide financial support for new projects after Centrica’s ageing Rough facility was shut down in 2017.
A UK parliamentary committee published evidence on 31 October on whether the country needed new storage capacity. It included submissions from consultants, transmission system operator (TSO) National Grid, energy-intensive industries, gas storage operators and the Department of Business, Energy and Industrial Strategy (BEIS).
The BEIS insisted that system flexibility is crucial. Dan Monzani, the department’s director for energy security, networks and markets, told the committee that market signals had successfully encouraged investment in LNG infrastructure, interconnectors and storage capacity over the past 20 years. “It is dangerous for government to choose what the best way of doing that is,” he said.
The UK has one of the smallest gas storage capacities of any European country, amounting to just 2% of annual demand compared with around 25-35% in major continental gas consumers. The UK uses around 78 billion cubic metres of gas per year but is able to store only 1.5 bcm.
Centrica decided to close Rough, which could hold 3.3 bcm, in July 2017 because the 32-year old facility was uneconomic and had become unsafe. EDF took a similar decision to close its Hole House storage facility a year later. Rough accounted for around 70% of the UK’s storage capacity.
Meanwhile, the private sector has proposed more than 15 gas storage projects in the UK over the past decade but almost all of them have been scrapped or are struggling to raise funds that would allow them to go ahead.
Uncertainty over the future availability of continental gas supplies during winter has risen in recent months because of the cap on output at the Netherlands’ Groningen field, the risk of a hard Brexit and political tensions over Qatar and Russia. The UK nearly ran out of gas when the ‘Beast from the East’ cold snap struck in March 2018. The sudden drop in temperatures caused a temporary spike in prices at the NBP hub, from around 60 p/th to over 270 p/th.
The UK depends on gas to produce half of its electricity, while 80% of its homes use the fuel for heating and cooking. Imports have risen as domestic production has dropped, leaving the UK dependent on pipeline and LNG imports. The country imports gas through the Langeled pipeline from Norway and via the Interconnector UK and BBL pipelines, which connect to the Netherlands and Belgium respectively. The UK also imports LNG and has taken two cargoes from Russia so far this year, in addition to deliveries from other suppliers.
The UK’s underinvestment in gas storage has been criticised not only because it has made the country more vulnerable but also because it reduces the flexibility to supply the continent through gas interconnectors. However, the UK has argued for many years that energy security is better served by diversifying supply rather than building storage – although a government select committee recommended in 2010 that the country should double its storage capacity from the 5 bcm that was then available.
The current winter/summer spread between prices at the NBP does not support the building of new storage facilities. A spread of 22-24 p/th would be required to fully support the construction of new capacity in underground salt caverns or depleted gas fields, but the spread is currently less than half that.
In its Winter Outlook for 2018, National Grid said the UK’s demand for gas this winter will be lower than it was last winter because of increased generation from renewables and greater use of coal in the power sector, which it predicts will be cheaper to burn than gas. The TSO predicted winter demand of 46.6 bcm and a 1-in-20-year chance that peak day demand will hit 472 million cubic metres.
The article below was carried in Interfax Natural Gas Daily on 21 November 2018. Interfax runs a gas analytics service with daily, weekly and monthly analysis of the global gas and LNG market. By Peter Stewart, Interfax chief Energy Analyst and Managing Director of Interfax Europe Ltd
The International Energy Agency (IEA) said this week that oil and gas companies should be doing more to cut emissions from their upstream operations, singling out gas flaring as a key area for improvement.
The IEA’s flagship World Energy Outlook (WEO), published on Tuesday said flaring gas was both wasteful and harmful, and that upstream emissions could be reduced further by the electrification of upstream and midstream operations or by building renewables-based systems into the extraction and production process.
The call to action will pile pressure on IOCs and NOCs that are already under intense scrutiny from activist shareholders who want them to decarbonise their value chains. The IEA said 97% of the gas consumed today has lower lifecycle emissions than coal, but that companies need to decarbonise the gas value chain further because of gas’s growing role in the energy mix.
“The aim for the future should be to focus on cost-effective ways to minimise the gap between gas and zero-carbon technologies rather than focus on the gap between coal and gas,” the WEO said.
The IEA estimated that emissions from oil and gas operations accounted for 15% of the energy sector’s greenhouse gas (GHG) emissions.
The industry has been working for years to reduce emissions from oil and gas production, but results have been mixed. Carbon capture and storage/use have been discussed for decades, but the number of sites in operation is limited. Injecting carbon dioxide into wells is common in enhanced oil recovery operations, but it is expensive and by no means universally used.
Billions of cubic metres of gas are still flared annually at oil and gas production sites around the globe, however, and reducing flaring is one of the lowest-cost options for cutting energy-related emissions.
Carbon price
The IEA said a carbon price of $50 per ton of CO2, which is already used by some companies when screening upstream projects, would cut emissions in 2040 by more than 1,000 MMt CO2 equivalent (MMtCO2e) if applied across the oil and gas supply chain. A total reduction of 2,500 MMtCO2e could be achieved if the $50/t carbon price was combined with methane emission reductions that can be achieved at no net cost. The IEA estimated total emissions from oil and gas production amount to 5,200 MMtCO2e per year.
“This saving would be equal to the entire energy sector GHG emissions of India today,” according to the WEO.
Most flaring results from lack of infrastructure rather than the type of oil or gas that is extracted. Small-scale LNG and GTL plants are potential ways to monetise stranded gas or to avoid flaring gas produced in association with oil. But such projects typically make economic sense only if a carbon cost is assumed.
The World Bank’s Global Gas Flaring Reduction Partnership (GGFR) publishes annual estimates of gas flaring based on data from a satellite launched in 2012. The GGFR is a public-private initiative including IOCs and NOCs, national and regional governments, and international institutions. The GGFR has set a goal of zero flaring by 2030.
The 2018 GGFR report, produced with the United States’ National Oceanic and Atmospheric Administration in cooperation with the University of Colorado, showed a nearly 5% decline in gas flaring in 2017 despite a rise in oil and gas production.
“While Russia remains the world’s largest gas flaring country, it also saw the largest decline in flaring last year,” the GGFR said. Venezuela and Mexico also reduced flaring significantly in 2017, while Iran and Libya saw significant increases.
The article below was published in Interfax’s Natural Gas Daily when Peter Stewart was chief energy analyst for Interfax. Peter spoke at the Gas Asia Summit held 31 October-1 November in Singapore.
LNG Canada took FID on 1 October on a C$40 billion ($32 billion) plan to build a two train 13 mtpa facility at Kitimat in northern British Columbia. The plant could be expanded to four trains with a total capacity of 26 mtpa in the future. Kitimat is the traditional territory of the Haisla Nation, which the company said supports the project.
Spotlight on Canada
Speakers at a Canada Spotlight presentation at last week’s Gas Asia Summit in Singapore said Canadian LNG was “open for business” and that between five and 12 plants could be operating in the country by 2030 now LNG Canada has paved the way. However, with more than 200 mtpa of new liquefaction capacity proposed in the United States alone, new entrants such as Mozambique due to take FIDs in H1 2019, and Qatar already planning to expand its LNG capacity to 110 mtpa, the scale of the future Canadian projects is likely to be a bone of contention.
Western Canada is only 8-9 days sailing time from Asian markets – around half the time from the US Gulf Coast. Bigger vessels could be used to export LNG from the region because there is no need to traverse the Panama Canal, which improves freight economics. However, modular and small-scale LNG have become popular in recent years because of market uncertainty.
Pacific Oil & Gas is tipped as the next company likely to take an FID, on its small-scale (2.1 mtpa) Woodfibre project in Squamish, British Columbia. The company’s president, Ratnesh Bedi, said last week in Singapore that an FID would be taken “within months”. Woodfibre signed a heads of agreement with China’s CNOOC Gas & Power in September for potential offtake of 750,000 tpa for 13 years starting from 2023.
While Woodfibre is small, there are bigger projects at earlier stages of development, such as Steelhead LNG. Steelhead plans to export LNG from Sarita Bay on Vancouver Island and is targeting FID in 2020. The company filed a project description in mid-October with provincial and federal regulators for the Kwispaa project, which is being co-developed with the Huu-ay-aht First Nations, an approach that the company believes is unique. The plant will have a potential capacity of 24 mtpa.
Woodfibre and Steelhead are among nearly 50 projects that have sought export licences from the National Energy Board to export gas, LNG or NGLs from Canada. Many analysts had been pessimistic about the potential for Canadian LNG exports because the indigenous peoples of Canada, the First Nations, have in the past resisted industrial developments on land they consider sacred. This has also made it difficult for pipeline projects to get approval. Now that the First Nation hurdle has apparently been cleared, other Canadian liquefaction projects are likely to follow more quickly.
Canada could be ready to export as much as 60 mtpa of LNG from its east and west coasts by 2030, but there is a risk that the new capacity will scupper the recovery in prices that is expected as LNG demand catches up with the supply overbuild. New projects will need to have buyers signed up if they are to attract investment, but the number of competing LNG sources worldwide may encourage buyers to rely on short-term or spot supplies. New long-term contracts may be difficult to negotiate given market uncertainty over the level of future supply and Canada’s inexperience in LNG trading.
LNG Canada is led by Shell, but with several LNG consumers among the investors – including Petronas, PetroChina, Kogas and Mitsubishi. The inclusion of buyers as equity holders may be a model for future projects to succeed.
More of a buzz than usual at the Gas Asia Summit in Singapore this year. Gone were long faces about low prices — indeed, the big players in LNG seems to have forgotten the supply glut ever happened. The mood was upbeat: not quite business as usual, more like a shot of strong coffee after a heavy night out. I had a feeling that people were rolling up their sleeves having made some big decisions. GAS was part of Singapore International Energy Week (SIEW) and as ever the island is buzzing.
This conference had three big takeaways for me: Canadian LNG is no longer a pipe dream. It will happen, and it will probably be on a big scale. The Shell FID gave a clear signal that, despite the complex permitting process, it can be done. A Canada spotlight panel reckoned that Canada could have 5-12 liquefaction projects up and running by 2030, on both the east and west coasts. Exports will be of the same magnitude as those from the US, Qatar or Australia. LNG in shipping is becoming a reality. Shipyards are busy preparing vessels for the IMO 2020 regulation, but older vessels will be scrapped rather than retrofitted. The next generation of boats will be dual-fuelled or LNG ready, but the yards also have orders for LNG-fuelled vessels from barges to tankers. What we are seeing now is the seeds of a new industry. This is no longer something that is waiting to happening, it is happening now. Islands are getting smart about energy. Advising SIDCs on fuel supply has always been my idea of a dream job, and I met a gentleman who was doing just that over lunch. LNG is the fuel of choice, as it ticks all the boxes: lower carbon than diesel, energy intensive, resilient and with lower investment cost than alternatives such as energy storage. Mega-trends
After a conference, it’s important to think about what was not said, as well as what was said. Were there elephants in the room that no-one talked about? Yes. A whole herd of them. Here are just two:
The benefits of LNG vs diesel are crystal clear, but I felt that many in the gas industry were in denial about the potential for energy storage. Maybe batteries are the next big story, despite all the skepticism. Lithium has already had its first supply shock, after prices soared above $20,000/t a couple of years ago because supply couldn’t meet demand. The battery brigade are already looking at lithium alternatives such as selenium, costs are declining, and battery life and range improving. It cannot yet replace gas as a backup fuel for intermittent renewables, but by 2030? Perhaps.
King Coal has lost its crown, but no-one seems to entertain the idea that coal might make a significant comeback. I never understood the idea of Clean Coal, but if Carbon Capture and Use (CCU) were possible on a large scale, it would be a game-changer. Researchers are looking into ways to solidify emissions and potentially also finding uses for the solids. The dash for gas in China and India has been driven as much by air quality concerns as GHG emissions. CCS as a carbon disposal technology remains out of reach, but CCU could be a game-changer.
The article below was published in Interfax Natural Gas Daily on 1st November 2018. Peter spoke at the Gas Asia Summit during Singapore International Energy Week, and chaired a panel discussion on new uses for LNG.
Shipping companies around the world are scrambling to meet new fuel standards being put in place by the EU and the International Maritime Organization (IMO). Although the switch will not be immediate, LNG is back on the table again as potentially the main beneficiary.
Delegates at the Gas Asia Summit in Singapore this week said many shipping companies are largely unprepared for the tightening of the IMO regulations, which would see the limit on the sulphur content of marine fuels cut from 3.5% to 0.5% worldwide by 2020. Shipyards are full with vessels being converted to meet the new regulations and orders have picked up for new LNG-fuelled ships.
Under the EU’s Monitoring Reporting and Verification regulation, which came into force in July 2015, shipping firms must collect data on emissions from their vessels on a voyage-by-voyage basis from this year. The data will be collated by the European Maritime Safety Agency, and aggregate emissions data will be published in June 2019. The data will over time be used to bring the shipping sector into the EU Emissions Trading System.
In parallel, the IMO introduced regulation 22a of Marpol Annex VI in March. This will require all vessels above 5,000 gross tonnage to keep a detailed record of their fuel consumption from 2019. Under the new rules, shipping companies will have to issue a statement of compliance with the new fuel standards by the end of May 2020.
The new rules apply only to international shipping and not to vessels on domestic voyages, where exemptions are allowed.
Shipping companies have three options to meet the IMO fuel standard: switching to lower-sulphur fuels such as diesel or specially formulated heavy fuel oil; investing in scrubbers to clean the exhaust from their vessels; or using LNG, either by buying new LNG-fuelled or dual-fuelled ships or retrofitting vessels to allow them to run on the fuel.
Oil price spike
The new standards being introduced in 2020 are the biggest challenge the refining industry has faced in more than a decade. Philip Verleger, a veteran oil consultant, has predicted the new rules will contribute to a massive spike in oil prices in 2020. Verleger issued a report in July that predicted that oil prices could rise to $200 per barrel – and perhaps double that – because the refining industry will be unable to make enough diesel to meet the demand created by the new IMO standards.
LNG has for years been touted by oil and gas companies as a potential alternative to fuel oil and diesel in the transport sector, and its greater uptake could be the key to a step-change in global gas demand growth. But the volatile spread between oil and gas prices has to date discouraged shipping companies from investing in gas-fuelled vessels. Many companies looked at making the switch when oil was above $100/bbl, but the drop in oil prices in 2016 to below $30/bbl took away the incentive to do so.
Ports around the world are rushing to ensure that fuels meeting the IMO standard are available in time for the 2020 deadline. Singapore – the world’s largest bunkering port – is already offering LNG bunkering on a small scale, and its first LNG bunkering barge will be operating by mid-2020. The Singapore Maritime and Port Authority has invested around $20 million in building the necessary infrastructure to supply LNG to vessels. Other large ports in emissions control areas such as Rotterdam and Los Angeles already offer LNG, but uptake of the fuel has so far been restricted mainly to coastal vessels or image-conscious cruise firms.
By Peter Stewart, Interfax Chief Energy Analyst Interfax Global Energy held a breakfast briefing with consultancy Baker & O’Brien which posed the question: Permian gas: Pulling the Rug from Under Oil-Indexed Prices. The piece below explores the growth of Permian gas and how it will impact the global LNG market.
LNG exports from the United States are often touted as a cheap alternative to oil-indexed LNG, but the reality is more complex.
Although Cheniere’s model uses the Henry Hub as a price reference, LNG sold from the company’s Sabine Pass LNG plant reaches end-users mainly through oil-indexed term contracts on a delivered ex-ship basis or on the spot market. This because of the predominance of portfolio players among those taking gas from operational US LNG plants. Portfolio players typically make a margin between the Henry Hub-related free-on-board acquisition price and the oil-indexed sale.
That has created a multi-tiered market with differentiated pricing and resulted in a switch from inflexible long-term delivered contracts to shorter-term and more-flexible pricing structures, which have abandoned clauses restricting the final destination of cargoes. Even within oil-indexed deals, flexibility can be achieved by more frequent renegotiation clauses and by the flexible use of slopes and S-curves.
If US exchange operator CME Group’s proposed physically deliverable LNG futures contract at Sabine Pass becomes a reality, it would allow even more flexible price-risk management, as derivatives such as options and swaps could be tied to the price of the futures contract.
Nowadays, the consensus is that Henry Hub gas prices will remain low relative to oil – especially if geopolitical events and upstream underinvestment cause oil prices to spike higher. ‘Permania’ in the Permian Basin looks set to continue that trend. A 600,000 barrel per day rise in Permian oil production in 2019 will prompt a sharp rise in associated gas output. Dry gas production from the basin is expected to double from 2017 levels by 2025.
Almost all of that extra gas will go to the Gulf Coast for sale as LNG, according to Robert Beck, a consultant at Houston-based Baker & O’Brien. Beck was speaking at a roundtable discussion on Tuesday hosted by Interfax and Baker & O’Brien titled: ‘Permian – Pulling the rug from oil-indexed LNG prices?’
Citing public sources including the US Energy Information Administration, Beck estimated that an additional 100 mtpa of LNG could be available from 2025 as a result of the production growth from the Permian and other US shale plays.
US LNG’s competitiveness against other supply sources will depend on how much new capacity is built around the world over the next decade.
US LNG export capacity stands at around 25 mtpa. It will rise by a further 55 mtpa by around 2021 as plants come online that are either under construction or have taken FID and been approved by the Federal Energy Regulatory Commission and the Department of Energy. However, projects amounting to 100 mtpa in additional liquefaction capacity have also been approved in the US and Canada but have yet to reach FID. And double that capacity again has been proposed but not yet permitted.
Although Shell has warned that project FIDs need to be taken to ensure adequate liquefaction capacity to meet demand, the supply glut that has until recently depressed LNG prices could be extended if demand disappoints.
Global LNG imports hit 298 mt in 2017, according to a 2018 report from gas importers group GIIGNL. If the 4% annual growth in demand projected by some majors becomes reality, it would see LNG demand hit 405 mt in 2025 and around 500 mt in 2030. With global capacity at 365 mtpa at the end of 2017, shale gas production fuelled by Permian gas would create a potential surplus by 2025 if it is all liquefied and exported as LNG.
Forecasting
Most people associate forecasting with quantitative methods often lumped under the umbrella designation “number crunching”. But good forecasts can be made based on expert judgement. Asking the right questions, seeing a problem clearly and thinking logically through the range of possible outcomes can all result in the right decisions being made.
It is certainly true that econometric and technical analysis use complex mathematical and statistical techniques to measure relationships and predict outcomes more precisely. But you no longer need a Kray supercomputer to do the calculations. Predictive analytics can now be done on a laptop and in Excel, although there are also good econometric packages that supplement the analysis. Art or science?
My experience is that forecasting is as much an art as it is a science. I vividly remember my first job in a forecasting team, when the model threw up a result that clearly made no sense in terms of “gut feeling”. My colleagues tweaked the model with what they jokingly called fudge factors, to get a result that was more intuitively believable. So much for econometric rigour!
It’s important to encourage a diverse approach to forecasting, as most good forecasts are the result of teamwork and even the best “super-forecaster” has periods where he or she loses their magic touch. That’s inevitable, as there is always a probabalistic element in forecasting performance; often, the forecast is accurate, but the timing is wrong, and I prefer to keep experience within a team rather than sacking staff like football managers. That said, it is important to monitor and measure the accuracy of forecasts on a regular basis.
There are three main types of forecasting used in energy analysis, often combined in different ways depending on whether forecasts are short-, medium- or long-term:
Fundamental Analysis
Econometric Analysis
Technical Analysis
Fundamental Analysis
Fundamentals refer to the basic economic forces that drive prices: supply, demand, stocks, trade and competitors.
Fundamental analysis builds up a picture of whether the market is likely to be over- or under-supplied with a commodity in a particular time horizon, based on the various and often highly diverse economic and market drivers.
These often differ across time horizons: for example, demand may be driven in the short term by weather events, seasonal factors, trading positions, and do on; and in the longer term by GDP and population growth, wealth trends, government policy and trends affecting the price of competing commodities.
Similarly, supply may be affected in the short term by production shocks such as force majeure decisions, geopolitical events, cartel decisions, and unscheduled outages; but in the longer term, price trends, the availability of finance, investment decisions and the price of competitors may have a bigger effect.
Stocks are more difficult to predict because they depend closely on the time gradient of the market, which in turn is affected by the supply-demand fundamentals.
Competitors are also complex to incorporate in a forecast, partly because game-changing technological advances can be Black Swans, and because the price of competitors affect each other mutually.
Finally, imports and exports can be combined with the supply-demand analysis to create balances. The balance will affect prices and trade flows, defining whether a particular geographical market is long or short in certain timeframes. Econometric Analysis
Econometrics can be used to measure the relationships between variables, and these measurements can be used predictively to make forecasts – predictive analytivcs.
Econometrics is often associated with correlation and regression analysis, but there are a panoply of more complex techniques. Many of these are very useful.
The days when R2 was the only measure that mattered are long gone. Econometricians have refined their techniques to ensure that the relationships they identify are meaningful. Rigourous tests are made for the significance of an economic relationship, including causation testing.
That said, it is important that the analytical techniques are applied appropriately, and in ways that are consistent with economic theory.
It’s not uncommon for the mathematical wizardy of the Quants to be confused with a kind of super-intelligence — the means can all too easily become an end in itself, and you find that decisions are taken based on the mystique of little understood mathematical methods, based on little more than blind trust.
Econometrics is a useful toolbox, but it is still a toolbox. Quants make good and bad calls like anyone else.
They should not be accorded more prestige than any other member of the analytics team. Certainly it is reasonable for a manager to ask questions about the techniques used, and to expect a cogent explanation for any forecast.
My rule of thumb is that if the econometric analysis can’t be explained in simply language and is not easily understood by an intelligent manager, it should be taken with a pinch of salt. Technical Analysis
Technical analysis refers to techniques that are based on the price of a commodity, rather than the supply-demand pressures and events affecting its value. A technical analyst examines how prices have moved in the past as the basis for a prediction about how they will move in the future.
The technique has been controversial. During their heyday in the heady days of the 1980s, major financial houses and trading firms paid fortunes for chartists’ predictions of where markets were heading. A series of academic analyses typically concluded that there was little evidence that the techniques used were statistically meaningful. Nevertheless, many traders still use the tools in trading decisions, particularly but not exclusively in taking short-term trading decisions.
The commonly used technical analysis tecniques include: drawing trendlines on charts; identifying chart patterns including continuation and reversal patterns; moving average analysis; momentum and stochastic analysis; volume and liquidity indicators and cyclical and wave analysis. But there are endless more varieties, some of which ressemble astrology or tea-leaf reading rather than quantiative analysis of price movements.
One of the problems with evaluating the success of technical analysis is the sheer variety of indicators that have been proposed. Chart patterns often “work” in the sense that they result in a series of good calls, but frequently this peters out after 3-4 runs. I diagree with those who say the techniques are self-fulfilling. A more serious criticism, I beleive, is that it often difficult to pin down whether technical forecasts are made with perfect hindsight, or whether the trading signals genuinely result in taking profitable positions ahead of time.
Pure chartists often refuse to engage with market fundamentals because they say this colours their analysis of the price signals. I believe this is sheer nonsense. It stikes me as about as daft as someone refusing to use a map to reach their destination because they want to find their way by instinct.
Better data, better decisions. That’s the tagline used by the Joint Organisations Data Initiative to flag the need for accurate and transparent energy data.
At Resource Economist, we are acutely aware of the variable quality of energy and natural resource data collected by government ministries and statistical offices around the world.
Many data users assume that all statistics are equal and use the data in commercial and investment decisions without any questions as to whether it is fit for purpose. Research and consulting reports may also be inconsistent and at times opaque in how they source and display the data and forecasts presented.
The experience of JODI is that not all data is created equal. That’s also what we believe.
Some countries produce timely and reliable data, others do not. Data quality standards vary over time, as government commitment to “gold standard” statistical methods – and the funding needed to ensure its delivery — is not always guaranteed.
That’s why I created the TARGET system to analyse and review the quality of data from countries and inter-governmental data providers.
The TARGET system is used to create data quality rankings based on a set of specific, objective criteria. This provides a consistent standard for data quality evaluation, but one that is tailored to ensure relevance to the circumstances of those providing the data sets. The methodology is outlined in the attached PDF.
I have been involved in the JODI user community for several years, attending their New Delhi forum in 2014 and then participating as a speaker and chair at user events in London and Switzerland, both as an analyst / economist and as a media partner.
The JODI staff are passionate about the need for high quality, transparent energy data – as are the partner organisations of the International Energy Forum.
They currently collate data from around 70 countries on oil and around 55 on gas, and they have discussed expanding the data sets to include coal and other energy commodities. I have tracked the growing success of their efforts in a series of articles and blog entries over the years.
Resource Economist provides a number of services related to data and data analysis, including peer evaluation of research and consulting reports and independent feedback on the data underpinning such reports and the forecasts they contain.
We also plan to publish a series of region specific analyses in 2019 on the national source data for energy and natural resources. Please contact us if you require further details.
Contact: Peter Stewart +44 (0) 7703 341 529
The article below by Peter Stewart was published on April 11, 2018 in The Analyst column of Interfax Natural Gas Daily, an analytical newsletter focussed on latest developments in the global gas and LNG market.
A trade dispute between the United States and China kicked off in March when US President Donald Trump announced a 25% tariff on steel and aluminium imports from all countries except Canada and Mexico. Since then, the US has proposed additional tariffs on more than 1,300 Chinese goods from the aerospace, machinery, computer and medical industries – sparking threats of retaliatory tariffs from China.
The quarrel has erupted against the backdrop of China’s increasingly assertive profile on the world stage, which has triggered geopolitical tensions between Beijing and Washington. Chinese President Xi Jinping outlined his vision for China’s emergence as a first-rank global power in two keynote speeches in recent months. Beijing has meanwhile accelerated plans to develop disputed islands in the South China Sea, putting it at odds with US allies in the region, including Japan.
But despite the mounting tensions over trade, Washington has talked up the prospect of higher US exports of fossil fuels to China. Peter Navarro, the director of the White House National Trade Council, said last week the US “would love” to export more LNG to China, although he added this would not make a dent in the trade deficit between the countries. “We’re going to do everything we can to sell China more LNG,” he said.
US exports of LNG to China have risen substantially in recent months. The US sent 1.95 billion cubic metres of LNG to China in Q4 2017 – double the total volume exported during the first three quarters of the year – according to Energy Information Administration data. Exports in January 2018 were three times higher year on year.
China has threatened to place tariffs on 106 US products, but so far liquefied propane is the only energy product on the list, and no date has been given for when these measures would start. A variety of specialist petrochemicals and lubricants are also included. Although tariffs on these goods could indirectly affect US petrochemical manufacturers – who typically use ethane from shale production as their main feedstock – fuel exports from the US look unlikely to be affected unless the dispute escalates seriously.
China has prioritised gas in its fuel mix to meet air quality standards and Paris agreement targets. It imported 19.7 bcm of gas in the first two months of 2018, up by more than 40% from the same period in 2017, while gas consumption hit 45.8 bcm, up by 17.6%, according to recent data from the National Development and Reform Commission.
Twin tensions
Global equity markets slumped last week as the risk of a trade war was heightened by Trump’s Twitter remarks, but they rebounded this week after conciliatory comments by Xi. Commodity markets, meanwhile, have become increasingly volatile as the twin threat of heightened tension in the Middle East and the risk of a trade war pulls prices in opposite directions. Brent crude futures recovered to around $71 per barrel after Xi’s comments, having dropped to lows of around $67/bbl last week.
The stakes are high. China bought $130 billion worth of US goods in 2017, making it the third-largest market for US exports behind Canada and Mexico. The US imported more than $500 billion worth of Chinese goods in 2017, resulting in a US trade deficit with China of $375 billion.
Xi has promised to cut automotive tariffs this year as well as to improve intellectual property protection, open up financial services and raise foreign ownership limits within the auto sector.
The US has demanded action rather than promises. Trump had earlier threatened an additional $50 billion in tariffs after an August 2017 probe into Chinese intellectual property theft. China has vigorously denied the US accusations of unfair trade practices and vowed to retaliate if the US puts tariffs on Chinese goods.
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Date: 21 February 2018 Topics: Interfax chief energy analyst Peter Stewart provided an outlook on the European refining sector in light of recent price developments in the oil and gas markets.
The Price Reporting Agency Platts, part of S&P Global, has recently issued a Special Report on the Dated Brent benchmark. The price of Brent crude oil from the North Sea has been used for the last 30-odd years as the pricing reference point for billions of barrels of oil – some estimates suggest that as much as two-thirds of the 95 million barrels per day of crude oil produced and traded globally is directly or indirectly linked to Brent price. The catch? Over the last decade, Brent production has declined to the point that Platts has had to use the price of other grades such as Forties, Oseberg, and more recently Ekofisk and Troll, in its calculation of the Brent price. The Platts report: “Riding the Wave: The Dated Brent benchmark at 30 years old and beyond” can be downloaded at the link below: https://www.platts.com/IM.Platts.Content/InsightAnalysis/IndustrySolutionPapers/sr-north-sea-riding-the-wave-dated-brent-feb-2018.pdf
Date: 7 February 2018 Topics: Peter Stewart delivered a 5-year outlook for the Global LPG market. The conference takes place in Lisbon, Portugal and includes a global line-up of distinguished speakers. Link: LPG Europe Summit
The article below appeared in the 3 January 2018 edition of Natural Gas Daily, published by Interfax Global Energy Services.
Civil unrest in Iran has led to at least 21 deaths, and violent clashes between security forces and protesters that began in the northeastern city of Mashhad on 28 December have spread. Although the Iranian unrest initially focused on economic grievances, the religious establishment and security forces have subsequently been targeted by protesters.
Iran’s supreme leader Ali Khamenei, who despite being a cleric has de facto control of the army, accused the country’s enemies of causing the troubles, alleging that they had used “cash, weapons, politics and the intelligence services” to fan discontent.
The unrest has led to speculation that the United States may press to impose sanctions on Iran again. US and EU sanctions were lifted in July 2015 after the five permanent members of the UN Security Council and Germany, known as the G5+1, reached a deal with Iran on its nuclear programme. Iran and the joint commission of the G5+1 reiterated their commitment to the agreement, which former US President Barack Obama saw as his key foreign policy success, in December 2017.
However, current US President Donald Trump has repeatedly threatened to go back on the deal, and in a series of recent messages on Twitter blamed Iran’s leadership for the latest unrest. Calling the Iranian regime “brutal and corrupt”, he tweeted: “The people have little food, big inflation and no human rights. The US is watching.” Trump also alleged that “all of the money that President Obama so foolishly gave [Iran]” had either gone into the pockets of those in government or had been used to fund terrorism.
Oil prices settled close to a 30-month high on the first trading day of 2018. North Sea Brent crude oil futures hit a peak of $67.29 per barrel on 2 January, a 2% gain from the previous close and exceeding the 2017 high of $67.10/bbl reached on 26 December. The front-month contract closed at $66.24/bbl.
Iranian output
Iran is a major oil and gas producer, with the world’s fourth-largest proven crude oil reserves and the second-largest proven gas reserves. There is no sign yet that the troubles have affected oil and gas production, but if this were to happen it would have a major impact on the markets, as would the return of sanctions.
The sanctions imposed by the US and the EU in 2011 and 2012 had a profound effect on Iran’s energy sector. They caused a drop of around 1 million barrels per day (MMb/d) in Iran’s crude oil and condensate exports as European companies were banned from buying Iranian oil and a number of Asian refiners also cut their offtake. The sanctions also affected upstream investment in oil and gas projects, causing project cancellations and delays in implementing the planned 24-phase development of the South Pars expansion project.
Iran is OPEC’s third-biggest crude oil producer after Saudi Arabia and Iraq. Iran produced 3.9 MMb/d of crude oil in 2017, 2.1 MMb/d of which it exported. Iran’s crude oil production is currently around 720,000 b/d higher than it was in 2015 before US and EU sanctions were lifted. An estimated 62% of Iran’s crude oil exports went to Asia last year, while around 38% was sold to European refiners.
Iran is one of the world’s top five gas producers. It produced 202.4 billion cubic metres in 2016, up by 6.6% from 2015, according to BP Statistical Review of World Energy. But Iran consumes almost as much gas as it produces, so it is not a major exporter. BP estimates Iran’s consumption reached 200.8 bcm in 2016, up by around 5% from the previous year, while exports stood at 8.4 bcm – more than 90% of which went to Turkey.
The article below by Peter Stewart appeared in The Analyst column of the July 9 edition of Natural Gas Daily, a gas market publication by Interfax. Please note that all views expressed reflect the opinions of the author, and are for information only.
Lithium-ion (Li-i) batteries are the fastest-growing technology in the power storage sector, according to a recent report by Forum for the Future, which tapped insights from half a dozen key executives in the UK energy sector. But the rising cost of lithium and cobalt, which is a component of the cathodes used in Li-i batteries, could slow their progress.
Cheaper batteries are seen as a potential threat to gas demand because they could reduce the need for the fuel to deal with intermittency in renewable power generation. The World Energy Council issued a report on energy storage, E-storage: Shifting from cost to value 2016, which said Li-i batteries were among the most efficient technologies on offer and predicted a sharp fall in costs.
“The cost profile of lithium batteries has been strikingly similar to that of solar PV, falling four-fold in six years,” the Forum for the Future report said.
However, the vast bulk of solar PV cells are made from crystalline silicon, which is among the most abundant of elements in the earth’s crust. Costs have fallen sharply in recent years largely because of process improvements and growth in the scale of manufacturing.
In contrast, lithium is a relatively rare mineral, the price of which has risen sharply as demand has grown. Reserves are concentrated in a few countries: Chile and Australia account for the bulk of world production; and while a number of countries in Europe, Latin America, Asia and Africa have deposits, Argentina and China are the only other states with substantial reserves.
The price of lithium carbonate soared by as much as 300% year on year in 2016 because of an acute shortage of spodumene, a mineral rock that lithium is extracted from, which is mainly found in Australia. Chinese demand for lithium briefly pushed lithium carbonate prices above $20,000/ton in 2016. The price spike led to a scramble of mining activity that has now boosted production, but prices remain above $10,000/ton.
Cobalt is an even rarer commodity, with half of the world’s mined production coming from just one country: the Democratic Republic of Congo. Elsewhere, cobalt is produced as a byproduct of copper and nickel mining, both of which have declined because of low prices. Batteries account for 80% of refined cobalt demand. With China dominating the production of refined cobalt, supply is expected to remain tight as battery demand surges towards the end of the decade driven by increases in electric vehicle production.
Future demand
Elon Musk’s Tesla recently unveiled its Model 3 electric car, which uses Li-i batteries made by Panasonic. Tesla is also developing utility-scale applications for Li-i batteries. It signed a deal with the state of South Australia in July to install a 100 MW Li-i battery – more than treble the capacity of the world’s largest existing battery.
The US Geological Survey estimated demand for lithium rose by 14% between 2015 and 2016. Demand is expected to grow even more rapidly as electric vehicles are rolled out on a larger scale over the next few years, although it will slow as battery recycling becomes more common. New lithium production from Australia and Tibet should ease the upward pressure on prices over the next year, and alternative battery designs are available if supply is unable to meet demand in the longer term.
The World Energy Council’s report said that although Li-i is the leader, “many other possible battery chemistries are in development or in the research phase, and could well supersede these”. The report singled out flow batteries as a significant potential competitor.
Faced with the possibility of tighter sanctions on Venezuela, US refiners are switching to lighter crude slates and sourcing more heavy grades from Canada and Mexico. Asian refiners look set to reap the benefit.
The US government last week imposed sanctions on 13 Venezuelan officials, and further sanctions are likely to be imposed in the next few weeks by the administration of US president Donald Trump. Even if these do not result in an import ban on Venezuelan crude, refiners look set to wean themselves off these grades due to the risk of supply disruptions as civil unrest in the country mounts. Marathon Petroleum and Valero have already said that they would process more light and sweet crude oil in the next quarter, thus relying less on Venezuelan and Middle Eastern barrels. US refiners look to Canada, Mexico
Venezuela depends on exports of crude oil and refined products for 95% of its revenue. Most of the Venezuelan crude oil imported by the US is processed on the Gulf Coast. The best alternative for these refiners will be Canada, which also produces heavy sour grades similar in quality to Venezuelan crude. However, pipeline constraints and railway transport will add up to $2.50/bbl to refiners’ average costs, at least in the early stages of intensified sanctions. Canadian benchmark West Canada Select (WCS) prices have surged – the discount to light sweet benchmark West Texas Intermediate (WTI) has narrowed to around $5 per barrel ($/bbl) in recent days. The price gap between the Midwest and the Gulf Coast could lead to higher profits for refiners in the Midwest at the expense of their Gulf Coast counterparts.
US crude imports from Venezuela have varied between 600,000-800,000 bpd in recent weeks, accounting for almost 10 percent of US requirements. Citgo Energy, the US refining arm of Venezuelan state-run PDVSA, Valero Energy, Phillips 66, Chevron and PBF Energy have been the key buyers of Venezuelan crude in 2017. The crude slate at BPF’s 190,000-bpd Chalmette Refinery in Louisiana has been more than 90% Venezuelan oil in recent years, while crude processed in Phillips 66’s 145,000 bpd Sweeny refinery in Texas and Valero’s 370,000-bpd St. Charles refinery in Louisiana has predominantly been from Venezuela.
Although Mexico would benefit from less competition from Venezuelan crude oil on the US Gulf Coast, its exports to Asia and Europe would suffer. Mexico has traditionally exported nearly two thirds of its crude oil to the US. Other Latin American oil producers would also benefit from an import ban on Venezuelan oil but their overall production has been declining in recent months. Any increase in Middle Eastern crude oil exports to the US is likely to be marginal because of OPEC/ non-OPEC production cuts.
US service companies such as Halliburton and Schlumberger are expected to leave Venezuela completely due to sanctions. The companies announced in 2016 that they would be curtailing their business activity in the country, although this decision appears to have been triggered in part by PDVSA’s tardiness in making payments to service firms. Middle Eastern crude oil grades face more competition
Surplus Venezuelan crude oil supplies are expected to be sold in Asia, primarily China and India. This has the potential to widen the discount of Middle East marker crude Dubai’s to North Sea Brent by 20 to 40 cents/bbl. Middle Eastern crude oils that are similar in quality to Venezuelan crude include Arab Heavy from Saudi Arabia and Basrah Heavy from Iraq. These grades will suffer, although the impact is reduced by OPEC production cuts which have significantly reduced supplies of heavy fuel oil-rich grades. Increased exports from Venezuela into Asia would be accompanied by a fall in the region’s imports from countries such as Mexico.
Venezuelan oil exports to India could hit 1 million bpd if the country stops exporting to the US. Reliance and Essar have the main Indian beneficiaries of heavy crude oil from Venezuela. Russia’s Rosneft, which receives Venezuelan oil in return for loans, will benefit from its 49% share of Essar Oil. PDVSA reportedly owes India’s ONGC Videsh about $600 million in late dividends for their joint crude oil project at San Cristobal. The Venezuelan state oil company is now settling these debts by dedicating exports of 17,000 bpd for this purpose. Rising Venezuelan exports could reduce Indian refiners’ interest in Canadian crude. State-owned Indian Oil Corporation (IOC) acquired its first cargo of US and Canadian heavy crude in July this year, as medium and heavy sour supplies from the Middle East have dried up.
China will also profit from additional deliveries from Venezuela. China’s indigenous oil production has suffered hugely in the wake of lower oil prices. Venezuela’s exports to China to service debts owed to the country have almost doubled since oil prices collapsed from their mid-2014 highs above $100/bbl. Venezuelan imports to worsen economic woes
The debt burden will get worse if the US applies sanctions on the Andean nation. Venezuela also imports gasoline and US light sweet crude oil for blending with its own heavy crude oil. Caracas will have to pay a higher price for gasoline imports and would be forced to source light crude from long-haul suppliers such as West and North Africa, if sanctions prevent it from taking US light sweet crude. Given the country’s spiralling debt burden, this could intensify the social and economic problems it faces.
Venezuela needs to blend its crude with that from countries such as Libya, Algeria and Nigeria to reduce the concentration of impurities such as metals and salt. Naphtha has also been used to improve the quality of Venezuelan crude oils. PDVSA could replace US naphtha supplies with European supplies but once again would have to pay higher freight. Similarly, US gasoline can be substituted by the European material while diesel can be sourced from the Middle East or Russia, but again at higher cost. Conclusions
US sanctions against Venezuela are expected to be supportive of global crude oil prices, particularly if the political instability results in supply disruption, or to a perception that Venezuela has become an unreliable supplier. Unless this happens, however, Venezuelan crude oil supplies will simply be redirected towards Asia, increasing the competition for Middle Eastern grades, but doing nothing to reduce global oil stocks. Heavy sour crude differentials would come under pressure, but outright prices would be little affected.
The article below appeared in The Analyst column in the 26 July issue of Natural Gas Daily, a daily outlook on the gas and LNG markets by Interfax Global Energy. Peter Stewart spoke at the London Centre of International Law Practice on the Caribbean region’s oil and gas potential.
Small Island Developing States in the Caribbean are transitioning from legacy energy supplies based on refined products to renewable sources including solar, wind and biofuels. The region also has significant oil and gas potential, but unresolved border issues have discouraged its exploitation.
Whereas gas is being hailed by IOCs as the fuel of the future because it can support growth in renewables by reducing intermittency problems, the high cost of delivering gas to the islands makes it unviable in economic terms in the Caribbean.
So far, only three LNG terminals have been installed on the Caribbean islands. Jamaica installed the Golar Arctic FSU at Montego Bay under a two-year contract in 2016, adding to the land-based regas facilities at Penuelas in Puerto Rico (2000) and Punta Caucedo in the Dominican Republic (2003).
One of the challenges faced by the islands is the small scale of their LNG shipments. Typically, the three terminals take less than one cargo per month, which makes delivered costs high. Shipments of containerised LNG from the United States to Barbados in 2017, for example, have been priced at more than $10/MMBtu on a delivered basis – nearly double the average LNG spot price to Latin America, which is around $5.50/MMBtu.
LNG can be supplied from the 15 mtpa plant at Point Fortin in Trinidad and Tobago, operated by Atlantic LNG, but delivered costs are often dollars higher than prevailing wholesale prices because of the scale and logistics of deliveries.
Trinidad is already having difficulty meeting the growing demand for gas from local industry, which includes methanol and ammonia plants, while at the same time servicing its LNG export commitments. The country is exploring new gas-prone acreage, but only one project is due to start up soon: Juniper, owned by BP (70%) and Repsol (30%), in H2 2017. The project involves development of the Corallita and Lantana gas fields in the Columbus Basin to the southeast of Trinidad. Several hydrocarbon reservoirs off Trinidad are close to the marine border with Venezuela. Recent finds in the highly prospective waters offshore Suriname and Guyana are also close to Venezuelan waters.
The London Centre for International Law Practice seminar on hydrocarbons in the Caribbean, held on 21 July, heard that the lack of demarcation of marine boundaries between the islands and between them and countries such as Venezuela and Guyana has been a disincentive to developing the region’s substantial oil and gas resources. Climate change targets
The Caribbean countries have extensive plans to mitigate the impacts of climate change in the Intended Nationally Determined Contributions made under the Paris agreement. Oil price volatility has also been a problem for the region, so focusing on renewables in the energy mix provides economic security as well as having environmental benefits.
The Caribbean Community Energy Policy (CEP) provides a regional framework for the implementation of national plans. The Caribbean Sustainable Energy Roadmap and Strategy was developed under the CEP to provide a coherent strategy for transitioning to sustainable energy. Targets include reducing energy intensity by 33% by 2027 and carbon dioxide emissions by 22% by 2022 and 36% by 2027. Building up renewables in power generation is crucial for these targets to be met: the CEP envisages renewables contributing 28% of power by 2022 and 47% by 2027.
A September 2015 study by the International Monetary Fund recommended that the Caribbean countries reduce their exposure to oil price volatility by diversifying the power supply mix and improving energy efficiency through energy-saving technologies on the demand side.
Market analysis Although fuel oil demand is under threat due to a bunker fuel specification change in 2020, recent production cuts from OPEC and several non-OPEC countries have provided a lifeline to the bottom of the barrel. Furthermore, the advent of complex refineries in the Middle East, Asia and Russia is leading to tighter supplies. The fuel oil market has been on boil in all key refining regions this year and any increase in OPEC cuts has the potential to keep on buoying its prices, although the end of the cooling demand season in the Middle East could put a ceiling on cracks.
In the Middle East, regional demand for fuel oil is at its seasonal peak. Saudi Arabia consumed 625,000 bpd of fuel oil in April, the highest since October 2016, although the total fuel oil burn over the summer looks likely to be less than last summer because the kingdom’s utilities are using more natural gas.
In South Asia, Pakistan is seeking 950,000 mt of fuel oil for September as stocks at the country’s power generators have fallen to just 3 – 4 days of supply compared to the obligatory level of at least 10 days. In Pakistan, debt-stricken power companies frequently fail to pay their fuel oil suppliers on time, which leads to knock on problems in the international market. There has been talk that the government in Islamabad may intervene, but a long-term solution is not in sight.
Fuel oil flows to the Far East from the West are well below normal levels, because the strong fuel oil market in Europe is limiting flows to Asia. Arbitrage shipments for July are estimated to be just 5 million mt.
Fuel oil cracks in Asia have been around $5/bbl stronger than last year. The discount of Singapore 380 cst fuel oil to Dubai crude averaged around $1/bbl in July this year, compared to around $6/bbl in July 2016.
Venezuela’s fuel oil exports to China have almost vanished from the market in the East, as refinery problems have tightened supply. The country’s refineries are operating at less than 50 percent of capacity according to the trade union representative of the Venezuelan Federation of Petroleum Workers. Moreover, some Venezuelan ports are also facing problems, reducing refined product exports to Asia and Europe. This has exacerbated an already tight market. Less and less fuel oil is being produced in China. In fact, fuel oil output in the Middle Kingdom was down more than 1.5 percent year-on-year in June.
Although flows from the Middle East could pick up once the cooling season is over, reports have circulated that Saudi Arabia might reduce its crude oil exports unilaterally by up to a further 1 million bpd. This would reduce medium and heavy sour crude supply, indirectly cutting fuel oil production capacity. This means that fuel oil cracks could remain supported even in the northern hemisphere winter, when demand for the fuel usually eases.
Tighter prompt fuel oil markets from Durban in South Africa to Rotterdam in Holland have led to a backwardated market structure. One reason for this has been lower inventories. In the US, for example, residual fuel inventories have fallen to their lowest levels since January 2015. in Singapore, fuel oil stocks remain seasonally low, although they have recovered from the 2 1/2 year lows seen at the beginning of June. Euroilstock data shows EU-16 fuel oil inventories in June stood at around 11.5 percent below levels a year ago. Fuel oil stocks in the Amsterdam-Rotterdam-Antwerp (ARA) are down around 12 percent year-on-year. Although fuel oil stocks are relatively abundant at Fujairah in the UAE, this is largely due to weaker bunker demand in the wake of a trade embargo on Qatar imposed by Saudi Arabia and a number of its regional allies.
Due to surging demand, some trading houses are opting for shorter-period stockpiling of fuel oil . In Singapore, fuel oil storage rates have tumbled to $5-6 per cubic metre from $6.50-7.00 per cubic metre a few years ago. Indeed, some traders are stockpiling fuel oil on tankers as VLCC freight is down more than 50 percent from levels 18 months ago.
The fuel oil price rally has been helped by OPEC’s decision to extend its 1.2 million bpd production cut until March 2018. OPEC agreed the cuts, which were supported by pledges for a further nearly 600,000 bpd by a group of non-OPEC countries, in November 2016. Resource Economist estimates the production cuts have taken as much as 1.3 million bpd of medium and heavy sour crude off the market. Lower supplies from Latin America have resulted partially from natural declines rather than the OPEC/non-OPEC agreement. Only Saudi Arabia has tried to reduce lighter crude exports instead of heavier barrels but any additional cuts if implemented are likely to be medium and heavy sour.
Global fuel oil production supply is also decreasing with the start-up of sophisticated new refineries in India, China and the Middle East, which produce little or no fuel oil. Their advent has also led to the demise of simpler refineries, further tightening fuel oil supply. Russian fuel oil exports are also falling as the country’s refineries boost their processing depth, while the Kremlin has imposed a tax regime that equalises export duties on crude and fuel oil, lessening the incentive to export fuel oil.
Though fuel oil demand has been falling in developed countries, a number of non-OECD nations still depend on fuel oil for power generation, particularly in the Far East, the Middle East and South Asia. While China is now gradually reducing its fuel oil consumption, South Asia along with neighbouring GCC countries have become the dumping ground for the bottom of the barrel.
Conclusion
Although the International Maritime Organization’s decision to reduce sulphur specifications in bunker fuel to 0.5 percent from 3.5 percent by 2020 will have a detrimental impact on fuel oil demand, rumours of the death of fuel oil look greatly exaggerated. Downward pressure on fuel oil may re-emerge when oil producers end their crude oil production cuts but until then, fuel oil cracks are likely to remain strong..
The article below appeared in the Analyst column in the 12 July 2017 edition of Natural Gas Daily, an Interfax newsletter focussed on the global gas and LNG markets.
Iran’s deputy oil minister, Amir Hossein Zamaninia, said at the World Petroleum Congress in Istanbul this week that his country planned to ramp up gas production to nearly 1.37 billion cubic metres per day and oil production to around 5 million barrels per day (MMb/d) by 2021.
Zamaninia said Iran currently produces more than 800 million cubic metres per day (MMcm/d) of gas, equivalent to over 292 bcm/y, although output in 2016 was estimated at 202 bcm/y by the BP Statistical Review of World Energy. Iran’s oil production is currently around 3.7 MMb/d.
The planned ramp-up in production capacity suggests Iran aims to become a major player in the global oil and gas market now the United States and Europe have eased sanctions on the country. Tehran is particularly bullish on its gas plans because it believes the fuel will supersede oil in the global energy mix “in a few years”, Zamaninia told Turkey’s Anadolu news agency. Iran holds the world’s second-largest gas reserves after Russia and the world’s fourth-largest oil reserves.
However, Iran’s ambitious plans could put it at odds with rival oil and gas producers in the Middle East that also aim to boost production. Iran signed up to OPEC’s agreement with non-OPEC producers to cut oil production, which came into effect at the start of this year and is due to expire in March 2018. Geopolitical tensions between Iran and Saudi Arabia, the world’s largest oil exporter, have escalated since the 2011 Arab Spring. The Saudis and a number of allies recently broke ties with Qatar – the world’s largest LNG exporter, which shares the world’s largest gas field with Iran. Riyadh accused Doha of being too cosy with its regional arch-enemy. Tehran subsequently upped the ante by sending food aid to Qatar.
Iran is negotiating with a number of IOCs about developing the country’s production potential, and Zamaninia said his country aims to sign 10 contracts over the next 10 months. Discussions are being held on 27 projects that are collectively worth $200 billion, and the country expects to sign deals with Russian firms within the next 5-6 months, Zamaninia added. Iran has been discussing upstream projects with Gazprom and Lukoil. The plans suggest Tehran has not been thwarted by the threat of renewed US sanctions. Zamaninia said the recent deal with French major Total suggested a return to the era of sanctions is “very unlikely, if not impossible”.
South Pars contract
Iran signed its first memorandum of understanding since the sanctions were ended with Total in 2016, and earlier this month signed a $4.8 billion Iran Petroleum Contract with the French major and China National Petroleum Corp. (CNPC) to develop Phase 11 of the South Pars gas field. Total will be operator of the project, with a 50.1% share, while CNPC holds a 30% stake. Petropars, a subsidiary of state-owned National Iranian Oil Co., holds a 19.9% stake. The contract will be carried out in two phases over 20 years. Iran said it expects to produce 56 MMcm/d (equating to 20.4 bcm/y) of gas from Phase 11 once it is in full production. South Pars holds gas reserves estimated at 51 trillion cubic metres as well as 50 billion barrels of condensate and NGLs.
Zamaninia said Tehran is also considering the viability of a pipeline to send Iranian gas to Europe via Turkey. The project has been mooted in the past but is unlikely to be developed anytime soon as it would put Iranian gas into competition with Russian exports in a market that has seen little growth in demand in recent years. Russia is the largest supplier of gas to Europe and is a key regional ally of Turkey and Syria, which has long-standing ties with Iran. Meanwhile, Turkey plays a large role in the region’s geopolitics because it borders Syria, Iraq and Iran.
The price differential between light sweet crude oils and heavier sour crudes has narrowed as OPEC and several non-OPEC oil producers’ continue to implement output cuts. Rising sweet crude production in Libya, Nigeria and the US have also contributed to exceptionally narrow sweet/sour differentials, leading refiners in the West to process more sweeter grades in their refineries.
The Brent/Dubai EFS has remained below $1/bbl for several months, while Urals in Europe is now trading at the narrowest discount against Dated Brent since November 2014. In the US, Mars is trading at a discount of less than $1/bbl to US benchmark West Texas Intermediate (WTI). At these levels, it does not pay to process too much medium and heavy sour crude, especially in the West as fuel oil demand in the Atlantic basin is falling.
OPEC agreed to implement production cuts of nearly 1.8 million bpd with a group of non-OPEC countries from January 2017, and the last OPEC meeting in May agreed that the cuts would be extended until March 2018.
Asia has been hit hard by OPEC production restraint, which have choked off its main source of medium and heavy sour crude oil supplies. Refiners in the East are either resorting to sweeter grades or buying spot barrels from other regions, as interregional spreads tighten. Indian refiners have already developed an appetite for Russia’s main export grade Ural. Now, they are switching to Mars. The state-owned Indian Oil Corporation (IOC) is bringing a VLCC carrying 1.6 million bbl of the US grade along with 400,000 barrels of Western Canadian Select (WCS) to its refineries.
Unlike in the West, fuel oil demand is still relatively healthy in Asia. Therefore, the East is unlikely to replace medium and heavy sour crude with sweeter crude. However, higher sweet crude processing in several parts of the world is further stretching the already tight fuel oil market. New sophisticated refineries in Asia and the Middle East are not capable of producing as much fuel oil as older and simpler refineries.
While sour crude supplies have been reduced significantly, oil storage tanks are brimming with light sweet supplies especially in the Atlantic Basin. Continued low oil prices prompted the Energy Information Administration in the US to revise down its production growth forecast for US shale oil recently to 310,000 bpd from its previous forecast of 320,000 bpd. However, the rising rig count is a harbinger of further production additions next year.
Libyan output has surpassed the 1 million bpd mark, the highest level since June 2013. Nigerian exports in August are expected to reach 2 million bpd. Indeed, OPEC might ask these African nations to limit their supplies but only if they continue to increase.
The upshot for OPEC and non-OPEC oil producers is that a cut of more than 1.5 million bpd of sour production has been replaced with a similar volume of sweet crude oil from Libya, Nigeria and the US. Sour crude availabilities could be hit further if geopolitical problems in Venezuela persist.
Some medium sour stocks are being drawn down to make up for production cuts but once these have been absorbed, the sour market will tighten further. This will impact gasoil and fuel oil supplies as medium and heavy sour crudes have higher middle distillate and heavy distillate yields.
This could mean that fuel oil supplies remain tight even after the peak demand period during the northern hemisphere summer, despite lower cooling demand.
Moreover, heating fuel supplies could be stretched especially if the winter is harsh. There are already signs of higher middle distillate demand. India is sucking up more and more diesel due to strong economic growth. European economies are recovering, resulting in higher diesel demand, while shale oil producers require more diesel to allow them to maximize oil production.
These are all ingredients which point to higher oil prices at the end of this year.
Ehsan Ul-Haq
The article below appeared in the July 5, 2017 edition of Natural Gas Daily, a daily gas publication from Interfax Global Energy
Qatar’s plan to sharply increase gas liquefaction capacity at its 77-mtpa Ras Laffan facility over the next five years puts the emirate on a potential collision course with the United States, which is dramatically expanding its own LNG export capacity. Qatar’s decision also threatens to extend the current glut of LNG – which many analysts had expected to be gradually absorbed over the next five years – until at least 2025.
Global LNG prices have dropped from peaks of $21/MMBtu in 2014 to around $5/MMBtu following the wave of new liquefaction projects that have been commissioned in Australia and the startup of the Sabine Pass plant on the US Gulf Coast in 2016.
Australia was expected to overtake Qatar as the world’s largest exporter of LNG in 2018 when its new plants, construction on which got under way from 2012 onwards, are due to be completed. The Australian projects, which will boost the country’s liquefaction capacity to more than 81 mtpa, typically have breakeven prices ranging from $10-15/MMBtu and have been relying on an improvement in global prices to ensure investment returns. After a wave of startups between 2014 and 2016, this March saw the third train at Chevron’s giant Gorgon plant commissioned. The Ichthys project is due online in Q3 2017, and the Prelude FLNG project should be completed next year.
The US projects, also under construction and due for completion by 2020, include the Freeport and Corpus Christi LNG projects in Texas, Cameron LNG in Louisiana, the smaller Cove Point project in Maryland, and new trains at Cheniere Energy’s Sabine Pass. When these are completed, the US will have an LNG export capacity of 70-75 mtpa. Cheniere sells LNG from Sabine Pass on a Henry Hub-linked formula, unlike the Australian projects, gas from which is typically sold on an oil-indexed basis.
The Australian and US projects combined will add at least 135 mtpa to global liquefaction capacity compared with 2011, when Japan was forced to hike LNG imports after the Fukushima disaster led to the shutdown of the country’s nuclear fleet. The latest GIIGNL annual report estimated global liquefaction capacity stood at 340 mtpa at the end of 2016, a 22% increase on the 278 mtpa of capacity in 2011.
Qatar boost
Qatar Petroleum announced this week that it will expand production capacity at the North Dome field – the world’s largest gas reservoir, which it shares with Iran, where the structure is known as South Pars. The expansion will allow Qatar to increase its LNG production capacity to 100 mtpa from the current 77 mtpa sometime between 2022 and 2024, the company said. Qatar had imposed a moratorium on new gas developments at the North Dome field, but this was lifted in April 2017.
US LNG exports started in February 2016 under former President Barack Obama, but the administration of Donald Trump has flagged expanding LNG exports as a key pillar of its plan to dominate world energy markets. US oil, NGL and coal exports have all risen sharply since Trump took office. The new president has also launched a campaign to secure outlets for US LNG in northern Asia, and his administration has held meetings with Chinese, South Korean and Japanese officials aiming to sign up customers for US exports, including LNG.
Qatar’s decision to boost LNG export capacity coincides with a breakdown in political ties with Saudi Arabia following a visit by Trump to Riyadh in May, during which the US president alleged Qatar had promoted terrorism in the Middle East. Saudi Arabia’s arch-enemy Iran has sent food aid to Qatar following the rift.
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Category: Skills for Innovation.
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Energy is a big industry, and innovation has always been its lifeblood. But meeting the world’s soaring energy demands in the 21st century will require game-shifting innovation that can be implemented quickly and on a huge scale.
Not only the brightest brains and generous funding will be needed, but a commitment to shared goals. How can this shared commitment be achieved?
A Central Bank for Energy Innovation would bring together the vision and expertise of the best talents in industry, government and academia to implement innovative solutions in energy. This would be a permanent institution, not a cocktail party. It would be underpinned by hard cash, put to work to deliver tangible results. The board would reflect the funding provided by stakeholders, but with a one-third stake held by developing countries to ensure the interests of poorer nations are served.
Why is such a central bank needed?
Currently, the two main sources of funding for energy R&D are companies and governments. These two worlds rarely meet.
Governments typically allocate funding for research based on long-term energy policy priorities such as climate and energy security. The blue-sky thinking of the chosen academics and research institutes often never gets implemented. Meanwhile, energy companies typically entrust research to internal R&D groups tasked with finding ways to boost productivity and profitability. Such research tends to be incremental, with a high probability of being implemented, and with shorter and more clearly defined payback periods.
A Central Bank has three main functions: to control inflation, to monitor the economy, and to act as a lender of last resort.
On this analogy, the Central Bank for Innovation would have innovative ideas as its currency. Of course, this is an easy enough coinage to mint. To control the risk of hyperinflation from impractical ideas and redundant theory, the board would be entrusted to keep a tight rein on monetary policy. The bank would monitor research in energy, identify gaps and – given that speculative funding is currently anathema to banks – provide funds to high potential innovations in the energy sector.
The bank would have a small team of permanent administrative staff acting independently of the government and corporate stakeholders, reporting to a board of directors who would be rotated every three years to ensure that the innovation did not dry up and that innovative research led to results that could be implemented practically within defined timeframes.
The board would commission the individuals and institutions who would deliver the research, but only within the period of their three-year tenure. This would avoid any gravy trains where, rather like a consultant recommending that more consulting dollars need to be thrown at a problem, a research effort requires ever-increasing resources to deliver results.
Visionary thinking and practical engineering / economic skills will be needed. The Central Bank for Energy Innovation would be a vehicle to break down barriers between research communities, harnessing the brightest talents in academia and industry to work with commitment to shared goals.
The article below appeared on 28th June, 2017 in The Analyst, a weekly column by Peter Stewart in the Interfax publication Natural Gas Daily.
China will continue to prioritise LNG in its energy mix despite the prospect of substantially higher LNG prices after around 2022. The dichotomy between government targets to boost the use of gas and the dynamics of a volatile world market was discussed at an Interfax breakfast seminar in London this week.
China’s gas demand is expected to grow by 8-9% per year over the next five years, increasing its dependence on imports and forcing it to compete for LNG against Japan and South Korea, the region’s traditional heavyweight buyers of the fuel, as well as emerging buyers.
China’s gas demand growth is outpacing production, widening its supply-demand gap. The country is likely to use around 222 billion cubic metres of gas in 2017, an increase of around 8% from 2016. China’s imports of gas and LNG hit 54 mt last year, up by 22% on an annual basis, and could rise by 14% this year.
This rapid increase in demand and imports will require a correspondingly massive investment in LNG receiving capacity, despite the fact that piped supplies are cheaper. China imported more LNG than usual during the first four months of 2017 to cover a drop in piped supplies from Uzbekistan following a now-resolved commercial dispute, but its imports are typically skewed in favour of cheaper pipeline gas. Piped supplies accounted for around 52% of China’s gas imports in 2016, when the price of pipeline gas averaged $5.2/MMBtu compared with $6.6/MMBtu for LNG. Global Gas Analytics forecasts China’s regasification capacity could reach more than 100 mtpa by 2025, roughly double its capacity in 2016. With LNG imports expected to roughly double within the next 10 years, the rise in capacity will be needed.
The growth in China’s LNG demand will be particularly strong between now and 2020, with offtake expected to be supported by low prices for spot and contract cargoes.
Meanwhile, despite all the talk of a slowdown in the Chinese economy, the government will continue to prioritise policies to reduce atmospheric pollution, which will cause rapid growth in demand for gas. This will continue to be the case after 2020, when the price outlook is expected to gradually become more challenging.
The outlook for Chinese LNG imports will also be squeezed by increasing volumes of piped supplies – including via the 38 billion cubic metre per year Power of Siberia pipeline from Russia, which is expected to be commissioned by 2020 – as well as by increased volumes of cheaper domestic supplies from conventional and shale gas projects that are set to come onstream during the period. Security of supply
The need for supply security will be a significant driver of Chinese LNG demand. A delegate at the Interfax seminar on Tuesday said the country’s state-run oil and gas firms have already prioritised security of supply over price – and that their stance will not change even if gas and LNG prices rise after 2022, when many expect the glutted global gas market to rebalance.
As gas becomes a bigger part of the energy mix, Beijing has also made the development of sufficient underground gas storage a high priority, with fixed targets in its gas development plans.
These efforts face a number of challenges – gas demand growth is not uniform across the country, and implementation plans at the provincial level vary. But despite the complexity of China’s multi-layered implementation plans, huge growth is expected in the Chinese gas market. “It’s a clash of two systems,” said a delegate at the seminar. “But we shouldn’t lose sight of the huge growth [in gas demand] due to the switch from coal, and growth in the power and transport sectors.”
Oil prices remain under pressure as rising US production pushes back impact of OPEC-led cuts.
International benchmark Brent crude oil futures dropped as low as $45.4 per barrel on Tuesday – their lowest level since November 2016 – and dropped to similar levels early on Wednesday before recovering slightly. The United States benchmark West Texas Intermediate dropped to $42.8/bbl on Tuesday and was trading at around $43/bbl at the time of publication.
OPEC members and a group of 11 non-OPEC producers led by Russia agreed on 25 May to extend their 1.8 million barrels per day (MMb/d) output cut for a further nine months. The original deal was for cuts of 1.2 MMb/d by OPEC members and nearly 600,000 b/d by non-OPEC countries to be made during the first six months of 2017. This was initially extended until the end of June, but now the cuts have been extended until the end of March 2018.
The oil price weakness comes despite heightened geopolitical tensions between the US and Russia over Syria, as well as a rift between Gulf Cooperation Council (GCC) members Saudi Arabia and Qatar over the latter’s alleged support of terrorist groups. Saudi Arabia, the United Arab Emirates and Egypt have broken diplomatic ties with Qatar, claiming the country – the world’s largest LNG exporter – has supported Sunni and Shia terrorist groups in the Middle East. They also allege that it has been accommodating Iran in a way that the other GCC members deem unacceptable.
The recent weakness in oil prices stems from concerns that rising global production, led by the US, is keeping stocks stubbornly high. Oil-indexed commodities including gas and LNG have also come under pressure, along with others such as gold. The Goldman Sachs Commodities Index, which tracks the most liquid commodity futures markets, has dropped to its lowest level since 11 November 2016. Higher production from Nigeria and Libya – which were exempted from the OPEC/non-OPEC deal because of their history of disrupted production – and weaker demand growth in China have helped depress sentiment in the oil market. Gloomy outlook for 2018
The weak oil price outlook now looks set to extend into 2018 as the inventory overhang is still not being absorbed by rising demand. Earlier this month, the International Energy Agency (IEA) gave its first outlook on what it expects 2018 might have in store for oil markets. Its analysis suggests that high global oil stocks will continue despite the OPEC/non-OPEC cuts. “Our first outlook for 2018 makes sobering reading for those producers looking to restrain supply,” the IEA said. “In 2018, we expect non-OPEC production to grow by 1.5 MMb/d, which is slightly more than the expected increase in global demand.”
The IEA estimates that oil stocks have grown by 360,000 b/d so far in 2017 despite OPEC’s efforts to restrain production. The US is the main culprit, with crude production there expected to grow by around 400,000 b/d in 2017 and by nearly double that in 2018. US crude production averaged 9.3 MMb/d in the week ending 9 June, an increase of 900,000 b/d from the lows reached nearly a year earlier.
The latest analysis from Interfax Global Gas Analytics suggests that reduced disruption in global oil supplies is also taking its toll.
“The reductions in supply disruptions from Nigeria and Libya have caught the attention of market participants,” Interfax Global Gas Analytics said in its latest monthly report, published on Wednesday. The report estimates that production outages in May 2017 averaged 520,000 b/d in Libya and 360,000 b/d in Nigeria – nearly half the level of outages seen at the same time last year in both countries. The publication lowered its forecasts for Brent crude oil in 2017 as a whole and 2018 by around $2/bbl, to $52.0/bbl and $56.1/bbl respectively.
Unsurprisingly, OPEC’s own analysis is more optimistic – albeit cautiously so – on when the market will rebalance. OPEC’s latest Monthly Oil Market Report says OECD oil stocks will continue to decline in H2 2017. “The decline seen in the overhang in OECD commercial oil inventories in the first four months of the year […] is expected to continue in the second half, supported by production adjustments by OPEC and participating non-OPEC producers,” it said. “These trends along with the steady decline in oil in floating storage, indicate that the rebalancing of the market is underway, but at a slower pace, given the changes in fundamentals since December, especially the shift in US supply from an expected contraction to positive growth.”
Peter Stewart participated in the Hyper-smart Power Systems panel discussion at St Petersburg International Economic Forum. The article below appeared in the 1st June issue of Natural Gas Daily, an Interfax publication covering the global gas and energy markets. The views expressed are his own. (more…)
The article below appeared on 15th June, 2017 in The Analyst, a weekly column by Peter Stewart in the Interfax publication Natural Gas Daily.
This is not a storm in a teacup. Qatar has supported Saudi Arabia in its proxy war against Iran in Yemen and has been part of the Gulf Cooperation Council (GCC) – which also includes Bahrain, Kuwait, Oman, Saudi Arabia and the United Arab Emirates – since it was founded in 1981. But its joint ownership of the world’s largest gas field means it has closer ties with Iran than its Arab neighbours.
Saudi Arabia’s decision to up the ante in its long-simmering dispute with Qatar is a high-risk strategy. Although all sides are scrambling to defuse the crisis, there is a relatively low but nonetheless real risk that the rift with Qatar will spiral out of control. Airspace could be a trigger point. The geographical distances involved are tiny – Qatar’s capital Doha is just 100 km from the Saudi border, while Bahrain’s capital Manama is just 140 km from Doha. The UAE and Iran are separated by less than 80 km at their nearest point. Flights from Qatar have to pass over Bahrain’s airspace. Iran has responded to the crisis by sending food shipments by air and sea to Qatar and by opening its airspace to 100 new Qatari flights per day.
If the spat were to escalate, the stakes could not be higher. Qatar is the world’s biggest LNG exporter, and with Iran it straddles the largest gas field in the world. The field, known as the North Dome in Qatar and South Pars in Iran, is a single gigantic pocket of gas and condensates formed hundreds of millions of years ago in the Permian and Triassic eras. It holds an estimated 51 trillion cubic metres of gas.
Riyadh has accused Doha of backing Shia militant groups allied to Iran in Saudi Arabia and Bahrain, and it has also accused Qatar of supporting the Houthi rebels in Yemen – even though Qatar has provided support for the Saudis’ military campaign there. Impact on LNG market
The flare-up in Saudi-Qatari tensions has had an immediate impact on trade flows. LNG shipments are being rerouted because of the blockade. Interfax Global Gas Analytics has said the row will force Qatar to sell more LNG on a spot basis, while Egypt and Dubai will need to find alternative sources of the fuel. Qatari cargoes to these countries have already been diverted. Another potential destination for rerouted Qatari shipments is northwestern Europe, including the UK. Qatari LNG carriers will no longer be able to bunker at Fujairah. Oil shipments are also being affected.
In the longer run, however, a realignment of geopolitical allegiances could have important ramifications for investment. Qatar has used gas from North Dome to build an LNG export capacity of 77 mtpa and to provide power for the country’s residential and commercial sectors. It has also developed a GTL and fertiliser industry. Iran has ambitions to develop its gas resources through pipeline and LNG exports, and to expand its petrochemical industry to make use of the NGLs produced by the field. It has been stymied in the past by technological constraints as a result of sanctions by the United States and the EU.
The GCC has so far provided a united front against Iran, but it has been split into two factions for years. Saudi Arabia and Bahrain are Sunni countries with large Shia populations, while the UAE has long-standing border disputes with Iran over islands in the Gulf, meaning the three countries are united in the face of the perceived threat from Tehran. Saudi King Salman bin Abdulaziz Al Saud led a 2011 proposal for greater GCC integration intended to counter Iranian influence in the region.
The less-hawkish group includes Qatar, Kuwait and Oman. Kuwait has refused to join the blockade of Qatar and is offering to mediate in the crisis. Oman has sent food shipments to Qatar and has opened new shipping traffic between the countries. Oman is relatively non-aligned in Middle Eastern politics and has discussed building a pipeline to import Iranian gas for its LNG plants. Kuwait, meanwhile, is a key LNG importer in the region. The joint development of the Dorra field with Saudi Arabia in the Neutral Zone between the two countries was put on hold in 2013, and Kuwait’s LNG imports have subsequently soared. Iran also lays claim to Dorra.
It is unclear what diplomacy can achieve at this stage. US Secretary of State Rex Tillerson and his Russian counterpart Sergei Lavrov have called for negotiations. Turkey has warned that the crisis would have global ramifications were it to escalate and has sent its foreign minister to Doha to try to mend fences. The Turkish parliament approved sending troops to Qatar on 7 June – just two days after Saudi Arabia and its allies severed diplomatic ties.
It is difficult to predict specific outcomes and whether the rift will be permanent. A previous spat in 2014 took nine months to resolve, but history suggests that diplomacy will eventually prevail. However, the complex backdrop of Iran and Saudi Arabia’s battle for supremacy in the Middle East makes a swift and permanent resolution unlikely.
By Peter Stewart
The article below appeared on 7th June, 2017 in The Analyst, a weekly column by Peter Stewart in the Interfax publication Natural Gas Daily.
Billed as the Russian equivalent of the Davos forum, the St. Petersburg International Economic Forum (SPIEF) conference is a platform for big ideas. The integration of Asian electricity grids and the potential for Russia to become an ‘energy bridge’ between Asia and Europe were among the biggest of the big ideas discussed at the three-day event.
Proposals to build a huge electricity transmission grid in northeast Asia have been labelled as either “visionary” or “pie in the sky” in the past, depending on the viewpoint of the observer. The latest scheme – known as the Energy Super-Ring or Asian Super Grid – involves integrating the national power grids of Mongolia, Russia, China, Japan and South Korea.
Progress so far has been tentative. China’s State Grid Corp., South Korea’s state-backed power and nuclear utility Kepco, Russia’s Rosseti and Japan’s Softbank Group signed a memorandum in March 2016 on how the integration might be achieved. Although Mongolia did not sign the 2016 memorandum, the plan is to integrate the country into the system as well. Mongolia’s Energy Minister Purevjav Gankhuu, who spoke on the panel, called for “clear action” to give the project momentum, noting that a feasibility study had still not been concluded despite 12 years of discussion about this and similar schemes.
The aim of the project is to integrate the increasingly complex energy supply sources across the five countries, which have a combined land area of 2.87 billion hectares, and ensure common standards across regional and national grids to allow scope for maximum integration. The Far East is rich in hydrocarbon resources – including oil, gas and coal – but also has enormous potential for renewable energy, including hydropower, wind and solar generation. For example, Russia claims its Asian coast has 350 days of sunshine per year.
The SPIEF panel, chaired by World Energy Council (WEC) Secretary General Christophe Frei – who has led a series of discussions for WEC on its Energy Trilemma index – included Oleg Budarin, the chairman of Rosseti, which has been promoting the scheme. Budarin said it was important to ensure that technologies and standards are aligned at the start of the project, rather than trying to retrofit systems later on. “Early integration is much more efficient,” he said. From centralised to distributed systems
The enormous change under way in the power sector – from centralised to distributed systems, which will see customers will play an increasingly important role – was highlighted as a key driver of the need for systems integration. The rise of local and renewables-based generation – especially through new technologies such as blockchains, which allow electricity contracting to be done at a more local level – will require the power system to become more integrated. “Our ally is the consumer. They should vote for integration,” said Budarin.
The panellists agreed that homogenous transmission systems and convergent pricing would optimise conditions for power transmission between regions, but also outlined a number of challenges. The huge geographical area, and the uneven distribution of demand between urban and rural areas, will be a particular challenge for planners.
Meanwhile, the idea that a more interconnected system is more resilient is too simple, panellists said. For example, cyberattacks can spread more quickly if grids are interconnected. “You always have to manage complex systems in the right way,” said Frei.
Russia will play a key role in the progress towards grid integration in the region. Its policy has been increasingly directed eastwards in recent years, led mainly by demographic trends that are driving the growth in energy demand towards emerging markets in Asia.
The Power of Siberia pipeline was announced in May 2014 and is slated to export 38 billion cubic metres per year of gas from eastern Siberia to northeastern China. Several plans have been proposed to expand the flow of gas from Russia – not only from eastern Siberia but also the country’s resources in western Siberia – into China, and potentially onward into South Korea and Japan. Although these plans have been scaled back and in some cases postponed since oil prices peaked in mid-2014, the core Power of Siberia project is on track to be completed by around 2019.
Russia is also diversifying its energy policy to encourage the development of renewables and to encourage the use of ‘smart’ technologies such as smart grids and meters.
More than 120 panel discussions were held over the three days of the SPIEF, around one-third of which touched on the theme of energy and a dozen of which dealt directly with the upcoming revolution in energy systems around the world.
Should the Asian Super Grid go ahead, it would unlock huge opportunities for investment in the five main countries involved. A total of 475 investment agreements amounting to RUB 1.82 trillion ($32 billion) were concluded at the 2017 SPIEF conference, compared with 356 in 2016 and 205 in 2015. A recent Eastern Economic Forum in Vladivostok resulted in around 200 agreements worth RUB 1.70 trillion, with predominantly Chinese, Japanese and South Korean companies.
The article below appeared in the October 5th 2016 edition of Natural Gas Daily, a specialist newsletter published by Interfax, focussed on the global natural gas and LNG industry. Costs may constrain transatlantic ethane trade By Peter Stewart, Chief Energy Analyst, Interfax Global Energy
The ethane tanker INEOS Insight – blazoned with the slogan “Shale gas for manufacturing”– arrived at the Scottish port of Grangemouth last week to deliver the first cargo of shale gas to the UK. Media reports referring to the shipment as being LNG were incorrect – it was in fact carrying ethane, which is used along with propane and butane as a petrochemical feedstock.
Ethane is a type of NGL – as are propane, butane and pentane – and is primarily used in the production of ethylene. While propane and butane are sometimes used for heating, cooking, and – in some countries – as a vehicle fuel, they are mainly used by the petrochemical industry to produce ethylene and propylene to make chemicals and plastics. All three fuels compete with naphtha, a liquid petroleum product derived from crude oil or gas condensate, which has for decades been the mainstay of petrochemical manufacturing in Europe and Asia.
The gas that arrived in Grangemouth was produced at the Marcellus shale and NGL field in Pennsylvania. The liquids were then transported via a 480 km pipeline to the Marcus Hook plant, which began operations in March. Ethane is prepared there for export under a tolling arrangement, and is refrigerated and loaded under pressure onto special tankers. INEOS plans to create what it calls a ‘virtual pipeline’ of ethane across the Atlantic, and it has chartered eight Dragon-class vessels to do the job.
The growth in United States shale gas and NGL production has led to a renaissance in the country’s petrochemical industry. Dow Chemicals restarted its Hahnville ethylene cracker in Louisiana in 2012. The Energy Information Administration (EIA) forecasts that 9.25 mtpa of new ethylene cracking capacity, using ethane as feedstock, will be added by 2017 – a 27% increase from 2012 levels. In the past, the ethane market has been so small that output was simply reinjected into natural gas fields, a process known as ethane rejection.
Ethane was first exported by pipeline to Canada from North Dakota in May 2014, and US shale producers now have ambitious plans for maritime exports. Marcus Hook has a capacity of 35,000 barrels per day and sent its first shipment to Rafnes, Norway in March 2016.
The EIA forecasts that increased ethane recovery will mean its production will grow much more strongly than that of natural gas. Annual ethane production is expected to increase by 27% between 2015 and 2017, while marketed natural gas production will rise by just 3%. The EIA projects that ethane production will increase by 140,000 b/d in 2016 and by 160,000 b/d in 2017 compared with an annual average growth of 50,000 b/d between 2008 and 2015.
INEOS also plans to start importing shale-derived propane and butane next year, when the Mariner East 2 pipeline is completed. Ethane is also expected to be exported to Asia via the Panama Canal. Houston-based Enterprise Products opened a new ethane export facility at Morgan’s Point in Q3 2016 with a capacity of 240,000 b/d. The new terminal is expected to support exports to Europe and India. Reliance Industries, a Mumbai-based refiner and petrochemical producer, is building terminal and pipeline infrastructure and has ordered six large ethane carriers to transport the fuel. The first of Reliance’s ethane carriers is expected to be completed by the end of 2016.
However, several factors could stymie these ambitious plans – the first being price. INEOS has said it is using ethane mainly because it is cheap. Alternative feedstocks such as naphtha have typically been more costly, but the gap has narrowed since oil prices crashed from their 2014 highs of above $110 per barrel. Ethane is typically priced in dollars per ton on an energy-equivalent basis, using prices at Mont Belvieu in Texas as a reference.
Although domestic prices are low, ethane is more costly to transport than oil, and naphtha is plentifully available in the US and Middle East, where it is produced by refineries as well as from gas-associated condensates. If oil prices remain low, ethane exports may prove to be a costly gamble.
Plant and vessel constraints may also limit the growth of ethane shipments. Steam crackers in Europe and Asia were designed to use primarily naphtha and propane as feedstock for ethylene manufacturing. Although plants can be adapted to run ethane, their full capacities cannot be utilised. “Any shift in the global feedstock mix away from naphtha is likely to be gradual,” an Oxford Institute for Energy Studies report concluded.
Transport may also prove to be a bottleneck if export volumes increase. Ethane is transported in vessels similar to LNG carriers, but the fleet is much smaller. Around 450 LNG carriers were available worldwide at the beginning of 2016, but large ethane-capable ships are in short supply. Ethylene carriers are equipped to transport ethane, but more than two-thirds of them have a capacity of less than 10 thousand cubic metres (Mcm). Only 40-45 are larger, with capacities of 10-36 Mcm, according to www.maritimeprofessional.com. Ethylene-capable vessels have semi-pressurized containment tanks where the ethane is cooled to -100C.
(C) Natural Gas Daily, Interfax
The article below appeared in the September 14th, 2016 edition of Natural Gas Daily, a specialist newsletter published by Interfax, focussed on the global natural gas and LNG industry.
The International Energy Agency (IEA) has said that the pace of global oil demand growth is dropping more quickly than initially predicted. In its latest monthly outlook, the agency lowered its forecast for oil demand growth in 2016 by 100,000 barrels per day, to 1.3 million b/d. It forecast the growth rate would be even lower in 2017, at 1.2 million b/d.
With OPEC producers pumping at close to record-high levels, the stock overhang that has stymied oil price rallies in recent months looks set to continue. Non-OPEC production has been dropping because of low prices, but not by enough to eat into bloated inventories. The IEA estimated that oil inventories in OECD countries hit a new record high in July, of 3.1 billion barrels, a rise of 32.5 million bbl from the previous month.
Oil prices rallied from four-month lows of around $41.50/bbl in early August to a high of $51.22/bbl on 19 August as peak summer demand for oil for transport kicked in. But the rally has faltered, and Brent futures currently stand at around $47.50/bbl. The northern hemisphere summer is usually a time when more oil is consumed – especially in the United States, where motorists guzzle nearly 10% of the oil used globally.
The IEA said OPEC crude production nudged higher in August, to 33.47 million b/d. This was 930,000 b/d above levels seen earlier in the year and was led by Middle East producers pumping at full throttle. The IEA said Kuwait and the United Arab Emirates hit their highest-ever output and Iraq also increased supplies.
Saudi Arabia and Iran have each raised their output by more than 1 million b/d since late 2014, when OPEC shifted its strategy to defend its market share rather than protecting prices. Saudi output has almost reached a historic peak while Iran has also reached a post-sanctions high. As Saudi Arabia had planned, the surge in its production has stolen market share from US shale producers. However, the slowdown in US shale production has been slower than expected as a result of lower costs and higher well productivity. In its latest monthly report, which was issued on Monday, OPEC said that losses in non-OPEC supply would be less than expected in 2016, falling by 610,000 b/d rather than the 800,000 b/d decline it predicted earlier in the year. Additionally, it reported that non-OPEC production in 2017 would be 200,000 b/d higher than 2016 levels and that OPEC production of NGLs would rise by 150,000 b/d in 2017, to 6.43 million b/d. The OPEC report said third-party sources estimated its members pumped 33.24 million b/d in August, close to the recent production peaks.
The IEA’s own supply estimates are broadly similar to those of the oil cartel. The IEA expects non-OPEC supply to drop by 840,000 b/d this year, with high-cost producers hit particularly hard. However, growth will resume in 2017, with the IEA forecasting a 380,000 b/d year-on-year increase in oil production. Output gains are expected because North Sea fields that were shut for summer maintenance have now been brought back to full production, while Kazakhstan’s Kashagan field will also start producing again after extensive repairs. Eni has forecast production will recover to 360,000 b/d in 2017, above the level anticipated by the Kazakh government, the Financial Times reported.
“Supply will continue to outpace demand at least through the first half of next year,” the IEA said. “Global inventories will continue to grow […] As for the markets’ return to balance – it looks like we may have to wait a while longer.”
The article below appeared in the September 7th, 2016 edition of Natural Gas Daily, a specialist newsletter published by Interfax, focussed on the global natural gas and LNG industry. Energy storage can be used to bridge the intermittency of renewables such as wind and solar, making it a potential competitor to gas, which is typically used to meet mid- and peak-load power demand. Gas-to-power has been a growth market for LNG, particularly in countries such as the UK, where intermittent renewables form a significant part of the energy mix. The energy storage industry is in its early stages, but it is growing rapidly. Bloomberg New Energy Finance (BNEF) predicts investment in energy storage will exceed $8 billion per year by 2024, a sixfold increase from current levels. The BNEF forecasts that Japan, India, the United States, China and Europe will account for 71% of global installed energy storage in 2024. The Energy Storage Association has predicted storage on the US electrical grid will increase 10-fold by the end of the decade. Storage exists in several main forms: pumped hydroelectric storage is the most widely used technology, in which water is pumped uphill behind dams and then released, turning turbines which generate electricity. Best-known to the public, however, is large-scale chemical storage – including batteries such as the Powerwall, unveiled last year by US entrepreneur Elon Musk. The Powerwall is a rechargeable lithium-ion battery for homes, but Musk’s company Tesla has also developed the PowerPack – a 100 kWh battery that can supply electricity on the same scale as a small utility. Tesla is building what it calls a Gigafactory in a 1,300 hectare area of the Nevada desert near Reno that will provide 35 GWh of lithium-ion battery power for new electric vehicles by 2018. The $2 billion project aims to produce enough power to charge 500,000 electric cars per year. Other storage technologies involve the use of compressed air or flywheels to provide power when generation from intermittent sources drops. Thermal storage using concentrated solar power has also been developed where the climate is suitable. All these options are technically feasible, but their main drawback is that they are costly compared with conventional generation. Energy storage can be located in the generation and transmission part of the supply chain, often called ‘in front of the meter’, or at the site of final consumption – for instance at a utility customer or at a corporate site with solar panels – often called ‘behind the meter.’ Investment across the supply chain Investment in energy storage is likely to be made across the supply chain from generation to consuming sites. Generators look at energy storage primarily as a technology to balance the system, by deploying batteries rapidly when renewables generation is low. Consumers use energy storage within distributed electricity systems to ensure stable power supplies to their own sites. When combined with demand-side management systems and smart grids, which allow peak power demand to be shaved by reducing supply to those who do not need it, electricity storage could significantly alter the profile of power sector demand for conventional fuels. This could have a notable impact on the growth of gas-to-power demand, even when gas prices are favourable. Last month, a National Grid competition to provide 200 MW of power to balance the UK power network was dominated by battery projects tied to intermittent renewable sources such as wind. The Pen y Cymoedd onshore wind farm in Wales, which is due to be completed in 2017, will have a battery on site able to deliver 22 MW of power when the National Grid needs it. This may become a template for the design of new renewable generation facilities. Energy storage already has a foothold in the US, almost entirely in the form of pumped hydroelectric systems. The 21 GW of installed capacity represents just 2% of peak demand, but the rapid growth of wind and solar in states such as California is driving the need for the expansion of energy storage. The California Energy Commission estimates the amount of wind energy generated doubled between 2010 and 2015 to reach 8.2% of the state’s power mix, while solar rose from virtually zero to account for 6% of over the same period. Cost will be critical How big the industry will become depends largely on the evolution of costs. The Electric Power Research Institute (EPRI) has forecast that lithium-ion battery packs will drop to one-quarter of their current price by 2022. The EPRI has released simulation software that it says provides a solid foundation for evaluating where the use of energy storage makes sense in the national grid. The EPRI used the software to model the viability of energy storage for the California Public Utility Commission. Other studies have shown that energy storage remains significantly more costly than gas in terms of providing a backup for intermittent renewables generation. Investment bank Lazard produced a report in November 2015 that made levelised cost comparisons between lithium-ion batteries and conventional generation, specifically diesel and gas plants geared to manage peak-load demand. It found that the battery costs were in the range of $321-658/MWh compared with $165-218/MWh for gas peaker plants, and in the range of $351-838/MWh compared with $212-281/MWh for diesel in the commercial and industrial sector. The study, which provided similar cost comparisons for other battery types, found no energy storage source was currently “in the money” compared with gas and diesel. But it said combinations of storage technologies were within “striking distance” of competing with conventional fuels. If the sharp cost reductions seen in the growth of solar photovoltaic cells were replicated in energy storage, there is a real prospect these new technologies would make significant inroads into the market share of gas in the power sector.
On the 15th January 2015 Toyota presented the world’s first Mirai fuel cell vehicle to the Japanese Prime Minister, Shinzo Abe. The Prime Minister heralded the moment “the dawn of the age of hydrogen”, and, with Mirai meaning “future” in Japanese, Toyota themselves certainly believe their FCV to be ground breaking. They even predict its success being comparable to that of the Prius (Hybrid electric engine), which is now the top selling car in the US state of California.
The technology of the Mirai is the culmination of over 20 years of research and development. Toyota have succeeded in creating an engine that produces no emission other than water and unlike electric vehicles, which can only run 75 miles and then need significant recharging time, the Mirai can run 300 miles and, with the right infrastructure, can be refilled quickly.
Interest in fuel cell vehicles is spreading through the motor industry. Honda was due to begin sales of their first FCV in 2016, Hyundai have already started leasing a fuel cell version of their Tuscan SUV in California, and Ford, Daimler, Renault and Nissan are working to develop a joint fuel cell project. These high levels of investment demonstrate that the major car manufacturers recognise the potential benefits of FCVs over electric. The potential to expand the engine to power trucks and larger vehicles is another important benefit they recognise over electric vehicles.
However currently there are many obstacles to the widespread use of FCVs, the first being the cost of producing the car. In Japan currently the Mirai is being sold for £44,000 while in the US it is predicted it will be sold for around £66,000. At these prices, which include a certain amount of government subsidy, Toyota is still making a loss. However the cost would reduce should production volumes increase, currently Toyota only plan to release 700 globally.
Furthermore, a major issue to the long term success of FCVs is the cost of infrastructure development that would be needed to support the use of hydrogen cars. While Toyota predict the success of the Mirai to potentially be comparable to that of the Prius, the Prius used existing infrastructure. Predictions state that implementing the infrastructure for FCVs to be viable would cost many billions, or even trillions, of dollars. Raising the finance for this investment would be very difficult without government backing, as the chicken and egg situation surrounding hydrogen development means few will be willing to invest when there are very few FCVs on the roads. Even Toyota acknowledge that the launch of the Mirai will be in baby steps and it will take decades to embed the infrastructure required; Satoshi Osigo, the Managing Officer of Toyota, states that FCVs “are for the coming decades”.
The green credentials of FCVs are dependent on the methods of production of hydrogen. While Hydrogen is the most abundant element on earth, only tiny concentrations are found in the atmosphere. Current methods of extraction of hydrogen are expensive and inefficient, therefore the most important, and often overlooked issue holding back FCVs is finding a way to sustainably produce the hydrogen fuel they require. The most common method currently used is steam reforming of methane, which uses non-renewable resources and produces significant quantities of carbon dioxide. An alternative is the gasification of biomass where the net production of carbon dioxide is very dependent on the source of the biomass. While electrolysis of water, requires electricity, which is largely sourced from non-renewables and produces high levels of carbon dioxide. If hydrogen is produced at times of low levels of electricity demand, existing infrastructure could be used to create the electricity needed. However, while FCVs produce no carbon dioxide emissions themselves, in the current environment significant carbon dioxide will be released in producing the hydrogen fuel.
However, in natural-resource-scarce Japan politicians are pushing for a “hydrogen society”, they are looking to develop the infrastructure to allow hydrogen to power homes and offices, meaning widespread FCVs could be viable. The Japanese government is already investing billions in hydrogen development and is also offering huge financial incentives, they may even give away a few Toyota Mirai’s to get the ball rolling. The Mirai is an exciting development, and while there are many obstacles preventing FCVs from becoming widespread, it will be interesting to see how successful Japan is in leading the way.
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