London — S&P Global Platts launched a suite of UK hydrogen price assessments April 1, shedding light on three different low-carbon production pathways for the…
Apr 01, 2021
The assessments reflect the daily cost of hydrogen production via autothermal reforming of natural gas with carbon capture and sequestration, proton exchange membrane electrolysis and alkaline electrolysis.
“The UK has significant plans aimed at accelerating hydrogen production and consumption as part of its 2050 Net Zero carbon plan, and hydrogen continues to attract interest from investors, policymakers and energy market participants as a carrier for clean energy,” said Jeffrey McDonald, Hydrogen Pricing Specialist at S&P Global Platts.
Project data compiled by S&P Global Platts Analytics show plans for 26 low carbon hydrogen projects, totaling potential investment of GBP6.54 billion ($8.97 billion) over the next decade.
Low-carbon hydrogen is a key component of the government’s Ten Point Plan for a Green Industrial Revolution. The plan, announced in November 2020, outlines a range of measures to support the development and adoption of hydrogen, including a GBP240 million ($331 million) Net Zero Hydrogen Fund.
Support thus far has focused on fossil-based production with CCS, the government on March 17 announcing industrial decarbonization funding of GBP171 million for nine projects across five industrial clusters.
The projects — in Scotland, South Wales, Merseyside, Humber and Teesside — support engineering and design studies into carbon capture usage and storage and hydrogen infrastructure. These include the HyNet North West project on Merseyside, Net Zero Teesside and H2H Saltend on Humberside.
Underlining the current direction of travel, on March 18 oil major BP announced it would study installing up to 1 GW of fossil-based hydrogen capacity with CCS on Teesside by 2030.
BP said 1 GW of capacity could produce up to 260,000 metric tonnes of hydrogen a year in theory, although actual output would be lower due to maintenance and the need to build demand.
The UK has a target of 5 GW of “low carbon” hydrogen production by 2030. A detailed hydrogen strategy is due to be published in the coming weeks, although government sources were not immediately available April 1 to confirm exactly when.
Platts’ calculated hydrogen prices reflect both the commodity production cost and the capital expenditure associated with building a hydrogen facility, expressed in GBP/kilogram and GBP/kilowatt hour.
For autothermal reforming with CCS, Platts’ methodology assumes plant efficiency of 68%, a capacity factor of 95% and a CO2 capture rate of 95%.
For alkaline electrolysis the methodology assumes electrolyzer efficiency of 67% and a capacity factor of 95%.
For PEM electrolysis, electrolyzer efficiency of 58% and capacity factor of 95% are assumed.
Per kW installed capital cost assumptions in the methodology equate to around GBP646 for ATR with CCS, GBP631 for alkaline electrolysis and GBP1,003 for PEM electrolysis.
Apr 02, 2021
Mexico’s Pemex, the state oil company, is facing challenges to increase production, as the government desires, and also internationally to meet its environmental commitments.
We spoke with Andrew Rudman, director of the Wilson Center’s Mexico Institute, about these challenges and the relationship between Pemex and the United States under the Biden administration.
Apr 08, 2021
The European Parliament on March 10 backed a Carbon Border Adjustment Mechanism which would place a charge on the carbon content of emissions-intensive goods imported into the EU from 2023.
The CBAM aims to level the international playing field for European raw materials producers and is intended to replace free carbon allowances for those industries under the EU Emissions Trading System. However, industrial companies want to maintain free allowances, setting the stage for claims of “double protection” and potential legal challenges from Europe’s trading partners under the WTO.
Mar 08, 2021
Navigating a pathway to a low-carbon global economy requires a new plan. The S&P Global Platts Atlas of Energy Transition, produced in collaboration with S&P…
Feb 22, 2021
Feb 01, 2021
Platts has launched a Euro price conversion for its CEC voluntary carbon credit assessment from April 1, 2021. Platts will convert its current daily CEC…
Apr 01, 2021
Platts has launched a Euro price conversion for its CEC voluntary carbon credit assessment from April 1, 2021.
Platts will convert its current daily CEC spot assessment from $/mtCO2e to Eur/mtCO2e.
This conversion will be available in European Marketscan, US Marketscan, and Asia Pacific and Arab Gulf Marketscan, on fixed pages PGA 1414 and PGA 0483 and in the Platts pricing database under code PCECE00.
Platts launched CEC on Jan. 4, 2021 in a note available here: https://www.spglobal.com/platts/en/our-methodology/subscriber-notes/010421-platts-begins-publishing-voluntary-carbon-credit-price-assessments-jan-4
A daily commentary is available on fixed page PGA 0496.
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For written comments, please provide a clear indication if they are not intended for publication by Platts for public viewing. Platts will consider all comments received and will make those not marked as confidential available upon request. To see this note and others, please go to https://www.spglobal.com/platts/en/our-methodology/subscriber-notes
Multiple renewable records in March drove wind generation back to the top of the Southwest Power Pool fuel stack and to the highest monthly average…
Apr 12, 2021
Multiple renewable records in March drove wind generation back to the top of the Southwest Power Pool fuel stack and to the highest monthly average on record, as wholesale power prices averaged below $20/MWh on warmer weather month on month and dipped into negative territory as wind surged on the grid.
SPP power prices dropped an average of 97% month on month following record winter weather that led to record-high prices, generation shortages and rotating power outages. However, the year-on-year price change was split as South Hub prices rose but North Hub prices fell.
South Hub on-peak day-ahead locational marginal prices averaged $19.22/MWh in March, an increase of 12.3% year on year, despite falling as low as minus $2.66/MWh March 8 as wind averaged 63% of the fuel mix, according to SPP data. Real-time off-peak prices sank to minus $21.53/MWh March 8 and averaged negative prices on 11 days throughout the month.
Likewise, Texas-Oklahoma Panhandle spot gas climbed 81% year on year to average $2.288/MMBtu, according to S&P Global Platts pricing data.
Meanwhile, North Hub on-peak day-ahead LMP averaged $16.87/MWh, down 6.2% year on year, as prices reached as low as minus $6.21/MWh March 29 as wind penetration surpassed 80% for the first time in SPP history.
SPP wind penetration set a record of 81.85% at 4:33am CT March 29 and caused renewable penetration to reach a record of 84.2%, while wind generation set a peak record of 21.133 GW at 7:35am CT March 29 and caused renewable generation to reach a peak record of 22.685 GW. In addition to wind, renewables included hydro and waste.
“As wind capacity continues to grow, the number of negative hours will increase, especially during seasonally lower load, namely in the spring and fall,” said Giuliano Bordignon, S&P Global Platts gas and power analyst.
Wind-powered generation set multiple records in March and returned to the top of the fuel stack, averaging 47.7% of the total fuel mix in March, up 13% year on year and a jump of 21.2% month on month, according to SPP data.
Natural gas-fired generation fell to a four-year monthly average low of 14.5% of the total fuel mix, down 13.5 percentage points year on year and down 8 points month on month. Coal-fired generation increased 3.5 points year on year to average 27.8% of the mix, down 13 points from February.
“With coal virtually remaining a baseload technology — the share is almost flat year on year, similar to nuclear — a shrinking thermal gap due to higher wind generation affects primarily the technology at the margin, gas in this case,” Bordignon said.
Peakload slipped 19% month on month to average 29.321 GW in March, as population-weighted average temperatures across the footprint climbed 75% from February, according to CustomWeather data. Heating degree days fell 54% month on month and were 21.5% lower than normal.
Power forwards continue to trend above year-ago package levels, with North Hub on-peak April rolling off the curve at $23.40/MWh, 22.5% higher than where the 2020 package ended.
The North Hub on-peak April package averaged $23.86/MWh, 13.2% above where the year-ago package averaged, according to Platts data. Likewise, Texas-Oklahoma Panhandle April averaged $2.353/MMBtu, 85% higher than its 2020 counterpart, and rolled off the curve at $2.306/MMBtu, 115.3% higher than the 2020 contract.
The trend continued down the curve as North Hub on-peak May averaged $25.76/MWh, up 6.2% from the 2020 package average, while on-peak June averaged $29.96/MWh, a jump of 19% from the year-ago package.
The trend was even more obvious in gas contracts, with Texas-Oklahoma Panhandle May averaging $2.339/MMBtu, up 77%, as the June contract averaged $2.392/MMBtu, up 71%.
“The fact that gas is the marginal technology means that overall prices are strongly impacted by fuel prices,” Bordignon said about higher forward packages. “This means that some of this premium will translate into higher power prices, although the increase in wind capacity — and therefore output — clearly softens the upside.”
In addition, the three-month outlook indicated a greater probability for above-normal temperatures through June, according to the US National Weather Service.
Mining and trading company Glencore and China Huaneng Group have signed a Memorandum of Understanding to cooperate on carbon capture utilization and storage, starting with…
Apr 12, 2021
Mining and trading company Glencore and China Huaneng Group have signed a Memorandum of Understanding to cooperate on carbon capture utilization and storage, starting with a project at the 850-MW Millmerran coal-fired power station in Queensland, Australia, Glencore said April 12.
The companies have committed to support deployment of low carbon emission technologies like CCUS to reduce greenhouse emissions from the use of fossil fuels and other industrial processes, it said.
“This project is vitally important because it can scale up to support the reduction of Scope 3 emissions from the use of fossil fuels across a broad range of industrial sectors,” Glencore CEO Ivan Glasenberg said.
The Carbon Transport and Storage Company (CTSCo) project at Millmerran coal plant is to use China Huaneng technology to capture a stream of CO2 that would then be transported and stored in a non-potable aquifer at a depth of over 2 km. The volume of planned capture was not disclosed.
“This is the first integrated international carbon dioxide capture and storage project that China has participated in,” said Li Weidong, Chairman of China Huaneng Group Clean Energy Research Institute.
It would help build cross-industry cooperation in achieving “near zero emissions” from a coal plant, he said.
The CTSCo project is Australia’s most advanced onshore CCUS project, looking to demonstrate the technical viability of CCUS in the Surat Basin west of Brisbane, where there are a number of coal-fired power stations.
Funding and project participants include Glencore, China Huaneng, Low Emission Technology Australia, Australian National Low Emissions Coal Research and Development and the Australian government.
Energy transition is a widely used term but means different things to different people. Energy markets have always been in transition, shifting to cheaper or…
Apr 13, 2021
Energy transition is a widely used term but means different things to different people. Energy markets have always been in transition, shifting to cheaper or cleaner fuels as they become available and competitive. Invariably these transitions are journeys, taking time for new entrants to displace incumbents.
While the technology in the current energy transition is new, it will still be a process to shift from fossil fuels to cleaner alternatives. The disruption of COVID-19 complicated matters, challenging many of the assumptions around the long-term evolution of energy markets.
S&P Global Platts Analytics’ Future Energy Outlooks Annual Guidebook, issued in February, lays out the pathway of the energy transition: here are five key energy transition themes that we highlighted in the publication.
It is painfully obvious that COVID-19 has disrupted the short-term, cross-commodity outlook, particularly for fossil fuels, with a massive shock to the macroeconomic framework in addition to restrictions on mobility. Across all fuels, CO2 emissions from energy combustion declined by the greatest extent in human history, falling by 6.4% in 2020.
It has also become increasingly clear that the impacts of COVID-19 will linger into the medium to long term and be deflationary to demand on a net basis. Changes to the macroeconomic outlook will depress energy demand not only because of weaker GDP projections, but due to “economic regression”, where the global middle class—the real engine of energy demand—will stagnate or shrink.
There will also be behavioral changes in response to COVID-19, with a greater prevalence of working from home, reductions to business travel (particularly aviation), and potentially the shortening of supply chains also reducing energy demand.
Finally, there have already been a spate of policies unveiled in the aftermath of COVID-19, ranging from “green stimulus” to net zero pledges. All three of these adjustments—macroeconomics, behaviors, and policies—will significantly deflate energy demand, and by extension CO2 emissions, from the pre-pandemic outlook.
However, while the huge decline in demand and emissions in the immediate aftermath of COVID-19 has the world temporarily on or ahead of a path that would limit global heating to 2 degrees celsius, the recovery in demand, even blunted by the lingering impacts of COVID-19, will bring about a return to CO2 emissions growth over the medium term. While there is perhaps an opportunity for COVID-19 to be a catalyst if behavior and policy changes become severe, Platts Analytics does not believe this is the path energy markets are currently on.
Even before the coronavirus pandemic disrupted demand, oil consumption growth was showing signs of slowing. The lingering impacts of the pandemic have reduced growth largely in the transportation sector, across aviation, road, and marine transportation.
There are still backstops to demand, particularly if gasoline and diesel prices fall, which makes electric vehicles more expensive relative to internal combustion vehicles. But even accounting for these backstops, we project that oil demand for passenger vehicles will peak by 2030 and move into structural decline thereafter.
Outside of personal transportation, there are limited economic alternatives to oil at scale, particularly in aviation, marine bunkering, and heavy trucking. Petrochemical sector oil demand has already become one of the largest areas of growth for oil, and the increase in demand in 2020 is a testament to the diversity of products that emerge from this sector and the fact that the recovery from COVID-19 will require both durable and non-durable petrochemical products.
Underlying all these factors is that the cost of oil is, and will remain, low. Platts Analytics estimates that oil production cost breakevens are below $50/b (in real 2019 dollars) in most non-OPEC growth areas, with some breakevens in the low-$40s/b or high-$30s/b. Such low-cost supply on top of even less expensive OPEC barrels will keep oil economically competitive with alternatives, supporting demand overall.
When it comes to the energy transition, much of the focus falls on the deployment of new technologies. New electric vehicle models, wind/solar capacity additions and new hydrogen electrolyzer plants certainly grab the headlines, but turnover rate of existing infrastructure will be a critical determinant of how quickly sectors can transition to low carbon pathways.
It is a much easier and less expensive proposition to replace an older, inefficient vehicle, power plant, or boiler at the end of its useful life than it is to do so with efficient infrastructure that may have decades of useful life left and perhaps some capital left to recover.
For example, the relative old age of the coal-fired generating fleets in Europe and North America was a major factor in coal’s displacement by gas and renewables. Conversely, China has virtually no coal-fired capacity older than 40 years, with most of its fleet at less than 20 years of age.
Another example of this dynamic is in passenger vehicles. While EV penetration of new car sales continue to rise, around 95% of new cars hitting the road are still internal combustion engine models.
In industrialized nations, new vehicles last on average 10-13 years, but a significant amount of them will continue to operate for another decade or more, perhaps sold as used vehicles in developing nations. Globally, the passenger vehicle fleet doesn’t fully turn over for 30 years or more, illustrating the lag between the adoption of EVs from a sales perspective and a use perspective.
Natural gas has long held the promise of being a “bridge fuel”, essentially spanning from coal, and a lesser extent oil, to renewables. As a generally less polluting fuel than coal, with supply that has turned out to be abundant (or overabundant in some instances), natural gas has broadly been used to displace coal in industrialized nations and slow the growth of coal in developing nations.
Renewables are clearly far from just a promise anymore, and the other side of the proverbial bridge is coming into focus. The downgrade in the long-term macroeconomic outlook from COVID-19 has reduced global energy demand growth considerably, while more aggressive emissions policy pushes over the past year have caused Platts Analytics to upgrade the outlook on renewables penetration, which will further limit the upside to natural gas.
Additionally, there are longstanding structural impediments to gas demand growth that we have cautioned about for several years, not least gas pricing, particularly LNG. The global gas market is in a precarious position if it wants to continue growing strongly, as prices need to be high enough to incentivize new liquefaction but low enough to keep demand growing.
For many years, the view of hydrogen developing into a potential clean energy solution was characterized by its potential. Hydrogen has always had the potential to be used in a variety of sectors and applications without emitting CO2 at the point of consumption.
However, hydrogen had long been seen as being only that, just a potential fuel, with its hypothetical application and related reductions to oil, gas, and coal emissions still decades away.
Commitments to hydrogen have accelerated considerably over the past year, an achievement made all the more impressive for taking place during the COVID-19 pandemic.
There have been notable policy pushes such as the European Commission’s hydrogen strategy; development of regional partnerships; and deployment of hydrogen production capacity and end-use technologies.
It should not be surprising that the catalyst of the acceleration of hydrogen’s development has been more companies and governments making net zero pledges. Achieving net zero or even severe reductions in CO2 emissions without a non-intermittent energy source is next to impossible. The use of carbon-free hydrogen as an energy carrier offers pathways to decarbonization in sectors where electrification is ill-suited, such as industry, refining, chemicals, and heavy transportation.
The production of hydrogen with renewables could provide solutions to electricity intermittency and longer duration storage, and the production of hydrogen with fossil fuels and CCS offers ways to continue to use those fuels without emitting CO2.
The biggest barrier to hydrogen’s ultimate development and potential use as a major driver of emissions reductions is cost, particularly in markets that do not offer financial incentives to reduce CO2 emissions. Policymakers in Europe (and a few other countries) have signalled their willingness and ability to subsidize the deployment of hydrogen, with the aim of driving down the cost globally so that it can be more widely deployed globally. Cost declines will be key to the ultimate deployment of hydrogen and other clean energy solutions.
The seaborne metallurgical coal and coke markets entered 2021 with increased spot price volatility, following a transformative year in 2020, which saw shifts in global…
Jul 15, 2021
The seaborne metallurgical coal and coke markets entered 2021 with increased spot price volatility, following a transformative year in 2020, which saw shifts in global trade flows and historic price dislocations.
Coupled with the uncertainty of the pandemic, new trending themes like energy transition and the unofficial Chinese import ban on Australian coal, are shaping much of the conversation in coking coal markets today.
What are the key market factors that could affect seaborne prices this year? How will demand for greener steel be met? Can hydrogen and renewable power be incorporated to help the global steel sector lower its emissions profile?
Be part of the discussion and find out what’s in store for met coal in 2021 at S&P Global Platts Singapore Coking Coal Conference on July 15 in Singapore. As part of Singapore International Ferrous Week 2021, the event will set the bar as Asia’s must-attend gathering and the leading discussion point for the metallurgical coal and coke markets specialists.
1) Seaborne metallurgical coal and coke market overview – what’s next?
2) China’s role as a swing factor to price and trade flow
3) Macro outlook and supply/demand and trade flow forecast
4) Energy transition – how hydrogen can help meet demand for greener steel, and what are the challenges?
5) Key insights into latest Atlantic market trends
6) Factors to consider for effective risk management