BARCELONA -- Considering the expected growth in US LNG exports over the next several years, it is natural to focus on the developers, construction contractors, regulators and contract pricing mechanisms that enable the resources to flow.
But, what happens at the next step in the LNG value chain when cargoes get where they are going?
At Enagas’ regasification terminal at the Port of Barcelona, which received a shipment from Cheniere Energy’s Sabine Pass export terminal in Louisiana in August aboard the GasLog Salem tanker, the LNG is distributed to customers in Spain and throughout Europe via a variety of means.
The most common is for the LNG to be converted back into pipeline-ready gas and then delivered to the local grid that serves Barcelona and grids that serve the rest of Spain.
During a tour Thursday following the conclusion of the weeklong Gastech conference, the terminal operation manager, Ramses Ninou, explained how the LNG, at a temperature of -160 degrees Celsius, is fed through compressors and filtered into big vats of seawater that are warmed to 40-50 C. Thirteen kilos of seawater is needed for each kilo of LNG.
The process returns the liquid gas to its dry gas state, and the water is returned to the sea only about 5-6 degrees warmer than when it was extracted, officials say.
At this time of year, the facility’s sendout rate to the grids is about 600,000 cubic meters of gas per hour. The gas is used to fuel power plants, heat homes, produce electricity and serve industrial facilities. The Barcelona terminal’s maximum sendout rate is 2 million cu m of gas per hour, but the highest rate it has reached was 1,650,000 cu m per hour during one recent high-demand winter.
The terminal also distributes small loads of LNG by truck to customers in Spain and several other countries. An average of 25 trucks are loaded each day, bound for countries including Italy, France and the UK.
The trucks that go to Italy can be lifted onto vessels for the journey across the Mediterranean Sea. The trucks can even reach Macedonia a few thousand kilometers away, as the insulated hull is able to secure the LNG for up to 50 days without any material boil-off.
If LNG is delivered by truck, it would be regasified at its ultimate destination.
For customers that don’t need the LNG or converted dry gas right away, the terminal can park the LNG in its six storage tanks for later use.
Enagas receives six-seven LNG tankers a month with an average capacity of 150,000 cubic meters. It also can handle the supersized Q-Flex tankers. The biggest exporters to the facility include Australia, Qatar, Nigeria, the US and Norway, officials say.
Because some of the exporters liquefy heavier types of LNG than others, the facility’s storage tanks are loaded from the top and bottom, and the density inside the tanks is constantly monitored.
So, how about those medium-size loads of gas that an industrial customer outside of Spain might need — ones that are perhaps not as feasible for a pipeline, too big for a truck and too small for a vessel?
Germany’s VTG AG, a wagon hire and rail car company, has designed what it describes as a “movable pipeline,” a large rail car capable of delivering mid-size loads of LNG from Enagas’ import terminal in Barcelona to the rest of Europe.
The rub? Big money is needed to extend the rail tracks from where a prototype now sits adjacent to the Enagas facility. Other infrastructure also is needed to make the LNG-by-rail proposal a reality, says Heinz-Jurgen Hiller, an international manager for the company.
Hiller says his company is talking to some interested parties who may be willing to finance some of the needed infrastructure. His pitch: VTG would lease the LNG rail cars, with a cost to the shipper that is meaningfully cheaper than taking the same-size load on several trucks.
LNG-by-rail isn’t the only thing Enagas is experimenting with along with its vendors at the Barcelona terminal.
It is trying to sell some of the freezing cold air that comes off the LNG as it is filtered through its facility. A rectangular walk-in freezer sits at the site — the effect inside was created with LNG that was received at the terminal.
Officials say industrial clients who operate refrigerated warehouses might be interested in such a product.
The growing number of regasification facilities popping up all over Europe and planned for the years ahead are part of the reason US exporters are so bullish about future demand for their liquefaction.
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The circular economy concept is simple in its proposition: Create a regenerative system in which the use and waste of resources are minimized by re-using and re-manufacturing materials prior to recycling.
Less simple is its implementation, which requires the global economy to redesign its processes and detach itself from the old linear model of take-make-dispose.
These were the topics surrounding a conference organized by the World Steel Association (worldsteel) in Brussels with a spotlight on steel, circular and clean material by nature.
S&P Global Platts discussed these topics with Dr. Edwin Basson, Director General at worldsteel.
Basson’s experience in the steel sector started in 1994, when he joined Iscor Ltd. in South Africa as Chief Economist, leading strategic initiatives for the company in later years. He became General Manager for Marketing Strategy in 2004, after which ArcelorMittal acquired Iscor. From 2006, he acted as Vice President, Commercial Co-ordination, Marketing and Trade Policy at ArcelorMittal. Basson has been part of worldsteel since 2011 as Director General.
1. In the circular economy we are trying to produce sustainable materials that pollute less, how does steel compare with competing materials (i.e. aluminum)?
I am going to expand your question to include other competitive materials. Steel is a useful product in such a large spectrum of applications, and we find specific competitive materials by sectors. For example in construction a competitive material is not aluminum but things like concrete or timber and they raise different questions in terms of re-manufacturing or recycling.
Looking at sector specific solutions, in the case of aluminum the key benefit was its light weight. [But] in the automotive sector, the benefit of having a lightweight material in terms of CO2 emissions cannot be recovered in the distance the vehicle travels. Steel has never found that aluminum has been a threat, maybe in some other markets, [but] steel sells five times as much as aluminum in the automotive industry. There is growing concern with automation, electrification and car-sharing, and the material question is becoming less of an issue. Automakers want to focus on properties of the materials, so steel remains a competitive product. It will be competitive product in the future. When we start looking at the re-use and re-manufacturing concept, steel has an intrinsic strength. It is a very clean product, not an alloy and you can re-use it in different applications. We are positive about it. The actual question will be how we are going to change the design of the vehicle in the automotive sector.
Do you see a time frame in which this is going to happen?
Redesigning and reimagining the vehicle has been taking place in the last 5-6 years. We have also seen circular economy concepts like car-sharing happening now. The redesign of vehicles has happened already [in areas such as] easy access, control and self-driving cars.
The question is how soon this will take place on a larger scale. And in this context there are two key questions: What will be the future for electric vehicles? And the role of automation? Both questions have been researched and evaluated. The answers will find their ways [into] new designs in the automotive sector of the future. Let us talk about safety, where the passenger sits and how much she or he weighs, how the vehicle is going to be used? long or short distance transportation? There are no clear answers for now. They will become clear but I am very sure that steel will play a role in all of this. Modern steels are formable and light enough to be able to provide with the answers.
It is not impossible to imagine automated vehicles to drive on predesigned routes. We heard in the presentations the unproductivity of the average EU car is 92% as the car is parked. We can get rid of the driver, then at least you can partly increase the productivity of the vehicle. We will see!
2. Renewable ways of extending the life of materials is one of the objectives of CE, but now we are operating in a difficult political environment and it is hard to focus on circular economy with section 232, safeguards etc. How is this impacting CE?
Just a brief clarification to qualify the answer I will be giving you. For antitrust reasons I cannot get into specifications of trade issues.
Yes, 232 trade restrictions in all steel products are an inconvenience and change, in a small way, the direction of trade and might change the value of the trades. But historically a product like steel, because it is so usable across so many areas, it is ingrained in the production structures that already exist.
How much steel has been traded across continental borders and goes on open waters? Even in previous restrictive times in the late 70s early 80s, as much of 30% , one out of three tons of steel, goes on open waters. That has grown in open times, has gone up to 40%. So, I am quite confident in saying that despite trade restrictions, trade in steel is going to continue at an average of 30% on a long-term average figure.
The second thing we might see is a reaction not only to the restrictions [to trade] but to the changes that we already see at political and societal levels. We might see the re-emergence of regional economic blocks as an important part of the global mix.
Steel is a very large group of products with a total of 1,600 million tons per year, and it is used globally within different applications, so it is going to remain a very important part of trade on a global or on a regional level. We do not know the final picture but steel will be in it. I am definitely not concerned about the restriction impact on steel.
Some regions might decide not to embrace circular economy, others will. So, we have slightly more regional fragmentation, with differences of speed and efficiency of those who implement changes.
However, I believe that forces of international competitiveness are strong and vibrant and will eventually force a search for common and equal regulation in the world. Secondly, issues such as cost of energy and quality of labor will play a role in economic vibrancy of regions. So, I would say that yes there might be drives towards regional differences but just as many forces will drive to equal common standards for trading.
3. China Blue Sky initiative: Is China going to reach the goal by 2020 and is it achievable and sustainable?
I believe China will make a success out of it and if we look at the history of implementation of very large impact policies on the environment, they all have been so far successful. If we look at history, China is not unique. The UK after its industrial phase had similar environment conditions in the 40s and 50s and they have implemented changes alongside the rest of EU and today we are living in a much cleaner environment. This is why the EU is such an architect of environmentally sensible policies. I remember in my life time in San Francisco they changed environmental policies with the same aim. Other countries have done the same thing with the focus of getting a more sustainable environment for their people. China is efficiently implementing them as well. We have seen the impact of the policies already. China wanted to reduce 150 million mt of steel over a five-year period. We are now in the third year and they have reduced steel making capacity by 150 million mt.
Informally they have also reduced something like 60 million mt of induction furnace capacity. If you look at the latest policy announced in June, a continuation of the one leading to 2020, it implies a focus on the use of coal, steel production and aluminum to improve the air not only in three main cities but in 82 municipalities including tier 1 and 2 cities. This is a substantial impact in environmental terms in the next three years. They will continue the rationalization of production capacity for steel, aluminum and coal use.
We should watch these developments because, as a result of China’s size in global steel and aluminum trades, these changes in China have a strong potential to spill over into other Southeast Asia regions and also into other parts of the world. It is too early to say what will happen but I am sure China will succeed in its aim to have cleaner air.
Read Jamila’s related blog post: Steel aims to boost its potential in the circular economy
The post Steel and the circular economy: Interview with Dr Edwin Basson, worldsteel Director General appeared first on The Barrel Blog.
Thank you to our great sponsors who are supporting IPAAs Education Foundations 6th Annual Wildcatters' Sporting Clays Tournament in Dallas TX this Thursday Sept. 20. #STEM #clays #oilandgaspic.twitter.com/Dfs0x29Ihm
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In June 2017, Mexico’s Energy Regulatory Commission (CRE) announced the elimination of the maximum price of natural gas, known as the first-hand price, or the VPM. Instead of using this price cap formula, the state-owned oil and natural gas company, Petroleos Mexicanos (Pemex), alongside independent market participants, would determine prices based on market conditions.
More than a year later, how does the Mexican market look from a pricing perspective?
In place of the VPM, CRE took steps towards engineering pricing transparency in the gas market through the publication of the National Reference Index of Wholesale Natural Gas Prices (IPGN), starting in July 2017, making price reporting mandatory for the first time in the Mexican market.
Moving to a more granular level, in February, CRE broadened its pricing coverage to six different regional indexes, which represent a volume-weighted average price of all trades reported by marketers during the prior month with respect to volume, average price billed and service costs.
However, regional pricing formation has not occurred solely from a federal standpoint.
Pemex prices are now no longer based on just two markets, Reynosa in the North and Ciudad Pemex in the South, but are determined by market activity in nine different regions of the country, while continuing to utilize S&P Global Platts’ published Henry Hub and Houston Ship Channel indexes as their reference prices.
While pricing transparency has accelerated in the Mexican gas market, obstacles remain.
According to a majority of market participants, CRE’s regional prices, while providing an additional pricing point, have limited use due to the opaqueness of the data included, lax reporting rules as to the types of transactions to report, as well as a several month lag.
Pemex, on the other hand, appears to be conducting business as usual, utilizing an updated version of the pre-reform VPM as well as publishing daily natural gas prices. However, the formula and methodology are now regularly being reviewed and amended by CRE— Pemex’s own system of checks and balances.
In addition, adders for LNG cargoes distort prices in parts of the country that do not maintain direct access to either Manzanillo or Altamira, two of Mexico’s most utilized regasification facilities.
More broadly, when comparing Pemex pricing and CRE pricing in a particular region, such as northeastern Mexico, the two values diverge starkly due to fully loaded costs and various adders being included in the CRE prices, whereas Pemex’s pricing shows strictly the value of the gas.
Fundamentally, the prices are apples and oranges.
Looking ahead, as proposed by CRE, the regulator’s monthly, and eventual daily, indexes, are not a permanent feature of its role in the gas market, with price reporting agencies, such as Platts, expected to take the reins and develop pricing for the burgeoning market.
Since May 2017, Platts has published 15 locations on a net forward model, utilizing final daily settlement prices in the South Texas and Southwest markets as the index, and tacking on transport costs to various points within the country.
As the Mexican market develops, so must modeled pricing, to reflect changes in infrastructure developments, like flows from West Texas to Topolobampo on the western coast of Mexico, as well as shifts in the supply-demand balance, resulting in a dramatic revamping of daily Platts Mexican pricing.
The new prices have sought to pivot away from a heavy reliance on border crossing points, and move deeper into Mexico to capture isolated markets like Merida in the Peninsular region, as well as future interconnection points at Tuxpan, where the 2.6 Bcf/d Sur de Texas-Tuxpan pipeline will end. The project is expected to be in service before the end of 2018.
Currently, these prices are featured weekly on S&P Global Platts Analytics’ Spotlight, but will soon reside in a dedicated Mexican gas product titled “Gas Daily Mexico”, which is scheduled to launch in the fall.
So far, the progress in price transparency to the Mexican energy sector is substantial, but Mexico still has a long way to go in establishing both full transparency and garnering market confidence, as it is an integral part of achieving the full aims of the 2013 Energy Reform and to attracting international investors.
The post More than a year later, how has Mexican natural gas pricing evolved? appeared first on The Barrel Blog.
Recent expressions of support by the US and UK governments have highlighted a new class of very small nuclear power reactors.
Microreactors, sometimes defined as reactors of less than 15 MW, have been identified as potential recipients of development funds by the UK government as part of its search for an “advanced modular reactor” for near-term deployment, while the US Congress passed legislation in July asking the Department of Energy to develop a report on the potential deployment of such units at military or energy facilities.
Small modular reactors have received attention in recent years as a potential solution for the problems of small grids and remote locations while benefiting from faster factory-like manufacturing. Advocates for microreactors say their diminutive size allows for an expanded range of siting options and functions.
Critics wonder, however, whether the tiny reactors have much of a market outside a few remote Arctic communities, as well as highly specialized defense and resource extraction facilities.
Some established and newcomer reactor vendors have developed such designs, initially in secret, and report growing interest for the product category. Westinghouse is looking to build a demonstration unit of its eVinci reactor, while US start-up Oklo has engaged for more than a year with NRC on fuel and licensing plans for its design. The UK’s U-Battery is developing a microreactor design, as are other global companies.
The units could be small enough to fit inside a standard 40-foot shipping container, vendors have said.
“In terms of their role in the nuclear industry, they would be broadening the range of applications for which nuclear technology can be applied,” said Jonathan Cobb, a senior analyst with the World Nuclear Association. “Some microreactors also have the ability to load-follow, which could have applications in balancing supply,” he noted in an email.
Art Wharton, vice president of market development for Studsvik Scandpower, said there are “potentially attractive economics” for locating microreactors in isolated communities, noting remote communities in Alaska and Canada are paying $1 per kilowatt-hour for electricity produced by diesel generators. By comparison, he said, customers in US and Canadian cities and towns, where electricity is produced by large coal, gas or nuclear plants, pay 6–9 cents per kWh.
Another consideration that favors microreactors in such locations, Wharton said in an interview, “is their ability to operate off the grid in these areas, where building transmission lines” to connect to a regional grid would be prohibitively expensive.
Everett Redmond, the Nuclear Energy Institute’s senior technical advisor for new reactors and advanced technology, said that a key attribute of microreactors is their “ability to offer resilience and reliability.”
“In remote locations, the bottom line is that if the electricity goes out they are in serious trouble and in a life-threatening situation,” Redmond said.
Microreactors could be useful for a variety of industrial applications, he said, and could be downsized to the point they become portable – enabling them to displace diesel generators that are brought to industrial or work sites for specific periods of time.
Studsvik’s Wharton said that the heat, rather than electricity, generated by microreactors could be a cost-effective product of the units. The reactors would substitute for other generating sources, such as natural gas, to produce heat for chemical processes, the extraction of oil from tar sands, and sea water desalination or district heating in towns and cities. Such reactors could be the primary source of electricity generation in small African towns, he said.
However, Stephen Thomas, an energy professor at the University of Greenwich in London, is skeptical about the need for new nuclear construction, said in an email that “after 40 years of observing the nuclear industry, my gut-feel is this is just the latest nuclear technology rabbit out of a hat that will lead nowhere but might attract a little public funding and will give hope to nuclear enthusiasts that the industry has a future.”
Some microreactors could be unstaffed, with operators monitoring them remotely, vendors have said. The WNA’s Cobb said the use of microreactors in certain settings would “require a different regulatory regime to that to which the current large nuclear reactors are subject.”
The NEI’s Redmond said he “does not see barriers” at NRC for staff to review microreactor design approval applications, noting the agency “is doing a lot of work to educate staff on various advanced technologies, such as high-temperature gas-cooled, molten salt and liquid metal” reactor design concepts.
Some advanced reactor developers believe the standards for microreactors may be more comparable to those for nuclear materials licensees, which use radioactive sources for industrial and medical purposes.
William Reckley, a senior project manager in NRC’s Office of New Reactors, said during a meeting to discuss advanced reactor licensing July 26 that the agency is considering whether additional regulatory options are needed for microreactors. Even the new framework being considered by NRC to streamline the licensing of advanced reactors and small modular reactors – those under 300 MW of capacity – still might not be suitable for the unique features of microreactors.
“We’re looking to say, do you reach a point where it is so fundamentally different — and I’ll get in trouble for this — but at some point does a reactor even though it’s commercial power, look more like a radiographer than a Vogtle? Obviously that’s an exaggeration,” Reckley said.
The expansion of Georgia Power’s Vogtle plant in the US features two 1,150-MW AP1000 units.
“At some point, is it so fundamentally different that we need to totally change how we’re viewing it in terms of how it should be regulated based on the potential consequences and risks associated with the machine?” he asked.
Fuel, enrichment issues
To achieve efficient, cost-effective generation, Studsvik’s Wharton said microreactors would use high-assay, low-enriched uranium, meaning levels from 5% U-235 enrichment to just below 20%. Almost all existing power reactors use fuel enriched to below 5% U-235.
However, he said a common element shared by microreactors is “they have smaller thermal loads and less decay heat that needs to be dealt with.”
Wharton said he could not estimate the cost to license and build a microreactor, noting the first prototype unit could be built by the late 2020s at a US national laboratory site.
Technological and cost-efficiency improvements “will be made by engineers in the next few decades,” he said. “Twenty years from now,” Wharton said, it is likely “we’ll see some of these [microreactors] available for substantially lower costs,” although he could not estimate a dollar amount.
Edwin Lyman, senior scientist, global security, with the Union of Concerned Scientists, was more skeptical about the economic viability, security and demand for microreactors. Noting that the idea of installing small-size nuclear reactors on military bases has been “discussed and dismissed” for many years, Lyman said microreactor developers “are going after the same remote communities in the Arctic and how big a market is this, realistically?”
“We’ll see a dozen companies all chasing after a tiny market segment with a product that is looking for a use,” he said.
Although he could not estimate any electricity production cost for microreactors, Lyman said, “the one thing you can say [about] the economics is that the smaller the plant, the more expensive the cost of electricity will be,” because of economies of scale. “That’s why reactors, which started off small, have consistently become larger,” he added.
Lyman took issue with comments by microreactor proponents such as Wharton, who said “the concept is that you can push the on-button and walk away for 10 to 12 years before having to refuel” the reactor.
“If something goes wrong,” Lyman said, “you will have to have a team of nuclear engineers on site to fix the problem.” In addition, he said “novel reactor designs will raise safety concerns,” especially since these systems will use high-assay LEU.
Procuring this material likely will be a problem, he said. There is no commercial supply of high-assay LEU, Lyman said, noting that “DOE has about 1.5 tons” of the material that it makes available each year “for research reactors around the world.”
He noted that Urenco’s New Mexico uranium enrichment facility could make high-assay LEU, but “it would need a license amendment to do this, requiring much research.” Existing centrifuges would have to be reconfigured, he said. “On a commercial basis, [no enricher] would do this unless it knows the demand will be there, but demand is greatly uncertain, and so you have a chicken-and-egg situation.”
Nonetheless, Oklo, Urenco and Westinghouse are pressing ahead with their microreactor designs. Other companies working on microreactors include Ultra Safe Nuclear Corp., LeadCold Nuclear and StarCore Nuclear. All have engaged with the Canadian Nuclear Safety Commission about reviewing their designs.
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Unusual strengthening in the US Aframax tanker market has compelled more crude oil shippers to use larger Suezmax vessels in recent weeks, according to shipping sources.
There have been at least nine vessels placed on subjects on the voyage charter market over the past two weeks making the trans-Atlantic voyage from the USGC to Europe, six Suezmaxes and four Aframaxes, according to S&P Global Platts data.
Aframaxes are typically used to carry crude across the Atlantic to Europe; however, recent strength in the smaller ship class has prompted charterers to take Suezmaxes vessels on the journey, sources close to the shipping markets have said.
Platts assessed the cost of carrying 70,000 mt of crude on a Aframax vessel from the US Gulf Coast to the UK Continent at $17.03/mt Monday. Freight for Suezmax voyages carrying 145,000 from the USGC to the UKC last traded at Worldscale 65, when Oxy placed the Front Crystal on subjects loading at Corpus Christi. Applying a flat freight of $15.48/mt, as is the base for Platts Aframax assessments on that route, w65 on that route is the equivalent of $10.06/mt. Aframaxes have held a $6.97/mt premium over Suezmaxes for the journey; however, the smaller vessel commanded a $9.76-premium on September 5.
This trend could reverse as recent bullishness in the Suezmax segment could prompt charterers to move back to Aframax vessels to make trans-Atlantic runs, a shipbroker said.
One North Sea crude trader said that US light sweet crude, specifically WTI in Houston, continues to be an appealing option for buyers in Europe.
“WTI MEH has been working better into Europe,” the trader said.
The Suezmax tanker Cape Brindiski is set to be loaded with US crude this week and then will sail for Trieste, Italy, according to a S&P Global Platts shipping report. The Cape Brindiski was at the Energy Transfer Partner docks in Nederland, Texas on Monday, according cFlow, Platts trade flow software. Vitol is listed as that shipment’s charterer.
US crude exports saw a sharp increase during the week ending September 7. The Energy Information Administration reported last week that some 1.83 million b/d of US crude was exported, which was an week-on-week increase of 320,000 b/d.
A widening Brent-WTI swaps spread has allowed for more US crude to be exported. The 30-day rolling average spread between the front-month Brent-WTI swaps is $7.66/b. Last week the spread was as wide at $9.56/b. It settled Friday at $8.89/b.
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On my train journey from London to Brussels for the World Steel Association Circular Economy Conference, out of the window I watched the landscape change from the English to the French and finally to the Belgian. Jarring with the natural beauty of all three countries was one shared element — the rusty, abandoned steel rails at the side of the gleaming tracks.
Why not ensure a second life for this material? But what are we talking about precisely?
The Circular Economy Conference aimed to address questions about how materials are used and how the planet’s health might be improved by changing business models. In a world where economic growth has been driven by uncontrolled use of resources we have now reached a point where it is crucial to stop and assess how we innovate.
“We are in the 21st century, we don’t have the luxury to think short term,” Co-Chair UN International Resource Panel Janez Potocnik said at the event.
Several speakers addressed the finite raw materials issue from different angles, suggesting new ways of implementing change while uprooting the old linear economy based on a take-make-dispose model. Europe is still majorly dependent on imported raw materials for up to 90% of its industrial production according to 2014 European Commission data. The circular economy model instead focuses on reducing raw resource extraction, re-using available materials, re-manufacturing and recycling, preventing waste and pollution by extending the lifespan of metals, alloys and polymers.
Under the spotlight, steel is deemed to be among the materials that can most effectively lend themselves to use in a circular economy.
“Steel is circular and permanent,” General Director of European Steel Association Eurofer Axel Eggert said.
The numbers speak louder than words: steel production makes full use (up to 97.6%) of the raw materials extracted for its production (i.e. metallurgical coal, iron ore etc.) converting the rest into by-products used in various industries, from cosmetic to fertilizers, according to worldsteel data. On the other hand, today 78% of used steel ends up being recycled instead of being re-purposed, and 40% of this is waste produced by the construction industry alone, according to Arup, a London-based multinational construction and design consultancy. Hence the need for closing the steel lifespan cycle, optimizing steel products by changing their design so that right from their inception they can be made ready to be repurposed and re-absorbed in the value chain.
The greatest challenge is to persuade manufacturers to adopt the circular business model. This would entail collecting their used products, disassembling their components and reutilizing the materials for a new item. Technical and operational hurdles would however arise for the reverse logistics necessary to allow steel to be correctly handled and disassembled from the original product, protected and identified with the final aim of re-utilizing it before it goes to waste or to scrap.
“Recycling in itself is a rather demanding process and we don’t have to necessarily go there — the issue is that so much has been done at the legislative level to promote recycling while there is a long way to go to encourage businesses to embrace remanufacturing,” worldsteel Director General Edwin Basson said.
Following on from this new approach, the collective effort needs to be supported by “new policies that need to be implemented across all levels of businesses,” Eurofer’s Eggert said.
And with these new challenges in mind, I boarded on my train back to London in the expectation that soon enough those discarded steel rails would have their own return ticket.
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Thank you to our great sponsors who are supporting IPAAs Education Foundations 6th Annual Wildcatter's Sporting Clays Tournament in Dallas TX this Saturday Sept. 22. #STEM #sportingclays #oilandgaspic.twitter.com/xIzJMBMvoF
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Economic warnings around a no-deal Brexit have reached fever pitch proportions. If Bank of England governor Mark Carney’s latest Doomsday portent comes to fruition, house prices will collapse and the streets will be choked by dole queues if the UK unceremoniously crashes out of the European Union. Certainly, the energy industry will also be affected; just don’t expect the petrol pumps to run dry, or the lights to go out on March 29 next year.
Based on the evidence at hand, the nation’s vital oil, gas and electricity industries can continue to prosper even in the hardest of hard Brexit scenarios. Firstly, losing jurisdiction over Britain’s oil reserves in the North Sea is theoretically bad for Europe because it pushes up the bloc’s dependence on imported crude from outside the region. The UK and non-EU member Norway currently account for 84% of all European production, according to the BP Statistical Review of energy.
Neither should a weak pound seriously threaten a strategically important industry, which uses the US dollar as its global currency de jure. Labor costs – among the offshore sector’s biggest overheads in the North Sea – should be kept in check by sterling’s depreciation against the greenback.
In terms of licensing and operating regulations on the North Sea, even the most brutal outcome to Britain’s protracted talks with Brussels would have little impact, say experts. “In the event of a ‘no deal’ outcome, the licensing and environmental regime relevant to upstream industry in the UK will remain broadly the same and that no action needs to be taken by UK or EU companies,” said Julia Derrick, oil and gas partner at law firm Ashurst.
However, the UK’s oil and gas producers remain mostly pessimistic about the prospect of leaving the EU. Their concerns are largely centered on higher operating costs and extra red tape. Shell – the largest oil major listed in London – warned this week about the added hassle of Brexit but this hardly constitutes a major problem for the company, or its shareholders.
“There’s no existential threat around Brexit,” said Shell’s country head Sinead Lynch. “There is however aggregation of additional costs, administration, complexity, which is completely the wrong direction when you think about what we are trying to do in the industry.”
Anyway, Lynch’s concerns hardly amount to a catastrophe for an industry which frequently has to adapt to the volatility of fickle oil markets. Nevertheless, industry group Oil & Gas UK has also warned a no-deal and reversion to World Trade Organization rules could add £500 million in trading costs. But for a sector expected to generate $920 billion of revenue through to 2035 these additional costs look irrelevant.
The group, which represents an industry employing over 280,000 workers, went on to argue that additional costs “such as those envisioned in a possible ‘hard Brexit’ scenario would be potentially detrimental to the ongoing international competitiveness of the UK continental shelf.” However, its own research suggests the North Sea has become one of the most efficient major oil producing basins in the world in terms of efficiency by reducing operating expenditures by around 43% over the last three years.
Net imports of crude, natural gas liquids and feedstocks totaled just 0.9 million metric tonnes in the first quarter of this year, one of the lowest levels since 2004, according to the Department for Business, Energy and Industrial Strategy. If this recovery keeps going then the UK in theory could eventually become a net exporter again, albeit briefly.
Oil storage is one area where, it can be said with certainty, will be affected by a juddering hard Brexit. This week the government advised Brexit could change the terms under which companies are obliged to hold stockpiles of crude so the UK can still meet its international obligations to maintain a strategic reserves. Cutting through the jargon, a no-deal Brexit may result in the UK requiring companies hold approximately 35 million barrels in storage under International Energy Agency rules, instead of around 76 million barrels under EU edicts.
In other corners of the UK energy industry the evidence to support negative consequences of a no-deal Brexit is thin. Although Britain imported 4.8 billion cubic meters of the fuel from continental Europe through underwater pipelines in 2017, those flows won’t be endangered by EU negotiator Michel Barnier holding the public’s feet to the fire. Power supply is also secure, with more underwater cables to transmit power across borders planned regardless.
Britain imports less than 10 percent of its annual demand from Europe, but also has the capacity to send electricity in the opposite direction. Over the last year demand averaged 33.8 GW, of which imports met less than 3 gigawatts of demand. The UK has 4 gigawatts of subsea cables installed and a further 4.4 GW are being built to France, Belgium and Norway.
Even the most hardline Brexiteers cannot in all honesty expect the UK to leave Europe without suffering some economic consequences, at least in the near term. After all, it is entirely reasonable to prepare for the worst-case scenario when dealing with something that has never happened before. The energy industry – still Britain’s economic lifeblood – should be ready for all eventualities on March 29 but meeting demand for oil, gas and power should remain its most important priority regardless.
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In Asia Pacific thermal coal circles it is known as the “great decoupling” and refers to the yawning gap between spot traded prices for Newcastle 6,000 NAR thermal coal and another grade of Newcastle thermal coal, 5,500 kcal/kg NAR.
That gap has blown out to an unprecedented $50/mt, from only $10/mt in early February, and the phenomenon has not gone unnoticed in wider business circles.
A September 12 report in the London Financial Times headlined “Why Asia needs a new thermal coal price benchmark” discusses this dramatic price gap and speculates that it might imperil existing benchmark indices for the 6,000 kcal/kg NAR grade.
Proponents of high prices for Newcastle 6,000 kcal/kg NAR coal insist supply of this specification remains tight due to underinvestment in Australia’s coal sector and recent industry consolidation. Others are unconvinced, pointing to the small number of spot trades for this grade at irregular intervals, and clustered around the time of Japanese contract price talks.
The price gap could be squeezed sooner than many expect, as Japan quietly moves to restart a number of its stalled nuclear power generators left idle since the Fukushima accident in 2011.
Newcastle 6,000 kcal/kg NAR benchmark prices also appear to have decoupled from market prices for other grades of thermal coal, including Platt’s NEAT coal index for Japan, South Korea and Taiwan, and which some would argue is a contender for Asia’s new price benchmark for thermal coal.
For NEAT, an index that tracks the price of cargoes delivered to Japan on a 5,750 kcal/kg NAR CV basis, the price differential to Newcastle 6,000 kcal/kg NAR prices is currently $30/mt, after hitting a high of $37/mt in August.
The NEAT price index is based on traded prices for the liquid Newcastle 5,500 kcal/kg NAR market, which is generally shipped to China, though cargoes have traveled to India, Turkey and Mediterranean Europe, plus indicated freight for Panamax ships on the Newcastle to Kinuura, Japan trading route.
The lift-off in Newcastle 6,000 kcal/kg NAR prices started in early May, around the time that annual price negotiations for deliveries of Australian shipments to Japanese power plants over the 2018-2019 Japanese financial year became intractable.
Instead of being wrapped up quickly in convivial meetings over tea in Tokyo, this year’s talks foundered amid a soured atmosphere as price negotiators for the largest buyer and seller of Australian thermal coal in the Japanese market were unable to agree a price for their April-year term contracts.
Eventually, the April talks were abandoned, and a benchmark deal was salvaged when two other Japanese power companies and their large Australian supplier agreed a price of $110/mt for shipments of Newcastle 6,322 kcal/kg GAR — equivalent to 6,000 kcal/kg NAR thermal coal — for the Japan’s fiscal year 2018-19.
The price differential between Newcastle 6,000 kcal/kg NAR prices and NEAT and Newcastle 5,500 kcal/kg NAR continued to expand through June to August as Chinese demand for high-ash Australian thermal coal slumped on import controls, and its price hit close to $60/mt FOB Newcastle.
How much longer prices for Newcastle 6,000 kcal/kg NAR thermal coal — the grade used mostly by Japanese power generators — can remain out of kilter with wider Asian market prices will have to be seen.
It is a multi-million dollar question, to which only the market can provide an answer. But, when it happens, the price correction could deliver a heavy blow to those with bullish market positions for Newcastle 6,000 kcal/kg NAR thermal coal.
The post Out-of-kilter Newcastle 6,000 NAR thermal coal prices put future of Asian benchmark in question appeared first on The Barrel Blog.