For all the ink spilled over climate change and the global energy transition, the world’s biggest energy companies are focusing on where it all began: American oil.
Chevron Corp’s $33bn acquisition of Anadarko Petroleum Corp, announced on Friday, will make the US company the largest producer in the dusty plains of the Permian Basin by giving it control of an oil-rich area twice the size of Los Angeles.
The deal, the industry’s biggest in four years, is fuelling speculation about what arch-rivals Exxon Mobil Corp and Royal Dutch Shell Plc will do next and which other Permian operators are in their sights. Furthermore, it cements the booming oil patch in West Texas and New Mexico as arguably the most dynamic force shaping the global energy market right now. Output there is forecast to grow by millions of barrels in years to come, meaning global producers can’t afford to ignore it.
“It’s a strong message that one of the biggest players in the Permian wants to get even bigger,” Noah Barrett, who helps manage $328bn at Janus Capital Management in Denver. “The only way to do that right now is through M&A. The M&A teams at the other integrateds are certainly sharpening their pencils.”
The Chevron-Anadarko tie-up represents a remarkable turnaround from just a year ago. Coming out the worst price collapse in a generation, oil companies were still pledging capital discipline and vowing to never repeat the overspending seen at the top of almost all previous price cycles.
The newfound humility appeared to hit the right tone, coming at the same time as the industry faced growing pressure from politicians, pressure groups and shareholders to act on climate change. Shell said this year it wants to become the world’s biggest power company. BP Plc is ramping up gas production, which its boss Bob Dudley says is key to replacing coal, a dirtier source of energy.
But after half a decade of cutbacks, and boosted by a Brent crude price that’s up 33% this year, Big Oil is gaining in confidence and looking more favourably at growth.
Exxon is ramping up spending to more than $30bn a year while BP and Total SA also have ambitious plans for new projects.
US shale is attracting more investment dollars than renewables, but so far it’s been dominated by domestic players. Chevron, a bit-part player in the Permian just a few years ago, is poised to become the basin’s top producer and acreage holder once the Anadarko deal is completed later this year.
Total barely has an onshore US presence, nor does Equinor ASA or Eni SpA. BP is the only European oil company that has spent significantly in US shale, paying $10.5bn for the onshore exploration business of BHP Billiton Ltd last year. Shell is in talks to acquire closely held Permian specialist called Endeavor Energy Resources LP, people familiar with the matter said in February.

https://www.gulf-times.com/story/628694/Chevron-mega-deal-showcases-age-of-American-energy

Vapour is released into the sky at a refinery in Wilmington, California. Legal & General Group, one of the world’s biggest investors that oversees $1.3tn, has modelled the climate crisis and sees both risk and a big opportunity, according to Bloomberg. Not only will climate action cost less than expected, but it will make emerging economies more robust. The funds manager anticipates that it can start shifting its investment portfolio now and make extra money during the next few decades – even if politicians keep failing to act on limiting an increase in global temperatures. If they finally do, profits will be even higher. “The cost of transformation will be much more manageable than many people think,” said Nick Stansbury, head of commodities research at the company’s investment management unit. Asset managers are increasingly trying to quantify the risks associated with climate change. While most still rely on external models of the future energy system to make decisions, Legal & General’s work is an indication that some are increasing their scrutiny of the issue.

Solo poco tempo fa Mike Pompeo, Segretario di Stato Usa, ha concluso il suo giro mediorientale. Un viaggio controverso, che è servito in primis a rassicurare gli alleati nella regione, nell’ottica di tirare le fila della complessa situazione nell’area.

Tra l’altro, Pompeo, è stato in Libano, paese da sempre al centro delle delicate trame politiche mediorientali. Per l’occasione Roudi Baroudi, imprenditore dell’energia libanese, personalità si spicco nel mondo degli affari del Mediterraneo, e apprezzato columnist di vari quotidiani, ha scritto una lettera aperta al Segretario di Stato. Il tema è quello cruciale nella regione. Si parla, appunto dei rapporti tra Israele e Libano sul versante dell’Energia.

«Vari giacimenti di primo piano di idrocarburi sono stati scoperti nel mar Mediterraneo orientale, questi giacimenti offrono un’opportunità storica per migliorare l’economia della zone. Sfortunatamente, il provvido sfruttamento di queste risorse viene rallentato, se non bloccato, perché pochi stati hanno definito i confini marittimi con i loro vicini. Ci sono 12 frontiere tra i sette principali stati costieri» Nota Baroudi. «Solo due di essi sono stati definiti con trattati bilaterali. In una regione che contiene oltre mille miliardi di dollari di petrolio e gas, quindi, l’83 per cento dei confini marittimi rimane irrisolto, con rischi significativi per lo sviluppo in diversi paesi».

Avverte Baroudi: «Fortunatamente le moderne tecnologie di mappatura ora consentono alle applicazioni satellitari di risolvere le controversie offshore, e di farlo con relativa facilità e precisione quasi assoluta». Secondo l’analista libanese «l’argomento più importante» della visita di Pompeo «è stato il progetto degli Stati Uniti per favorire l’accordo sui confini marittimi nel Mediterraneo orientale, in particolare quello tra la Zona Economica Esclusiva tra Libano e Israele». Il grande gioco verte su chi possa sfruttare i giacimenti offshore.

«Nonostante la difficile posizione del loro paese e del sistema di governo imperfetto, i libanesi – secondo Baroudi – esibiscono tremendi poteri di resilienza. Ma questo ciclo non può continuare indefinitamente, specialmente quando il debito nazionale equivale a oltre il 150 percento del Pil. In una recente conferenza di aiuti a Parigi, i paesi donatori hanno chiarito che i loro impegni non si concretizzeranno se e fino a quando il Libano non attuerà riforme radicali, misure anti-corruzione serie e altri passi significativi per mettere ordine dal punto di vista finanziario. Ora, proprio grazie ai nuovi giacimenti offshore potrebbe iniziare una nuova era. Se e quando inizierà la produzione, l’impatto sarà a dir poco rivoluzionario. «Il Libano diventerebbe un esportatore di energia, avrebbe i mezzi per effettuare investimenti senza precedenti in strade, scuole, ospedali. Le entrate del gas potrebbero anche sradicare la povertà e accompagnare le disuguaglianze sociali che forniscono ai gruppi terroristici campi di reclutamento così fertili».

Appunto secondo Baroudi, opinionista autorevole, il prestigio degli Usa nell’area si gioca sulla capacità di mediare tra Libano e Israele sulla questione dei giacimenti di gas offshore. Alcuni, in LIbano, sospettano che lo scopo di Washington non sia quello di facilitare un accordo equo, ma piuttosto di imporne uno sbilanciato che favorisca Israele. «Qualsiasi governo libanese che firmi un tale accordo dovrà affrontare una significativa perdita di legittimità percepita» ammonisce Baroudi. Che sottolinea, appunto, il ruolo costruttivo degli Stati Uniti. «Se l’America agisce come arbitro, un simile esercizio di fair play potrebbe dare all’intera regione la possibilità di disinnescare le tensioni e cambiare direzione D’altra parte, se gli Usa decidessero di agire principalmente come difensore israeliano, non sarà possibile per il governo libanese accettare alcuna proposta». Come si vede, anche nello scacchiere del Mediterraneo dell’Est, la prima discriminante rimane l’energia.

Dutch solar developer GroenLeven has announced that it is building a 48 megawatt (MW) floating solar PV project on an old sand extraction site in the Netherlands which, upon completion, will be one of the largest in the world, and the largest in Europe.

The new floating solar park will be built at the Zuidplas in Sellingerbeetse, in the country’s northeast, at an old sand extraction site owned by Kremer Zand en Grind, one of Europe’s leading sand and gravel extracting companies. The electricity generated from the new 48 MW floating solar project will be delivered to Kremer Zand en Grind for its local operations, and being built on an old sand extraction pond opens the door for further development of solar on sand extraction sites.

GroenLeven expects that the new project will deliver the equivalent electricity necessary for powering around 13,000 households and fulfills the company’s existing philosophy of creating solar projects that fulfill a dual function — such as installing solar on rooftops, parking places, landfills, and industrial sites.

Kremer Zand en Grind is also using this new project as a catalyst to relocate a classifying installation for sand extraction located in the Noordplas and a drying installation currently located in Emmen to an industrial park in nearby Groningen-Zuid, to better optimize the company’s electricity usage by bringing the beneficiaries of this new floating solar park closer to hand.

Additionally, Kremer Zand en Grind is also converting its drying installation from gas-fired to an electric dryer, removing a huge amount of gas from its energy mix each year. Further, by co-locating facilities the company will also reduce transport via pipeline of the sand from its extraction site, minimizing disruption to the local communities.

It is also believed that other industries in the surrounding area may benefit from the floating solar project.

The nation has plans for two ambitious renewable energy tenders but the procurement process is dragging and Lebanese institutions lack experience in designing such schemes. A solution will be provided by Europe.

Lebanon has plans for renewable energy tenders including a procurement exercise for three 100 MW solar plus storage projects, for which it has received 75 expressions of interest.

pv magazine has previously outlined the process of the tender – which is being managed by Lebanon’s Ministry of Energy and Water – which will see the Lebanese authorities review the expressions of interest before publishing a call for project proposals.

In the meantime, Lebanon’s institutions have been seeking advice on best practice regarding the proposals call, and discussed the matter at the Beirut Energy Forum in September.

The EBRD

The process has been slow and the European Bank for Reconstruction and Development (EBRD) has offered a solution.

The EBRD announced it “is intending to engage a consultant to provide support to the Lebanese authorities for the successful implementation of renewable energy auctions”.

The selected consultancy will provide technical, financial and legal assistance for the solar plus storage tender and an on-shore wind exercise. The consultant will be selected competitively and it is hoped will start a 30-month contract in June. That timeframe provides a schedule for the tendering of Lebanon’s solar plus storage projects.

Financing for the consultancy work, which it is estimated will cost around €1.75 million plus VAT, will be covered by EBRD donor funds.

Interested consultants should file their applications no later than 5pm (GMT) on Wednesday, April 24.

This article was amended on 09/04/19 to reflect the consultancy services are expected to be worth around €1.75 million, not €750,000, as previously stated.

EBRD to help Lebanon’s solar plus storage tenders

This is a bit surprising since Canada enjoys many of the same advantages that the U.S. shale revolution does (U.S. gas output has risen 55% since 2008). Among other benefits, Canada has: 1) a huge shale gas resource, 2) leading oil/gas companies and experts, and 3) free market competition that helps ensure that “the best teams win.”

Up 25% over the past decade, Canada’s proven gas reserve base now stands at a very solid 70 trillion cubic feet (Tcf). And the Montney shale play in the west could hold a staggering 450 Tcf of recoverable gas. Today, although yielding less than 20% of what the U.S. does, Canada is still the world’s 5th largest gas producer, offering 4-5% of global supply. Some 97% of all natural gas produced in Canada occurs in the western-most provinces, with Alberta alone constituting 75% of the country’s output.

With such a western-based supply system, the obvious problem is that over 70% of the population lives in the far off eastern half of the country (Calgary to Toronto is a 33 hour drive!).

Canada’s natural gas industry has quickly devolved into crisis mode. For example, soaring shale production in the U.S. has lowered the need for Canadian gas to be imported. Canada’s gas exports to the U.S., long its only customer, have steadily declined 25% since 2007 to 7.8 Bcf/d. Although this is still a pretty solid export level, expected non-stop growth in U.S. shale will continue to erode the need for Canadian gas, especially as more and more interstate pipelines are built in the U.S. to share domestic supply.

In fact, some companies such as TransCanada have been cutting pipeline tolls to try and get western Canadian gas to central and eastern provinces and better compete with imports of cheap shale flowing into the country from the U.S. While not growing, U.S. gas exports to Canada still hit a healthy 2.3 Bcf/d in 2018 – almost a quarter of Canada’s total demand.

Worse, pipelines to move gas out of distant Alberta have been extremely slow to get built, facing pushback from environmental groups and/or Indigenous peoples, regulatory burdens, costs overruns, and a number of other problems. For western Canada, too much supply, not enough demand, and worsening pipeline constraints have saddled the gas industry with “the lowest prices in the world,” even in negative territory.

As is true for oil, Canada’s gas future thus depends on reaching foreign markets by exporting off its western coast of British Columbia

If production can grow as hoped, the capacity to export will be strong. Blessed with an incredible water resource, hydro accounts for over 60% of Canada’s electricity, with gas only at 10% (gas holds a rising 35% share in the U.S.).

Democratic with a stable political system, the appetite for Canada’s gas will surely be there. The world is turning to cleaner, reliable, and more flexible natural gas to grow economies and reduce greenhouse gas emissions. Canada’s goal of course is to splash into the rapidly growing LNG pool. Although now just 12-14% of the global gas market, LNG is the fastest growing way to trade gas, rising 4-7% per year for as far out as is currently being modeled.

Two key advantages for potential Canadian LNG are low-cost domestic supply and short shipping distance to gas-hungry Asia. For example, drastically cutting transport costs, it takes just 10 days for an LNG cargo to get from British Columbia to Asia, versus as many as 30 days for projects along the U.S. Gulf Coast.

Last fall, Shell and partners green-lighted the $31 billion LNG Canada export project, the first of its kind in the country. Interestingly enough, LNG Canada made a final investment decision without first securing the usual long-term off-take contracts that have typically been used to underpin projects, instead being a joint venture with five participants and an equity financing structure. With PetroChina a partner, the U.S.-China trade row has also been bolstering hopes in Canada. And the government of British Columbia has offered a variety of incentives, such as exempting LNG Canada from carbon tax hikes if it can maintain the cleanest possible standards.

There are a variety of issues, however, that will be challenging for Canada’s LNG exports.

Let me just mention a few. As greenfield (i.e., developed from scratch), LNG export projects will be more expensive in Canada than in the U.S., where many are simply retrofitted to export. Pipeline bottlenecks and pushback will make supplying west coast terminals even more challenging. In addition, the potential Jordan Cove LNG export project in Oregon will be strong competition for Canada.

Canada’s other key natural gas problem has also been that gas is mostly a forgotten commodity as compared to oil, a higher revenue generator. Canada’s oil producers have also faced such destructive price discounts for their product that Alberta’s Premier Rachel Notley had to step in and demand nearly a 10% reduction in output to lift unsustainable prices.

We do know that Canada’s LNG projects must move more quickly to be primed to ship when a global supply deficit materializes in less than five years.

Looking forward, Canada’s National Energy Board (NEB) forecasts around a 30% increase in output to 21 Bcf/d by 2040, or what the Permian and Eagle Ford plays in Texas produce today combined. The NEB projects a 130% boom in the Montney to 12.1 Bcf/d by 2040.

I would argue that a strong LNG buildout would prove these as very conservative estimates. And an expected boom in Canada’s tar oil sands development – which uses natural gas as a key input for operations – would also help encourage more gas production in the western region.

https://www.forbes.com/sites/judeclemente/2019/04/05/canadas-natural-gas-industry-really-needs-lng/amp/?__twitter_impression=true

Almost 1,500 miles from Moscow, the tiny port of Sabetta nestles in a desolate Russian Arctic peninsula. A former outpost for Soviet geologists, it’s now the site of Russia’s most ambitious liquefied natural gas project, operated by a company that only entered the market just over a year ago.

Several times a week, a giant tanker leaves this remote place carrying the super-chilled fuel to buyers in Europe and Asia. It’s not the only LNG plant beyond the Arctic Circle, but it’s by far the largest.

Novatek PJSC, the main shareholder of the Yamal LNG plant, says plans for further projects will transform Russia into one of the biggest exporters of the fuel within a decade. Already the world’s top exporter of pipeline gas and second-biggest shipper of crude oil, exports from Sabetta are giving President Vladimir Putin’s Russia another conduit into the world economy for the country’s unrivaled energy resources.

“Russia can be in the top four main LNG exporters,” Novatek’s Chief Financial Officer Mark Gyetvay said in an interview in London.

Showcasing The Potential

Novatek has demonstrated that it’s possible to produce and liquefy the fuel in such harsh conditions at competitive prices and ship it to markets thousands of miles away in Europe and Asia. That’s helped by receding Arctic ice which is allowing a specially built fleet of strengthened tankers to ship fuel along Russia’s northern coast.

This week, Putin will tout the potential for development of Russia’s hydrocarbons at the International Arctic Forum in St. Petersburg. Russia’s leader has been a long-standing supporter of developing oil and gas resources locked under the region’s permafrost. When opening the first production train of the Yamal LNG project in late 2017, Putin said the region gives Russia the opportunity to take up the fuel’s “niche it deserves.”

“We can boldly say that in this century and the next, Russia will expand thanks to the Arctic,” he said at that time.

Novatek, whose biggest shareholders include Russian billionaires Leonid Mikhelson and Gennady Timchenko, as well as French energy giant Total SA, became Russia’s top LNG producer after starting up its plant in the Yamal peninsula almost two years ago. The facility reached its full capacity at the end of 2018, ahead of schedule, doubling Russia’s share of the global LNG market to 8 percent.

The gas producer has aggressive plans to command a 10th of the global market by 2030, Gyetvay said, and position Russia as one of the world’s largest exporters alongside the U.S., Qatar and Australia.

All three of Yamal LNG’s production units, with a combined actual capacity of 17.5 million tons a year, are now online. Novatek is attracting partners for a second plant, the so-called Arctic LNG 2 project, which is expected to come online in 2022.

The company is also considering commissioning a third facility and may increase its LNG production target for 2030 by about 20 percent, to as much as 70 million tons a year.

Novatek’s resource base at two Arctic peninsulas — Yamal and Gydan — allows the company to raise production volumes to as much as 140 million tons a year in future, according to its chief executive officer Mikhelson.

Russia, the world’s largest gas exporter, has been slow to join the global LNG boom as it has focused investment on pipeline supplies to Europe. Until recently, the country had just one liquefaction project in operation, the Gazprom PJSC-led Sakhalin 2 project near Japan with an annual capacity of about 10 million tons.

The country has now taken an interest in the market for tanker-borne fuel amid growing global LNG demand and more difficult relations with its customers in the European Union.

Vast Reserves

Russia’s Energy Ministry pegs total gas in place within the region at about 210 trillion cubic meters, or over 70 percent of the nation’s total. Novatek’s Arctic gas reserves are “conservatively” estimated at about 3.3 trillion cubic meters, Gyetvay said.

“We believe that Russia could be the fourth or even the third” biggest holder of LNG production capacity, said Karen Kostanian, Moscow-based oil and gas analyst for Bank of America Merrill Lynch.

The resources are located more than 5,000 kilometers (about 3,100 miles) away from key markets in Asia and are almost 4,000 kilometers from the European trading hub at the port of Rotterdam. That requires extensive shipping capability.

The freezing environment also means Novatek has to produce natural gas at temperatures as low as minus 56 degrees Celsius (about minus 69 Fahrenheit), according to regional government data. This requires special techniques for construction in permafrost areas, including installing pylons in ice, and for ships to navigate frozen routes.

Furthermore, not only does Novatek manage in the harsh environment but it sees the Arctic’s location as a competitive advantage, Gyetvay said, because the lower temperatures actually make production costs cheaper because less energy is needed to chill the gas.

The cost of producing Yamal feedstock gas is only around $0.1 per million British thermal unit, whereas U.S. producers typically buy their gas on a market such as the Henry Hub, where prices are currently about $2.60.

Eyes On The Prize

After starting up its $27 billion Yamal LNG project, Novatek is finalizing the partnership structure for the planned Arctic LNG 2 project.

Novatek’s potential has attracted investment from global players from Total to China National Petroleum Corp., a rare bright spot for Russia’s energy segment hit by U.S. and European sanctions. While Novatek is on the American sanctions list, and the U.S. Congress is considering restricting investment in Russia’s LNG facilities outside the country, it won’t impact the start-up of Arctic LNG 2 or the company’s longer-term expansion plans.

Total, a shareholder in Novatek’s first LNG project, last month signed a deal to buy a 10 percent stake in the second plant. The French major’s commitment could prompt a rush of other potential partners to take stakes in the project, Gyetvay said.

Whether other companies buy stakes in Arctic LNG 2 or not, Novatek will move forward with it regardless. The company is already doing pre-marketing for the future cargoes, discussing potential off-takers and volumes, Gyetvay said.

Last week, Novatek signed 15-year agreements with Vitol SA and Repsol SA to supply each with 1 million tons of LNG a year from the Arctic LNG 2 and other projects.

“We’re basically at that point in time when the train has started to move and it’s time to jump on or miss it,” Gyetvay said.

 With assistance by Adrian Leung, Tsuyoshi Inajima, and Rob Verdonck

(Updates with production estimates by Novatek CEO in paragraph 12.)

https://www.bloomberg.com/amp/news/articles/2019-04-07/russia-eyes-greater-energy-dominance-as-novatek-taps-arctic-lng?__twitter_impression=true

TOKYO/SINGAPORE (Reuters) – Japan’s Tokyo Gas said on Friday it has signed a deal with Royal Dutch Shell for the long-term supply of liquefied natural gas (LNG), partly using a coal-linked pricing formula in an unusual move for an Asian LNG buyer.

This is believed to be the first time a Japanese buyer is using a coal-based pricing index in an LNG contract, industry observers said.

The companies signed a heads of agreement for Tokyo Gas to buy 500,000 tonnes a year of LNG for 10 years from April 2020.

Japan’s second-biggest LNG buyer is stepping up its efforts to diversify its supply sources and reduce costs.

“As far as Tokyo Gas and Shell know, this is the first time a pricing formula linked with a coal index has been used with LNG contracts,” a Tokyo Gas spokesman said.

A pricing formula based on coal indexation will be used for part of the supply, the spokesman said, while the rest will be priced off conventional gas- and oil-linked indexes. Tokyo Gas did not give the volumes to be done under each pricing method.

“With our long-term relationship and joint consideration, we were able to achieve an innovative agreement that would enhance further diversification of price indexation pursued by Tokyo Gas,” Tokyo Gas Managing Executive Officer Kentaro Kimoto said in a statement.

In Asia, most long-term LNG contracts are linked to oil prices, while supply from the United States is typically priced off the Henry Hub Index for natural gas.

Earlier this week, however, two U.S.-based firms announced alternative pricing options for contracts being signed for their new projects, ahead of an expected flood of supplies hitting global markets this year.

The deal follows a series of innovations in LNG contracts announced at the LNG2019 conference in Shanghai, said Nicholas Browne, a Wood Mackenzie analyst.

“Coal remains the largest competitor to gas in the power sector in Asia. If the index is competitive, this could be an important step for enabling LNG and utilities to better compete with coal,” Browne said.

As a gas and electricity provider trying to build its share in a competitive and liberalized power market, Tokyo Gas needs to compete with cheaper baseload coal-fired power, he said.

Tokyo Gas together with Japan’s Idemitsu Kosan and Kyushu Electric Power said in January they had given up their plan to build a 2 gigawatt (GW) coal-fired power station in Chiba, citing economic reasons.

“This deal may help them compete with cheaper coal based generation even though they don’t have much coal generation,” Browne said.

Shell will be supplying LNG to Tokyo Gas from its global LNG portfolio, rather than from specific LNG projects.

SINGAPORE (Reuters) – China’s natural gas demand is set to grow by 14 percent in 2019 amid a huge government push to spur consumption of the fuel, a senior industry executive said, requiring the nation to import huge amounts of liquefied natural gas (LNG).

Yet even China’s booming consumption may not soak up a large glut of LNG that has emerged across Asia and dragged spot prices for the fuel down by 60 percent over the past half-year.

China’s gas demand will expand by 30 billion to 40 billion cubic meters (bcm) this year, said Li Yalan, chairwoman of Beijing Gas Group, main supplier to the Chinese capital, in an interview on Friday.

That would be an increase of as much as 14 percent from the 280 bcm of gas China consumed in 2018, according to data from the state economic planner, the National Development and Reform Commission (NDRC). It would also be slower than China’s 2018 demand surge of 18 percent.

The rising gas demand is a result of China’s ongoing policy to move households and industry from coal to gas, as well as economic stimulus that includes a value-added tax cut from April 1 and which is aimed at supporting industry growth.

Li said Beijing, one of the world’s biggest gas-burning cities, consumed a record 18.5 bcm of gas last year, up 14 percent from 2017.

“The broad direction is not going to change, which is to restructure the energy mix by increasing the share of natural gas,” Li told Reuters.

“What China needs to do is to connect the gas supplies with the demand nicely to ensure a smooth switch.”

Better state planning to ensure grid connections and to encourage energy companies to boost imports in advance helped China’s gas market, the world’s third-largest, to expand by a record 43 bcm last year, Li said.

The expansion came after a supply crunch over an unusually cold winter of 2017/18 as suppliers struggled to meet a demand surge that followed a policy to move millions of households to gas from coal.

“This year we’ll likely see the market growing between 30 and 40 bcm, which is a normal range,” said Li.

Although China’s domestic gas production is also rising fast, its 2018 growth of 7.5 percent cannot fully keep up with the nation’s expanding consumption.

CAN CHINA SOAK UP ASIA’S GLUT?

With new gas piped from Russia due only toward end-2019, China is expected to ramp up imports of LNG, said Li.

China, the world’s second-largest LNG buyer behind Japan, boosted imports 41 percent in 2018 to 54 million tonnes. That followed growth of almost 50 percent in 2017.

But the booming consumption in China is the lone bright spot. Asia is in the midst of a large supply glut that has dragged down spot prices for LNG by 60 percent since mid-2018, to below $5 per million British thermal units (mmBtu).

(Graphic: Asia LNG supply vs GDP growth – tmsnrt.rs/2WT6FxI)

This could mean gas producers are in for a stretch of low Asian prices as demand growth, especially outside China, falls behind a supply surge amid an economic slowdown, resilient coal consumption in many emerging markets, and also the rise of renewables.

While demand growth outpaced supply between 2016 and 2019, new production – mostly from the United States, Australia and Russia – is expected to exceed consumption increases this year by more than 2 percent, according to industry data.

Dan Yurman looks at plans for Small and Micro Nuclear Reactors. A UK report on Micros that generate 30MW says it’s an opportunity for the country to own the IP and export units that are simple in design, factory constructed and capable of being sited in remote locations. Given the rough ride nuclear can get, the report warns that progress will depend on political, regulatory and financial support. Meanwhile, in the US, Westinghouse will have a 25MWe unit ready to test by 2022. And while the world waits for such Micros, China will begin construction at the end of this year of a 125MW Small Modular Reactor, expected to be operational in 2025.

Westinghouse launches new SMR effort

After several earlier false starts, including a complete withdrawal in 2014 from efforts to enter the SMR market, Westinghouse buoyed with a $12.9 million grant from the U.S.Department of Energy, is making another go of it. The firm said it will spend $28.9 million to demonstrate the readiness of the technology of its 25-MWe eVinci micro-reactor by 2022.

The government money, which is covering about half of the costs, will cover costs used toward design, analysis, licensing to manufacture, siting, and testing work.

The monolith will serve as the second fission product barrier (the fuel pellet is the first barrier) as well as the thermal medium between the fuel channels and heat pipes. The heat pipes will extract heat from the core using a technology based on thermal conductivity and fluid phase transition.

Key technical attributes

On its website Westinghouse said the reactor’s small size and innovative design set it apart. (Technical Profile – PDF file) Here’s a short list of key technical details.

• Transportable as a reliable energy generator
• Fully factory built, fueled and assembled
• Output of 25 MWe electrical
• Up to 600ºC process heat for petro chemical and other industrial uses
• 5- to 10-year life with walkaway inherent safety
• Target less than 30 days for onsite installation
• Autonomous load management capability
• Proliferation resistance through encapsulation of fuel
• Minimal moving parts

Next generation nuclear: 25MW, smaller, safer, can be sited anywhere