Dubai-LOOP Sour spread shows open arbitrage east: In the LOOP

The Platts Dubai-LOOP Sour spread has widened to a little more than $3/b so far in February, suggesting an improved and opened arbitrage for US Gulf Coast medium sours grades to head to Asia.

The 10-day moving average spread between second-month Platts Dubai and front-month Platts LOOP Sour was $3.17/b Monday, with LOOP Sour the lower-valued of the two crudes. That compares with a January average spread of about $2.06/b and a Q4 2017 spread of $1.57/b.

As Dubai’s premium over WTI increases, WTI-based medium sour grades become more competitive in export markets with comparable Dubai-based Middle Eastern grades. The spread is thus indicative of the market for USGC medium sour grades in Asia.

Refinery maintenance season in the USGC has pushed down regional demand for LOOP Sour and other domestic medium sour grades. Regional sour benchmark Mars has fallen 60 cents/b since the start of February to be assessed at WTI cash minus $1.65/b on Monday.

Tanker rates for ships sailing from the USGC have moved lower during the past month, adding further competitive advantage to domestic sour grades heading east. S&P Global Platts assessed VLCC tankers sailing a Caribbean-Singapore run at lump sum $3.6 million Monday. The US Gulf Coast-Singapore run is valued at a $200,000 discount to the Caribbean-Singapore rate, several shipping sources confirmed.

Even as USGC sour crudes become more economic to sell into Asian markets, several Middle Eastern crude OSPs have been cut in a bid to maintain market share. For March-loading barrels bound for Asia, Iraq’s SOMO cut the OSP for Basrah light by 35 cents/b and the OSP for Basrah Heavy by 45 cents/b.

Iran’s NIOC cut several March OSPs for Asia-bound volumes, including that of Iranian Heavy by 25 cents/b, Forozan by 20 cents/b and Soroosh by 30 cents/b.

Kuwait’s KPC cut the price of Asia-Bound Kuwait Export Crude loading March by 25 cents/b. Saudi Aramco lowered the March OSPs for several of its grades headed to Asia, including that of Arab Heavy by 30 cents/b and Arab Medium by 25 cents/b.

The ‘In the LOOP’ Americas crude oil wrap runs each Monday in Crude Oil Marketwire, North American Crude and Products Scan and on the Platts Global Alert. You can read the FAQ: USGC LOOP Sour crude here and find the full special report LOOP Sour Crude: A benchmark for the future here. Also be sure to download our LOOP app by searching for ‘Platts LOOP’ in your app store.

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Drilling a one run lateral #Ulterra’s 8.75″ U713S drilled 6,145 ft in 223.5 hrs with an ROP of 27.5 ft/hr in Garvin Co.

Drilling a one run lateral ‘s 8.75″ U713S drilled 6,145 ft in 223.5 hrs with an ROP of 27.5 ft/hr in Garvin Co.


After a year of Trump, most energy prices now ahead of Obama’s last day: Of Presidents and Prices

It took nearly 12 months for several key commodity prices during President Donald Trump’s first year to surpass their levels on President Barack Obama’s final day in office. Commodity prices had bumped along mostly sideways until a late rally in fourth-quarter 2017.

Some are now up sharply in recent weeks, lending support to the broader economic debate around inflation. The US Federal Reserve’s mid-range inflation forecast is at 1.9% for this year and 2% for 2019; however, many material and feedstock prices are up 2%-12% compared with this time a year ago. S&P Global‘s latest US economic outlook forecasts the Consumer Price Index to rise 2.2% this year.

High wages and low unemployment are generally viewed as the key drivers of higher inflation, but the pass-through impact of basic commodity prices to consumers is also a factor. For example, increases in the prices of steel and aluminum generally get passed along to consumers in the form of higher prices for cars and appliances.

Seven of the 11 benchmark commodity prices being tracked by S&P Global Platts since Trump took office are now an average of 5% higher compared with when Obama left.

Dated Brent crude’s running average during the Trump era was $55.45/b for the January 20, 2017 – January 31, 2018, period, compared with $53.31/b on January 19 a year ago. NY fuel oil’s running average was at $48.59/b for the same period, up from the January 19, 2017, mark of $47.03/b. The biggest running average gains since the inauguration have been charted by Chicago gasoline (+11.6%), jet fuel (+7.9%) and COMEX gold (+6%).

But the running average prices of iron ore (-11.6%), thermal coal (-6.7%), natural gas (-5.6%) and steel (-0.28%) remain lower than Obama’s last day on the job.

What’s more, nine of the 11 benchmark prices being tracked continue to average price levels well below Obama’s two-term averages. US-made hot-rolled steel coil and Central Appalachian thermal coal are the two commodities averaging slightly stronger pricing after Trump’s first year in office compared with their averages over eight years of Obama.


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Enhanced oil recovery may offer climate solution: Fuel for Thought

As counterintuitive as it may sound to those who want to transition away from fossil energy to combat climate change, the US government has long supported research into technology that could potentially slow or even halt the growth of industrial carbon emissions while expanding the recovery of oil from existing fields.

Many in the oil industry support the concept—and have been implementing commercial projects based on it for decades, in the US and abroad.

In using this technology to enhance the recovery of oil (EOR), the oil industry has developed an extensive know-how for capturing, permanently storing, and monitoring carbon dioxide (CO2).

Additionally, a US government-backed research initiative has identified scores of underground receptacles nationwide that have the collective capacity for permanently storing, or sequestering massive volumes of CO2 captured from industrial sources—better known as carbon capture and storage (CCS).

The question arises anew because of shifting political winds in Washington. The administration of President Donald Trump is a strong advocate of fossil energy and wants to see more production of oil and natural gas and coal—rather than accelerating the nation’s transition away from these fuels and to renewable energy sources. Meanwhile, pressure continues to mount worldwide for the US to resume a leadership role in curbing greenhouse gas
emissions in order to tackle climate change.

In a sign of changing US priorities, a two-year federal budget approved by Congress early Friday includes an expanded tax credit for enhanced oil recovery, a measure pushed by top Permian oil producer Occidental Petroleum and governors of six oil- and gas-producing states including North Dakota and Oklahoma.

The new incentive offers credits worth $35/mt of CO2 used in EOR, up from $10/mt. The existing program had a cap of 75 million mt that was on track to max out in the first half of this year, according to ClearView Energy Partners.


EOR has proven a key arrow in the industry’s quiver of solutions for maximizing the recovery of oil resources from sub-surface rock formations by overcoming the barriers posed by the physics of fluid flow.

There are three stages of recovery: primary (natural lift, subsurface pumps), secondary (flooding the reservoir with water or repressurizing it with associated natural gas) and tertiary, aka EOR.

These stages represent levels of resource recovery ranging from 5% to 60%—which means that, in most cases, more than half the oil remains unrecovered in the reservoir.

EOR methods include the injection of chemicals, gases, or thermal energy into an oil reservoir to alter the subsurface rock physics so as to enhance the flow of oil to the wellbore.

By far the most widespread and prolific form of EOR is carbon dioxide flooding, or CO2 EOR.

The US Department of Energy’s National Energy Technology Laboratory (NETL) has estimated that the volume of residual discovered oil left behind—and thus a target for EOR—totals more than 400 billion barrels.

For perspective, BP’s Statistical Review of World Energy estimated US proved reserves of oil in 2016 totaled 48 billion barrels.

The US oil industry as of 2014 was injecting 3.5 Bcf/d of CO2 from natural and industrial sources to help produce 300,000 b/d of oil from 136 CO2 EOR projects, according to Vello Kuuskraa, president of Advanced Resources International Inc. of Arlington, Virginia. Kuuskraa then predicted that CO2 EOR oil production would increase to 638,000 b/d by 2020 with the availability of new CO2 supply sources.


What has stymied further growth in CO2 EOR is the lack of adequate, reliable supply of economic sources of the gas, according to ARI.

In a 2010 study ARI conducted for the Natural Resources Defense Council, most of the CO2 used for EOR comes from natural CO2 reservoirs,
which are limited in capacity and distant from markets other than the Permian Basin.

ARI recently noted that, even with increased access to naturally sourced CO2 by operators such as Denbury Resources, those sources remain inadequate relative to potential demand for CO2 by EOR.

“Thus, an attractive market exists for CO2 emissions captured from industrial sources and power plants for expanding domestic oil production through the application of CO2 EOR,” ARI concluded in the study.


Of course, with current CO2 EOR floods, the costly gas is recycled for multiple injection courses and can be considered permanently sequestered only after the targeted reservoir has been depleted of economically recoverable oil.

But some projects were designed for CCS as much as they were for CO2 EOR.

A prominent example is the Weyburn-Midale CO2 project in Saskatchewan, Canada, in which CO2 was injected into two adjacent oil fields for EOR, and the subsurface behavior of the CO2 was monitored from 2000–2011 by a large group of institutions led by the International Energy Agency.

The CO2 was sourced from the Great Plains Synfuels Plant at Beulah, North Dakota. The synthetic fuels plant is described by the Basin Electric Power Cooperative subsidiary that operates it as the only commercial-scale coal gasification plant in the US that manufactures natural gas and as the world’s largest CCS project.

Apart from recovering an incremental 160 million barrels of oil as a result of the CO2 EOR flood, the project is expected to permanently sequester about 40 million metric tons of CO2.


For all of its potential for sequestering CO2 industrial emissions and recovering large volumes of incremental oil, the hard truth is that CO2 EOR has a limited capacity for absorbing the mammoth volumes of North America’s total CO2 emissions, according to NETL.

However, the US DOE, Natural Resources Canada, and Mexico’s Energy Ministry issued a report in 2012 that North America has enough subsurface capacity combined in depleted oil and gas fields, uneconomic coal seams, and deep saline aquifers to store all of the continent’s CO2 emissions for 600 years.

With that potential in mind, DOE in 2003 awarded cooperative agreements to seven Regional Carbon Sequestration Partnerships, which are tasked to determine the best geologic storage approaches and apply technologies to safely and permanently store CO2 for their specific regions.

In short, there is enormous potential for CCS to help meet the challenge of climate change.

— with Meghan Gordon


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Ulterra’s Leduc Manufacturing Plant reached 1,000 days incident free on January 16, 2018. This milestone could not have been reached without our HSSE department and the compliance of the Leduc team! Read the full post here.

Ulterra’s Leduc Manufacturing Plant reached 1,000 days incident free on January 16, 2018. This milestone could not have been reached without our HSSE department and the compliance of the Leduc team! Read the full post here. 


How long can the lithium bull run last?

Lithium, one of the principal ingredients of the lithium-ion battery used for electric vehicles, has been on a bull run since 2015. Production increased substantially in 2017 with a flurry of new investors bringing capacity on stream, meaning there’s no sign of deficit, and further major mine increases are set to come in the next two to five years.

Prices still haven’t let up, remaining high after doubling in 2016, although some analysts foresee the possibility of market prices peaking this year.

Consultant Roskill puts mine production at 297,300 mt of lithium carbonate equivalent (LCE) — excluding Direct Shipping Ore of 72,900 mt LCE in 2017 — up from 209,000 mt LCE in 2016. This compares with production and consumption of some 150,000 mt LCE in 2015.

Despite last year’s increased production, prices rose substantially: battery-grade carbonate contract prices jumped 47% to $11,250/mt CIF Asia, with battery-grade hydroxide up 5% to $12,500/mt, according to the consultancy.

Market volatility means sales are made largely on bilateral deals, with prices negotiated quarterly, or using Chinese spot market prices.

And further price rises are foreseen: analysts Canaccord Genuity and SP Angel see prices for 2018 in the $14,000/mt range, while UBS has been cited by producer sources as seeing carbonate prices FOB out of South America at an average of more than $16,000/mt this year, with some indications of an easing late in the year.

“There is no alternative to lithium, we’ll see a bull run for the next ten years because car manufacturers have decided the batteries are going to be lithium,” said Gerard Reid, founder of corporate advisory and asset management company Alexa Capital, speaking at the recent Mines and Money London event.

However, a new flurry of merger and acquisition activity involving carmakers eager to lock in supplies may boost lithium production capacity quicker than expected until recently, which may end up capping prices.

An estimated 100 junior miners have already piled into the lithium space since 2015 amid the EVs hype.

Lithium is expected to move from a current situation of tight supply into surplus from 2021-22 as new mine projects currently planned or under construction come on stream, according to Catherine Girard, energy and raw materials expert leader at automaker Groupe Renault, who sees automotive battery demand taking 39% of all lithium supplies by 2025, up from 14% in 2015.

So what makes lithium so special? And why is it the darling of the investment community?

Unlike other battery metals, there is no easy substitute for lithium, considered the primary battery material as it has the highest electrochemical potential of any metal.

Research continues apace on changing chemistries to enhance cost-effectiveness: the plan is to move towards so-called 811 batteries, made from eight parts of nickel to one each of manganese and cobalt. But for now lithium remains the mainstay.

Some 80-90% of lithium production comes from four big producers, considered more chemical companies than miners: Albemarle, Sociedad Quimica y Minera de Chile (SQM), FMC and Sichuan Tianqi. In addition, output is focused on the “lithium triangle” of salt lakes of Chile, Argentina and Bolivia.

However, this is changing with the advent of more Chinese investors, junior mining companies and even mining major Rio Tinto, which has a large high-class deposit in Serbia, currently undergoing feasibility study.

Chinese, carmakers’ presence growing

Chinese investors, including carmakers, are notably expanding their presence in lithium mining, and already control some 60% of the world’s lithium chemical facilities for processing, essential for lithium’s use in lithium-ion batteries.

Chinese investment company NextView Capital has committed to pay GBP31 million ($43 million) for a 20% stake for Toronto-listed Bacanora Minerals, which guarantees it a supply of battery grade lithium metal from a major project soon to ramp up in Mexico.

Bacanora’s share price skyrocketed 91% in the year to early January. Shares for other junior lithium miners Nemaska Lithium and Galaxy Resources rose 50% and 40% respectively over the same period.

Chinese carmaker Sichuan Fulin Industrial Group has struck a memorandum of understanding to take equity and offtake in Minera Salar Blanco, part-owner of Chile’s Maricunga lithium mine project. The share price at SQM, also a target for a partial takeover, has leapt over 90% over the past year.

It’s not only Chinese companies driving M&A activity in the lithium sector. Japanese carmaker Toyota’s trading arm in January agreed to buy a 15% stake in Argentina-based lithium producer Orocobre, whose Q4 2017 sales revenues jumped more than 72% from the previous quarter.

The miner now plans to accelerate a capacity boost to triple lithium production to 42,000 mt/year by 2019, in a $271 million investment, partly financed by Japanese corporations.

According to a report last week from SP Angel, EVs producer Tesla Motors has now stepped in to eye “global lithium dominance” via investment, including in processing facilities, in SQM, which has recently resolved a long-running dispute with Chilean development agency Corfo that would allow the miner to quadruple lithium production by 2026.

SP Angel sees prices falling to $10,000/mt and $12,000/mt for carbonate and hydroxide respectively in the longer term as new production comes on stream.

Still, the market fundamentals look firm: and suggestions that this will continue to be a very attractive market for another decade are not unreasonable.

Plans for construction of new battery production capacity have led SP Angel, Roskill and BoA Merrill Lynch Global Research to see global consumption of lithium notching up annual growth of some 16% a year for the next few years, leading to a tripling or quadrupling of demand over a 10-year period, from 184,000 mt LCE in 2015, with the most bullish forecast putting this at well over 800,000 mt LCE/year in 2026.

— Diana Kinch, with the collaboration of Marcel Goldenberg

The post How long can the lithium bull run last? appeared first on The Barrel Blog.


China’s white goods sector tipped to weaken

Steel demand from the white goods sector benefited Chinese mills last year, but the effect of a weaker housing market is set to adversely impact demand this year.

China’s production of white goods – air conditioners, washing machines, freezers, refrigerators and televisions – totaled 532 million mt in 2017, up 11% year on year, according to data from the country’s National Bureau of Statistics. This growth rate was the highest since 2012.

However, several market participants surveyed by S&P Global Platts were concerned the growth rate could slow in 2018, dampening demand for hot dip galvanized and cold rolled coil.

One analyst said last year’s robust growth in white goods output could have been predicted in 2016, when property sales were robust. Property sales in China include a large portion of pre-sales by developers, and there is typically a one to two-year lag before they are delivered to buyers – so white goods demand generated by purchases always trails property sales.

In China, apartments are often not fitted out until the owners occupy the premises because developers do not want the equipment to deteriorate. Apartments can therefore be kept almost as empty shells for long periods of time.

Last year growth in property sales slipped amid tighter housing purchase restrictions nationwide. The central and provincial governments have issued a plethora of measures over the past 18 months to try and cool China’s overheating property market. These included lifting deposit ratios and imposing restrictions around purchases of second properties.

Though the sector proved resistant – house prices rose in most major Chinese cities in December, and a small apartment in Shanghai still costs at least $500,000 – the measures have impacted investment in residential properties.

Therefore, the outlook for the white goods market in 2018 is not so optimistic.

According to the NBS, China’s overall property sales in 2016 jumped 22.5% year on year, while the increase in 2017 was lower at 7.7%. The residential housing sector, the main driver of white goods demand, increased by 22.4% on year in 2016 but rose only 5.3% on year in 2017. This slowdown will likely result in subdued white goods and appliances demand this year.

“Even if housing purchase restrictions can be loosened a bit in the second half of this year, as some people are predicting, the positive effect on white goods may not occur until 2019,” a mill source said.

He said “shanty town” renovation was another major driver of demand for white goods and, compared with conventional apartments, demand was more immediate after renovation as local authorities were keen to reinstall residents. Renovation of these simple dwellings is not steel intensive, but the tenants still need fridges and air conditioners.

Data from the Ministry of Housing and Urban-Rural Development showed that about 18 million shanty town units were renovated over 2015-2017. At the start of 2017, the target for that year was 6 million new homes, receiving Yuan 224.3 billion ($36 million) in central government funding. The renovation target set for 2018-2020 by China’s State Council in May 2017 is lower at 15 million units.

Another mill source said the ratio of HDG to CRC used in the white goods sector was about five to one, so HDG would be the most affected by slower growth in the white goods market.

Mill sources noted flat steel consumption from white goods was relatively minor compared with consumption by the vehicle and machinery manufacturing sectors. They believed even if there was downward pressure on the HDG market from the white goods sector in 2018, it should be limited.

Overall, the flat steel market is expected to stay in balance and be similar to 2017, therefore limiting any opportunity for flat steel prices to rise further in 2018.

Steel consumption in the white goods, vehicle and machinery sectors totaled 10 million mt, 60 million mt and 192 million mt respectively in 2017, up 5.3%, 4.8% and 5.6% on year respectively, according to China Iron & Steel Association data published by Chinese information provider Custeel.

According to some market analysts, the white goods sector makes up around 1.5%-2% of total steel consumption in China.

CISA predicted white goods would consume about 10.5 million mt of steel in 2018, rising by a slightly slower pace of 5% on year. But China Metallurgical Industry Planning & Research Institute has forecast steel demand from white goods will increase only 2.6% on year.

The domestic price of 1.0 mm thick DX51D HDG in Shanghai fluctuated in 2017 from Yuan 4,950/mt ($789/mt) in January to Yuan 4,225/mt in May, before rising to Yuan 4,945/mt in December, S&P Global Platts data showed.

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#Ulterra is excited to attend multiple career fairs in the month of February! A few members from our team will be at the University of Colorado Boulder Technology Fair today. Make sure to stop by our booth to connect with us. @CUBoulder

is excited to attend multiple career fairs in the month of February! A few members from our team will be at the University of Colorado Boulder Technology Fair today. Make sure to stop by our booth to connect with us.


The irresistible allure of old mine shafts

UK energy start-up Gravitricity announced February 7 it had received a GBP650,000 ($903,400) grant from Innovate UK, the UK government’s innovation agency, for a plan to use old mines shafts to store energy.

The idea is relatively simple: A massive weight would be raised up the mine shaft using a winch powered by electricity at times of low power prices. The weight could then be released quickly or slowly depending on the power requirement, with the potential energy of the falling weight used to drive a generator.

The idea is a variation on two themes and another example of the seemingly irresistible attraction old mine shafts hold for energy development companies. It seems impossible not to gaze down into the darkness and think ‘how can this large hole in the ground be put to use?’

Gravitricity’s project is similar to one proposed by US company Gravity Power in 2011. That envisaged a huge piston in a mine shaft filled with water and was dubbed the Gravity Power Module. The idea was that cheap electricity was used to pump water into the shaft raising the piston, which would then be released when required, forcing the water back through a hydro turbine to generate power.

The concept fell afoul of the problem of scale. While it is possible, say in a car engine, to engineer a near-perfect piston, it is much harder to make a massive one with the same level of precision, and particularly where the piston casing is formed by the walls of an old mine shaft.

While this concept was a bit off the wall, mine shafts and hydro power hold significant attraction. A mine effectively represents the lower reservoir of a pumped hydro station with the surface the higher reservoir. The mine shaft is the race tunnel. There are plans to turn the Prosper-Haniel coal mine in North Rhine  Westphalia, Germany, into a 200-MW hydroelectric reservoir. In the UK, proposals for pumped storage have been made that would make use of old mines and slate quarries in Snowdonia.

However, Gravitricity’s concept depends on the potential energy of a weight rather than elevated water. It avoids the piston problem of the Gravity Power Module, but maybe not all problems with scale, as the weight is
envisaged at up to 2,000 tons.

In abandoning the hydro element, it is more closely related to another US project, ARES — Advanced Rail Energy Storage. That envisages using trains to store potential energy from cheap electricity. All that is required is a hill and an electrified railway; storage involves driving a train up the hill and electricity is generated from the train’s motion back down. Gravity is again the driving force.

As with all these projects, they will capture “green power,” which they may well do, but the reality is that unless they are tied to generation from a particular variable source — for example a wind farm — their storage of electricity will be somewhat more indiscriminate.

Projects using old mine shafts also inevitably claim to have regenerative powers for mining communities, but again a storage facility might generate power, but it won’t generate anything like the number of jobs that a mine would.

Gravitricity says the innovation funds will enable them to start building a scale demonstrator later this year, and find a site to install a full-scale prototype by 2020. The company plans models from 1 to 20 MW. Once they have proven the technology in old mines, the company plans to sink new shafts to store energy wherever it is required.

This is a selling point in that unlike pumped hydro, it would not be dependent on the existence of a particular topography, but sinking a new mine shaft will be significantly more expensive than rehabilitating an old one. As the technology advances, the cost of drilling will reduce significantly, the company says.

Unlike batteries, the Gravitricity system can operate for decades without any degradation or reduction in performance, according to Managing Director Charlie Blair. However, it’s a bit much to claim there would be no wear and tear on a mechanical system. The company also says its system would be more responsive than pumped hydro. Maybe so, but it would not be more responsive than a battery.

All forms of storage have their pros and cons, and Gravitricity’s might find its niche, but for the moment it looks like a much bigger challenge than the MW-scale batteries being turned out in easily-transportable transport container-sized boxes, even if they don’t last forever.

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