US Bakken crude latest to suffer from takeaway constraints: Fuel for Thought produced in North Dakota’s Williston Basin is the latest North American crude grade to experience plummeting values because of what many in the industry say is rising output and tightening pipeline takeaway capacity combined with regional refinery maintenance.

Bakken crude values began experiencing a rather sharp decline at the start of October when a combination of factors began to weigh on values.

Midcontinent crude traders have spoken about Bakken differentials being pressured by pipeline-constrained Canadian grades, as well as ongoing refinery maintenance in the Midwest.

More than 800,000 b/d of Midwestern refining capacity was offline in October, but planned work started to wrap up at the end of the month.

But one of the region’s largest refineries — BP in Whiting, Indiana — extended its maintenance to mid- to late November. There also were reported issues at Phillips 66 at the Wood River refinery in Roxana, Illinois, recently after the coker and crude sections were shut.

Bakken grades have dropped sharply since the beginning of October when a combination of factors began to weigh on values.

Bakken Williston discount to WTI grows on takeaway concernsPrices for Bakken at terminals near the oil producing Williston Basin decreased nearly 70% from September to October, according to S&P Global Platts data. Average price differentials in the Williston Basin fell from a $2.75/b discount to the NYMEX light sweet crude calendar-month average in September to a WTI CMA minus $8.45/b in October. So far in November, Bakken Williston has averaged about WTI CMA minus $17/b.

Bakken in the Clearbrook, Minnesota, hub has followed a similar trajectory.


In addition to seasonal maintenance, rising output is filling available pipeline space out of the Williston Basin, and that is leading to some in the industry to search for trucks and rail cars to move the crude to desirable markets. But trucks and trains also are in short supply, traders have said, as much of that rail capacity has been “re-positioned” because of new pipelines.

Sending Bakken crude to the Gulf Coast by rail has become a desirable option for some traders, if they can manage to secure railcars. The spread between Bakken in the Williston Basin and in Nederland or Beaumont, Texas has grown to around $26/b.

Bakken oil producers are close to maxing out available pipeline space and rail out of North Dakota, even though on paper the basin roughly has 300,000 b/d of spare takeaway capacity, the state’s pipeline regulator said in an interview last week.

Justin Kringstad, the director of the North Dakota Pipeline Authority, said the Basin has 1.37 million b/d in pipeline capacity, with another 250,000-275,000 b/d of crude leaving by rail. It’s unclear if more railcars are available in the region, but sources have said they have had a hard time securing railspace.

North Dakota recently reached a record 1.29 million b/d in oil production and that is expected to rise. Kringstad said that despite new wellsite requirements for natural gas capture, he expects Williston Basin output to reach 1.34 million sometime next year.

While there seems to be enough pipeline takeaway capacity on paper, in reality it’s a slightly different story, Kringstad said. Several lines are idled or running at very low volumes because it is undesirable to ship on them, such as Enbridge’s BEP line from North Dakota to Cromer, Manitoba, in Canada.

Other options also are not ideal for many, Kringstad said.

The Enbridge mainline that takes crude from North Dakota to Clearbrook, Minnesota, also is not shippers’ top choice because differentials in Clearbrook are hurting due to downward pressure from depressed Canadian grades, and refinery maintenance.

“[DAPL] is the obvious choice,” Kringstad said. “Those routes that get you to Clearbrook are the last resort.” Kringstad said that DAPL is by far the top choice for many shippers to move Bakken crude to the Gulf Coast, where differentials, refinery demand, and the opportunity to export is much stronger.


Extremely depressed values for North American crude near production fields have been a familiar trend this year, with output outpacing pipeline takeaway options as the main reason behind those low differentials.

Prices for WTI Midland crude reached record-low levels of WTI cash minus $17.50/b in August, when production in the Permian Basin continued to outpace available pipeline space. WTI Midland has found some support after it was announced a pipeline expansion project would start up by the end of the year.

But major relief for takeaway issues will not be available until new pipelines are completed next year.

A lack of pipeline takeaway capacity out of Canada, combined with refinery maintenance in the US Midwest, has widened Canadian crude price discounts and has pushed some producers to cut output. The dynamic has depressed values for both Canadian heavy and light grades, which compete with Bakken crude and often initiate price movements.

Syncrude Sweet Premium, the light benchmark, was last assessed at a discount of $32/b to the WTI CMA, the weakest differential on record. Mixed Sweet and condensate differentials at Edmonton also fell to record lows Thursday.

On the heavy side, S&P Global Platts assessed Western Canadian Select crude at an average $27.78/b discount to WTI CMA during Q3, out from an $18.15/b average in Q2. The discount has since widened to average $45.84/b so far in Q4.

S&P Global Platts Analytics expects total Canadian production losses to be limited to roughly 100,000-200,000 b/d by the middle of 2019.

The post US Bakken crude latest to suffer from takeaway constraints: Fuel for Thought appeared first on The Barrel Blog.



Insight from Washington: US energy conservation gets lost in the drive for oil abundance

US energy abundance underpinned the Trump administration’s case for rolling back federal vehicle fuel economy standards, a policy the government aims to adopt by March.

The US is producing enough oil “to satisfy nearly all of its energy needs and is projected to continue to do so,” the administration argued in the proposal that would freeze fuel efficiency for cars and light trucks at the 2020 target of 43.7 miles per gallon. Booming domestic output has “added new stable supply to the global oil market and reduced the urgency of the US to conserve energy,” it said.

However, this newly abundant supply has not shielded US drivers from global price risks, as recent volatility has shown. And the US has not become less exposed to global market forces as it pumps more crude and exports it around the world.

“The idea that the imperative on conservation is gone because you have abundance is just exceedingly short-sighted and not strategic,” said Sarah Ladislaw, director of the Center for Strategic & International Studies’ energy and national security program.

“That’s where people really take issue with an articulation of that position, because it seems to fundamentally misunderstand the history of oil markets,” she said. “You can have all the supply that you want, but if it can’t get to where it’s going, your reliance on it is still a strategic vulnerability.”

US oil import dependence has fallen sharply from a peak of 60% in 2005 to 21% in 2017, according to the Energy Information Administration. The EIA projects it will average 17.5% for 2018 and keep falling steadily until 2029, when total crude and refined product exports will overtake imports for the first time.

This figure – which EIA calls the net import share of product supplied – reflects the dramatic shift toward US energy abundance that the Trump administration rightly praises. The fact that this figure is on a clear path toward zero does not mean the US is “producing enough oil to satisfy nearly all of its energy needs.”

The US still imports about 7.9 million b/d of crude and 2.2 million b/d of refined products. Those volumes are projected to fall, while US exports of crude and products keep rising.

Even when the US becomes a net oil exporter, US producers will still rely on export markets to find the best home for their particular crude, while US refiners will rely on imports for feedstock. Gulf Coast refineries were built to process heavy crudes from Saudi Arabia and Venezuela. Some of this capacity will be reconfigured to take advantage of the light sweet crude streaming out of West Texas, but not enough to say the US can become self-sufficient when it comes to producing and refining all the oil it consumes.

“The idea that the amount that you’re producing equals self-sufficiency is wrong,” Ladislaw said. “If you look at what’s happening in the US oil market, we’re getting more deeply integrated into global oil markets because we’re trading and we need to trade to make sure we can optimize our own energy system from the upstream all the way to a downstream perspective.”

Congress created the first US fuel economy standards in 1975 to protect against price shocks and supply shortages like those seen during the 1973 oil embargo. The first rule aimed to double the average fuel economy of the new car fleet to 27.5 mpg by model year 1985. Fast forward to the Obama administration adopting standards for 2012−25 model years to get the fleet-wide average to an equivalent of 54.5 mpg, which would have been 49.6 mpg in actual efficiency gains plus offsets.

The Trump administration said the US no longer needed such ambitious targets because of rising domestic oil production and the US consuming a smaller share of global supply. In addition, a greater diversity of both suppliers and consumers in the oil market since the 1970s had made it less likely a single actor or group like OPEC could harm consumers. “The global oil market can, to a large extent, compensate for any producer that chooses not to sell to a given buyer by shifting other supply toward that buyer,” the administration said in the August proposal.

Despite this line of reasoning by his administration, President Donald Trump has spent much of 2018 blaming OPEC for high US gasoline prices. “The OPEC monopoly must get prices down now!” he said September 20 in one of half a dozen tweets devoted to high gasoline prices and OPEC.

Easing the vehicle efficiency standards is expected to increase US oil demand by 500,000 b/d. The proposal says the economic impact of this extra 2−3% of oil demand is dwarfed by cost savings for auto buyers.

The proposal acknowledges that rising US production and falling import dependence cannot entirely insulate consumers from the effects of price shocks. “But it appears that domestic supply may dampen the magnitude, frequency, and duration of price shocks,” it said. “As global per-barrel oil prices rise, US production is now much better able to (and does) ramp up in response, pulling those prices back down. Corresponding per-gallon gas prices may not fall overnight, but it is foreseeable that they could moderate over time, and likely respond faster than prior to the shale revolution.”

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On behalf of Ulterra, we remember the fallen #RemembranceDay #CanadaRemembers @ Canada …

On behalf of Ulterra, we remember the fallen @ Canada …


Ulterra’s Engineering Teams were put to the test during this derrick building challenge, successfully creating 9 unique rig designs that were able to withstand heavy hookloads! Next time,… …

Ulterra’s Engineering Teams were put to the test during this derrick building challenge, successfully creating 9 unique rig designs that were able to withstand heavy hookloads! Next time,… …


Charting relative cost of thermal coal vs LNG in Northeast Asia reveals fresh insights

For power plant operators in Northeast Asia striving to optimize their operational efficiency, the prices of imported gas and thermal coal are clearly key considerations.

But a direct comparison between the two fuel sources for power generation is not an easy one to make, given they are traded in different units of energy content.

Thermal coal is traded on the basis of its calorific value or heating content on a kilocalories per kilogram basis, and its volume priced in US dollars per metric ton.

LNG is priced on the basis of US dollars per million British thermal units, or $/MMBtu.

The most common way to compare like with like is to convert seaborne thermal coal prices into the same unit of measurement as LNG, in this case $/MMBtu.

S&P Global Platts publishes a daily price assessment for LNG shipped to Japan, South Korea and Taiwan on a delivered ex-ship basis — its JKM Marker.

Platts also publishes a daily price assessment for Australian thermal coal shipped to Japan’s Kinuura port — the Northeast Asia Thermal Coal index, abbreviated to NEAT.

The NEAT index is for 5,750 kcal/kg NAR thermal coal shipped from Australia’s Newcastle port to Japan and includes indicative freight for Panamax vessels on this trading route.

NEAT has accumulated almost two years of price history since its launch in early January 2017, which is enough to glean some interesting trends and information.

Plotting the NEAT price index against the JKM Marker on a graph in $/MMBtu reveals some thought-provoking details that are not immediately apparent when looking at their price histories separately.

JKM (LNG) vs NEAT (coal) Weekly Average Price Comparison

On a delivered-Japan $/MMBtu price basis, seaborne-traded thermal coal has been significantly and consistently lower in price than LNG cargoes over the past two years.

Secondly, thermal coal on a $/MMBtu price basis has mostly traded in a range of $3.50-$4.50/MMBtu over the past two years, while LNG prices have fluctuated in a wider and higher range of $5.50-$11.50/MMBtu over the same period, with significant seasonal peaks and troughs.

Thirdly, the difference between prices for thermal coal and LNG cargoes on a delivered Japan basis has varied from $1.80/MMBtu to $8/MMBtu since January 2017.

JKM (LNG) vs NEAT (coal) Weekly Average Price Comparison

Electricity generation companies can use Platts’ prices for thermal coal and LNG delivered to the Northeast Asian market, and China, in various ways.

They can assess the relative merits of each fuel within their individual business plans, make informed decisions about when to buy thermal coal or LNG at different seasonal times, plan ahead for their fuel needs, and plant operators with the capability can switch between the LNG and thermal coal.

Thermal coal is mostly used in baseload power generation, to supply a stable flow of electricity to the grid, while LNG generation can be used for times when electricity demand peaks.

China has been importing more LNG, and last winter ramped up its intake to satisfy domestic heating demand during periods of extreme cold weather.

At the same time, China is reliant on billions of tons of thermal coal, both domestic and export volumes, to sustain its industrial base and vast city infrastructures.

The fuel choices made in the Chinese market in the lead-up to winter this year look set to spur considerable interest across both the LNG and thermal coal markets in Northeast Asia — and impact the plotting of the price graph in the weeks to come.

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Insight from Brussels: Gas sector looks to P2G technology to survive low-carbon future

Could using low-carbon electricity to turn water into hydrogen and other gases keep the EU’s gas industry relevant in an increasingly CO2-constrained future?

The EU gas and power sectors are certainly interested in testing such technology at scale, as it could help them both with their different challenges going forward.

Natural gas and LNG suppliers are facing an expected dramatic decline in demand for their fossil fuels as the EU works to decarbonize its energy sector by 2050, while gas grid operators could see their assets stranded.

At the same time the power sector will have to integrate ever-increasing shares of renewable power, mostly variable wind and solar, creating huge demand for flexibility options to keep the grid balanced.

Coupling the two sectors through power-to-gas technology, known as P2G, would allow excess electricity in the system to be used to turn water into hydrogen or, in a second step using CO2, into synthetic methane, for example.

If the electricity used is renewable or zero-carbon, then the gases produced are also renewable or decarbonized. These gases can be used directly, for example in industrial processes or for transport. Or they can be injected into the EU’s extensive natural gas grid (within limits for hydrogen), and stored or transported as needed.

Small scale, high cost

Europe’s power and gas transmission system operators argue that this coupling would provide both the extra short-term flexibility and seasonal energy storage that will be needed to balance the power grid as more variable renewable power comes online.

EU policy is driving this change, with a new binding target to source 32% of the EU’s final energy demand from renewables by 2030. This is likely to push renewables’ share of electricity demand to around 50%, with even higher shares expected by 2050.

P2G plants can help by taking excess renewable and low-carbon power on the grid and using it to produce renewable, decarbonized gases. The problem is that such gases are currently much more expensive to produce than their fossil equivalents. This is in part because it is a high capital cost activity being done on very small scale in plants under 10 MW.

The EU’s formal gas TSO body ENTSOG wants to see a tenfold or greater increase in P2G capacity to around 1 GW by the early 2030s. This is to have enough capacity to test how this technology could support power grids with high renewable shares.

It wants to work with all stakeholders “to build a business case for P2G to attract investors.” That includes policy-makers, who have been rewriting the EU’s power market rules to help integrate renewables more efficiently.

“If the market does not deliver the investments in P2G facilities to scale them up to the EU industrial scale, some support schemes need to be designed,” ENTSOG said.

European gas suppliers’ group Eurogas has also called for an EU framework for supporting renewable and decarbonized gases, including harmonized national support schemes as well as a specific EU investment fund. It also wants the EU to set itself a binding target for using renewable and decarbonized gases, with the aim of enabling them “to reach technology maturity and scale.”

Crowded market for flexibility

The debate about whether to give renewable gas the same kind of preferential treatment that renewable electricity enjoyed during its early development is likely to continue into next year and beyond.

The European Commission is already exploring the options as part of planned updates to the EU’s gas market legislation. The formal proposals are expected toward the end of next year, after the new set of politically-appointed EU commissioners take office in November 2019 for five years.

A recent external study sponsored by the EC found that national tariff and grid access rules for renewable gas should be adapted as needed to encourage using it to gradually replace natural gas, while avoiding market distortions. The study cited support schemes and priority dispatch as options, both of which the EU has already used successfully to promote renewable power generation.

A key technical challenge for P2G will be developing large capacity electrolysers flexible enough to ramp up and down as needed in response to the amount of renewable power available. The economic challenge will be to make this flexible operation profitable.

P2G will also have to compete with other sources of power grid flexibility, including demand-side management, electric vehicle batteries, and other power storage technologies.

It will also have to compete with biomethane, a renewable gas made from purified biogas produced from organic matter.

The EU’s push to cut carbon is not just about the climate. It is also keen to reduce its fossil fuel imports, and developing all these new technologies could transform its political relations with its current energy suppliers, including Russia.

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In the LOOP: Exchanges CME, ICE face off for USGC light sweet crude benchmark

The battle to secure the benchmark for US light sweet crude on the US Gulf Coast crude heated up Monday as commodities exchange CME Group launched its physically delivered NYMEX WTI Houston Crude Oil futures and options contracts, just two weeks after chief competitor Intercontinental Exchange debuted its own USGC WTI marker.

CME HCL reflects “export-grade WTI” on an FOB basis at three Enterprise Products terminals in the Greater Houston refining area, according to CME. That contract will compete with ICE Permian WTI Futures, which commenced trading October 22 and represents the value of physical crude oil delivered to the Magellan East Houston terminal.

S&P Global Platts competes with both companies in providing pricing benchmarks to commodities markets.

“It’s become clear the status of the US light sweet crude market has moved from Cushing and the Midwest to the US Gulf Coast export market,” said Sandy Fielden, director of oil research with Morningstar. “It’s clear every new barrel of shale that gets produced now is destined for export. All the new pipelines built out of the Permian are headed to the docks, not the refineries.”

“All other things being equal, the price of light sweet crude is determined in Houston, not Cushing, because the marginal export barrel is setting the value,” Fielden added.

CME has told Platts it sees its HCL as complementary — not a competitor — to the current North American crude oil futures contract, its NYMEX WTI Light Sweet Crude Oil. The new CME WTI Houston contract can be traded as an outright value and as a spread versus NYMEX WTI at Cushing, Oklahoma. NYMEX WTI had 2.1 million lots of open interest on Friday. Each lot is a 1,000-barrel contract.

However, the increase in US crude exports has left many market participants searching for a new, more-relevant benchmark, which led ICE and CME to launch their Houston WTI contracts.

ICE forced CME’s hand when it announced Permian WTI in July. CME’s NYMEX WTI for years has faced headwinds in the form of questions around quality, and a changing landscape that sent more crude to the USGC. CME recognized the latter, saying in December 2011 it would “work with oil market participants to discuss developing a new Gulf Coast crude oil futures contract at the ECHO Terminal” in Houston, which at the time was under construction.

ICE is happy with the initial two weeks of trading on Permian WTI, an executive said.
“We’ve had 21 companies trade so far, which is a great start,” said Jeff Barbuto, ICE vice president and global head of oil sales. “The feedback from the customers has been positive and we think it can grow into a long-term benchmark for US pricing. Eight-hundred lots of open interest is really constructive.”

On Friday, ICE Permian WTI had 792 lots of OI and daily volume of 159, and the curve extends into February 2019. That compares with 653 lots of OI and a daily volume of 472 one week earlier, ICE data show.

Despite the common thread of WTI, the three contracts reflect different barrels as summarized in the following table:

CME WTI Cushing CME WTI Houston ICE Permian WTI
API 37-42 40-44 36-44
Sulfur max 0.42% 0.28% 0.45%
Nickel max 8 ppm 4 ppm N/A
Vanadium max 15 ppm 4 ppm N/A


Quality will remain an important determining factor in the success of these contracts as crude exports continue to rise. Citing Magellan data, Barbuto said the six-month average (April-September) for WTI into MEH off the Longhorn and BridgeTex pipelines was 42.4 API and 0.1281% sulfur.

Furthermore, while the US crude benchmark is in flux, Dated Brent has remained the largest global benchmark, even as global crude flows have continued to evolve, particularly with the growth in US exports. Indeed, most European buyers and many Asian buyers continue to price their US crude imports against either Dated Brent or ICE Brent.

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Insight Conversation: Jeffrey Currie

In the latest Insight Conversation video, Jeffrey Currie, global head of commodities research at Goldman Sachs, talked to Paul Hickin about the bank’s call on oil prices and the commodities impact of the US−China trade war.

The big question on everyone’s lips is whether we are going to see a return to oil prices at $100/barrel and beyond. Where do you think the market is going?

We’re not saying $100/barrel oil cannot happen. It’s not our base case, nor do we think it’s very likely. To get a $100 price spike, you need to have a sustainable loss in all of Iran’s exports for an extendable period of time… The key point here is yes, if you had a sustained outage you could see a spike of that magnitude, but in no way is it our base case. Our base case is for a modest decline in inventories in the fourth quarter, which will likely keep prices somewhere around $80/barrel. But the faster and sooner the Iranian barrels are lost, the greater the upside potential, because it’s harder and more difficult for the non-Iranian producers in OPEC to respond to that kind of disruption.

The key question is spare capacity. Can Saudi Arabia, OPEC and Russia deliver and make up what’s lost from, not just Iran but also Venezuela, if it experiences further falls in production?

It’s all a question of time. Always, when we ask this question, how much spare capacity does Saudi Arabia and OPEC have, it’s all a question of how long you are willing to give them. The longer you give them, the more rigs they put into the field, and the greater the spare capacity. In the last four months, we have seen a 20% rise in drilling in Saudi Arabia. You have already lost 700,000 b/d of Iranian exports and inventory built, which tells you there is a lot more oil in the market.

If we were to lose all of those Iranian barrels really quick right now, it would likely create a big problem, because we don’t think it will have the Partitioned Neutral Zone [estimated at 500,000 b/d] and other fields up and running until you get into the first quarter of next year. And then let’s not forget that the Permian has huge pipeline capacity expansions coming online in the third quarter of next year. So the longer we wait, the higher the probability of seeing global spare capacity increase to be able to accommodate almost any type of disruption. Now a $100/barrel price spike would likely require not only Iranian barrels being out on a sustainable basis, but something along the lines of Venezuela happening that would create further upside. So the short answer to your question: readily available spare capacity we would put at 800,000 b/d, remember that we have already lost 700,000 b/d, and Saudi Arabia is already at 10.7 million b/d. As you get into the first quarter that [spare capacity] begins to grow to the 1.5 million b/d range, and as we look further out into the second half of next year, there’s not an issue.

Goldman Sachs has a very bearish view on oil in 2019. Please explain your thinking.

Fast-cycle capital, as well as production, [has] fundamentally altered the way the oil market trades. What do I mean by fast cycle? Let’s think about deepwater: that’s what we call long cycle. You make an investment today, and it’s 5−10 years before you get the output. You make an investment in shale, and you get it almost immediately. That fast-cycle nature changes the response the industry has to a lack of spare capacity. Another way to say it is that it’s taking out oligopolistic market structure and turning it into a competitive market. That hasn’t changed.

Once we debottleneck [pipeline and midstream infrastructure] in the second half of next year, we think we will see very rapid growth in shale production, which will push us back into the new oil order or that “lower for longer environment.” Our target for oil prices at the end of next year is $70/barrel on a Brent basis, and then $60/barrel in the long term.

Earlier this year, you said you were at your most bullish in a decade regarding commodities demand. How has that view changed?

We’ve only reduced our demand expectations modestly, and when we think about the core behind the “most bullish in a decade” view, it was driven by three observations. First, strong robust late-cycle global demand growth, which we are seeing across the commodity complex. Second, supply curtailments in places like OPEC, as well as China: remember they cut back due to the anti-pollution and anti-corruption issues. And third, pipeline constraints in the Permian. Those were the core factors.

If we look at the demand component, I want to go over why late cycle really matters. And if there is one point I want to emphasize, it’s that commodities are driven by demand levels, while financial markets are driven by demand growth rates. Let me go over why that’s the case. We have the level of demand at 100 million b/d right now. It took the entire business cycle for the demand level to continue to grow to that level, and when demand gets up to that high level, it begins to stress the ability for the system to supply. So it’s the level of demand exceeding the level of supply, which creates a bullish market for commodities. Financial markets care about the growth rates, because they are expectations about the future: if the growth rate is good, it tells you to have a positive outlook in the future. So when we think about the current environment, with a late cycle the demand level gets really high and you draw down your inventories – that creates the bullish backdrop.

This is why commodities like oil give you a negative correlation against other asset classes. When demand begins to slow as interest rates rise, like we are seeing right now, you still have a situation in which the demand level exceeds the supply level, which stresses the ability of the system to supply and creates the upward price spike.

So what have we done with our demand growth rates? We had an expectation in oil of 1.75 million b/d when we wrote that report you are referring to. It’s now 1.6 million b/d. We took down emerging markets by 250,000 b/d, but increased the US in the developed markets by 100,000 b/d. So we have the US exceeding expectations, which is putting upward pressure on the dollar. The higher dollar is increasing funding costs in emerging markets, which is slowing growth expectations in those parts of the world, which is why we are reducing them. And you go back and you think about this: we are raising the US and reducing emerging markets, the exact opposite of what we did in the 2000s. In the 2000s, month after month I was taking down US oil demand and raising Chinese and emerging market demand. We had a very weak dollar backdrop over that time period. You had a robust China that needed to consume oil and other commodities, so the US was that marginal consumer who had to make room for the Chinese consumer, and you had a really weak dollar to achieve that redistribution of oil. Today it’s a similar dynamic, not as strong obviously as we saw before. The US is the engine of global growth right now and the strong dollar is making room for the US to continue to move forward. Put it all together, and it’s not that we have really taken down our demand forecast, it’s really that we have made room for the US.

What about about the US-China trade spat. How does that play out for commodities in general?

So far [the impact] has been relatively small. Our economists estimate the impact on China at 20 basis points on GDP growth – and in a 6.5% GDP growth environment it’s not that large – and then on the US they estimate it at below 5 basis points. So it’s relatively small, less than a 100,000 b/d when thinking in terms of oil demand.

Now to understand why it’s not having a big impact, let’s think about two bookend commodities: oil and soybeans. Oil was left out of the Chinese retaliation, but let’s use it as an example. Oil is completely fungible – it can be redistributed and moved around the world. Soybeans are not…

Overall, global soybean production comes out of China, the US, Brazil and Argentina, so there aren’t really any options for China to substitute away from the US, but Brazil and Argentina… Brazil cannot replace those US exports.

When we think about a lot of the goods that were targeted by the Chinese, they were very fungible goods, in which what we’ll likely see is a redistribution of supplies to avoid consumption of either Chinese or US goods that are going into either one of those countries. You will still get an inflationary pressure because you still get goods coming in, like soybeans, and that will have an impact on inflation in China and the US. However, I think the key takeaway here is that it’s modestly inflationary. It reinforces the inflationary trends already in place… but the impact on growth is relatively modest.

Do you feel the same about the metals side, given the tariffs on steel and aluminum?

With metals, it has definitely had an impact in the US on pricing – you can see it in the physical premium in aluminum as well as steel. Now in terms of it creating a supply response, it’s still relatively small and modest at best, which means it’s likely to be more inflationary than it is to be stimulative to supply. I think the one that has been hit the most is copper. When we look at copper right now, global demand growth is running at around 2.8%, so it has not been hit significantly. But the market itself was short copper a few weeks ago, which is an indication that people are quite bearish about global growth prospects. I think a lot of that is to do what’s going on with the trade war.

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Insight from Shanghai: China courts international traders with new crude contract

The Shanghai International Energy Exchange’s crude oil futures contract has got off to a good start.

The contract’s first expiry at the end of August marked another step on the road to developing a crude futures contract that China hopes will one day stand alongside ICE Brent and NYMEX light sweet crude.

The launch of the Shanghai contract on March 26 this year also coincided with the “internationalization” of other Chinese derivatives. Less than two months later, the Dalian Commodity Exchange’s well established iron ore contract was also opened up to international investors.

In actual fact, foreign companies have been able to trade Chinese commodity futures onshore for some time. But to do so requires setting up a domestic Chinese entity, with all the associated costs and approvals operating a company in China requires. By internationalizing futures contracts and making it easier for overseas capital to participate directly in price formation in China, the hope is that local exchanges will vie for international influence with incumbents like the Chicago Board of Trade, Intercontinental Exchange and the London Metal Exchange, which host many global agriculture, energy and metals benchmarks.

China’s leaders hope not only that Chinese exchanges will become international centers of price discovery, but also that prices discovered on these venues will become the benchmarks that are used to price commodities sold to China. Should this happen, these contracts will support another government objective:  the internationalization of China’s currency, the yuan.

Good start

Volumes for the Shanghai contract have steadily grown, with 3.4 billion barrels traded in August, a fifth of the volume for ICE Brent during the same month. ICE Brent marked its 30th anniversary this year; the Shanghai crude contract has only been in existence for six months.

However, liquidity is rarely a problem for Chinese futures exchanges, which host a number of well-established metal and agriculture derivatives. Many of these have higher trading volumes than international benchmarks hosted on platforms like CBOT and LME. Outside China, institutional investors and companies hedging physical exposure tend to be the main users of commodity derivatives. In China, retail speculators dominate.

This can clearly be seen by looking at exchange statistics. Open interest – positions held open at the end of the day and a measure of the contract’s use for physical hedging – is typically significantly larger than daily trading volume for contracts such as ICE Brent. This is because many traders are holding positions to expiry to hedge physical positions. In China, the presence of significant numbers of retail speculators trading in and out of positions boosts daily volume, which can at times exceed open interest.

At times, these speculators exacerbate price volatility, rushing into the momentum of a rising market only to exit just as quickly as the market turns. Allowing overseas capital to play a greater part in price formation could improve price discovery and reduce the influence of domestic speculators, as foreign players arbitrage away differences in price between Chinese and overseas venues.

Supply vs. demand

Existing crude benchmarks tend to reflect the price of oil close to the source of production or distribution. For example, Brent and Dubai are widely used to price light sweet and medium sour crudes. They represent the price of crude loading on ships from the North Sea and oil fields in the Middle East. WTI, on the other hand, reflects the price of crude delivered to Cushing, Oklahoma, a small town that sits at the nexus of a myriad of pipelines connecting producers with refiners across the US.

The Shanghai crude contract reflects the price of crude oil held in tanks at one of eight approved storage sites. These are located up and down the coast close to refining centers.

The contract can be settled by physical delivery. Normally, this is by transfer of a warrant – a receipt that allows the holder to take delivery of oil held in a specific tank – from the seller to the buyer. The seller chooses the grade and location of the crude they wish to deliver. This mechanism is similar to the established system of warehouses used by the LME and Shanghai Futures Exchange for the delivery and storage of base metals like copper and aluminum.

The price of crude oil benchmarks like Brent and Dubai depends on a wide range of factors. These include the strength of global demand, inventories, production expectations, macroeconomic factors like interest rates, and geopolitical factors that might pose a risk to supply.

In the case of the Shanghai crude contract, the level of inventory held in INE-approved, as well as non-exchange storage, is also a factor influencing price. If the market believes there is insufficient oil in storage to settle open positions, prices can become volatile, as the market prices in this uncertainty. A fall in INE inventories at the end of July to just 100,000 barrels likely contributed to the volatility of the contract in August ahead of its expiry at the end of the month. Prices had previously been moving in line with other futures like ICE Brent, but rose and fell sharply as oil was removed from and returned to INE storage.

Long road

Chinese buyers currently have to bear exchange-rate risk and costs when they buy commodities priced in dollars. These would be eliminated if they were able to price them in yuan. Should other countries also use the yuan as the basis for pricing their sales and purchases of oil and other commodities, it could provide significant support for the internationalization of the Chinese currency.

But even if the Shanghai contract proves a runaway success, there is a long way to go. Among other things, it would require the Chinese government to liberalize its financial institutions and remove the restrictions that currently stop the free movement of capital in and out of the country.

In the first quarter of 2018, slightly under two-thirds of reported foreign exchange reserves were denominated in dollars, according to the International Monetary Fund. The yuan accounted for 1.4% of total holdings, lower than the equivalent figure for the Australian dollar. So it may be some time yet before the yuan challenges the hegemonic status of the US currency.


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Insight: Steel, aluminum and coal reveal a “Trump premium”

Almost two years since it began, what has been the impact of the administration of US President Donald Trump on commodity prices? Joe Innace takes a look

If higher commodity prices reflect US presidential campaign promises kept, then President Donald Trump has already delivered on three fronts as he approaches two years in office.

The president campaigned hard on promises to help directly the US coal and steel industries and American manufacturing. It worked. Trump won key steelmaking, mining and manufacturing states like Ohio, Pennsylvania, West Virginia, Michigan, Indiana and Wisconsin.

It took a good year or so for Trump to settle in. Until November last year, most commodity prices had struggled to see their averages match, or surpass, the levels on the last day President Barack Obama held office. But with the passage of US tax reform legislation, an “America First” trade agenda in place and on full global display, manufacturing expanded and the domestic economy saw 4.2% GDP growth in the second quarter of 2018. In turn, this created more demand for energy commodities.

A group of 13 commodity benchmarks has been used by S&P Global Platts to track pricing performance during Trump’s term versus Obama’s eight years in office. Although fundamentals and a range of other factors have greater influence on commodity prices than US presidential policy alone, the exercise is intended to shed light on how prices and politics often intersect, where they’ve been, and perhaps to get a handle on where they might be going.

Ferrous, coal set the pace

After a slow start for most of 2017, steel, aluminum and coal benchmark prices were all averaging higher for the Trump period (January 20, 2017−September 30, 2018) than during Obama’s two terms in office. Largely because of an aggressive trade policy marked by the imposition of tariffs on steel and aluminum imports to the US, prices of both metals in the US market are up considerably compared with their average during the Obama years.

It’s not a stretch to acknowledge the metals price increases as a “Trump Premium.”

The price of US-made steel hot-rolled coil averaged $722/short ton through September 2018 under Trump, while it averaged $598/st during Obama’s two terms – a boost of nearly 21%.

The “all-in” price of primary aluminum in the US market is up almost 11% since Trump became president. This includes both the underlying, global London Metal Exchange price plus the S&P Global Platts US Midwest Premium that reflects regional supply/demand fundamentals and local logistics costs. It averaged $2,353/mt through September 2018 under Trump, compared with $2,127/mt under Obama.

And while coal prices in the US have not benefited from such direct trade policy as the tariffs implemented for steel and aluminum, the commodity has been buoyed by a president who embraces a pro-coal ideology. The benchmark price of railed Central Appalachian thermal coal through September 2018 has averaged nearly $60/st while Trump has been in office, compared with an Obama-era average of $56.41/st – about 6% higher.

Average commodity prices during Trump and Obama presidential terms

Surging energy prices

Most energy prices with Trump in office still lagged the average prices posted during the Obama years by about 22% at end-September 2018. But energy prices started to gain during Trump’s second year –with the exception of natural gas – to the point where they are now about 18% higher on average than the day before Trump took the oath of office.

Unlike the Trump premium in coal, steel and aluminum, however, these other commodities in the US market went along for the ride – more recently getting swept up by strong economic growth and manufacturing activity.

Leading the way — to the chagrin of American drivers — is CBOB gasoline, Chicago. From January 2017 to September 2018, this benchmark was up more than 21% to an average of 174.07 cents/gal. This compares with the day before Trump took office, when Obama left it at 143.45 cents. Chicago gasoline, however, averaged 230.22 cents/gal during Obama’s eight years, so it remains 24% lower under Trump.

With Trump as president, New York fuel oil through September 2018 was averaging $53.94/b, up nearly 15% since the day before he took office. But it also lags the Obama two-term average of $67.52/b by some 20%. Similarly, jet fuel (New Jersey Buckeye pipeline) is up 19.5% since Trump became president to an average for his term through September of $183.22 cents/gal, up from the 153.30 cents/gal contrails of Obama’s last day as president. Jet fuel pricing, nonetheless, averaged 226.41 cents/gal during Obama’s eight years, so recent Trump-era pricing still lags by about 19%.

Average prices for ethanol and natural gas through September 2018 under Trump have yet to exceed Obama-era pricing, mostly owing to abundant supply. But going forward, ethanol will be one to watch because Trump has directed the US Environmental Protection Agency to authorize year-round E15 sales. E15 is gasoline blended with 15% ethanol, currently restricted in the summer months because of gasoline volatility rules. The EPA aims to adopt final rules for fuel economy standards by March and year-round sales of higher ethanol blends by May 2019.

2019 growth in doubt

The US economy’s 3.5% GDP growth in the third quarter follows 4.2% growth in Q2, which was loudly trumpeted by the US administration. The latest GDP data came on October 26, just days ahead of the US midterm elections, and positive economic news is also good news for Trump-backed House and Senate candidates. Steel and other commodities benefit from such a rate of economic expansion. Steel demand, for example, tends to increase substantially when GDP grows at a rate greater than 3%.

“You’re seeing GDP and now wage growth; this drives consumer demand and gets you in a virtuous cycle, and that’s where we want to stay,” said Thomas Gibson, president and CEO of the Washington-based American Iron and Steel Institute.

But staying there may prove tricky in 2019, as the trade tensions of 2018 have the potential for a delayed reaction on the downside in a global economy. The International Monetary Fund in October lowered its forecast for US growth in 2019 to 2.5%, while leaving its projection for this year unchanged at 2.9% – after factoring in the potential impact of tariffs imposed by the US and retaliatory actions by other nations.

S&P Global Market Intelligence reported on the IMF forecast, noting the organization’s view that short-term risks to the financial system had increased, and that those risks could increase significantly if vulnerabilities in emerging markets and global trade continued to rise.

It’s the economy, stupid

There are eight full years of commodity price data for Obama’s two terms, compared with just two years for Trump. The past two years, many would agree, have been far more tumultuous than tranquil. Will we have like-period price data sets to continue comparing? Trump will indeed run for re-election in 2020, and many pundits are already citing Bill Clinton’s campaign advisor James Carville’s oft-quoted phrase, “it’s the economy, stupid,” as the determining factor.

Trump’s executive actions to impose import tariffs on steel and aluminum are likely to remain in place – although there may be country- and product-specific deals negotiated between now and the next presidential election, as he continues to use the trade hammer to forge new pacts. This America First trade and manufacturing policy played well on the campaign trail in 2016 among many voters in the Midwest states where steel and aluminum is produced and consumed.

Ensuing tax, trade and regulatory reform energized the US manufacturing base to the point where the National Association of Manufacturers’ monthly index reached an all-time high of 63.6 in June 2018. But it has been slipping ever so slightly since then. Might this reflect some waning enthusiasm on the part of steel and aluminum end-users that have seen their manufacturing costs rise – either by paying tariffs or higher prices for domestic material? “The tariffs are starting to take a bite out of profitability,” one purchasing manager in the chemical sector said.

In October the NAM’s Outlook Survey, which indicates the percentage of small-to-large manufacturers who are upbeat about their own company’s outlook stood at 92.5%, after posting an all-time high of 95.1% in June. That’s still a very strong positive indicator, despite some very minor erosion.

The early consensus is that if the US economy remains strong in 2019–2020, growing at a rate of 3% or more, then Trump should win another term. But sustaining such an economic growth level – or anything close to it – over the next 23 months ahead of the November 3, 2020 election is a big ask.

As such, US commodity prices will be among the interesting indicators to keep watching.

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