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Dollar Tree, Dollar General, King Dollar … and now, Dollar Diesel in the US

Big-time refined product traders are now shopping at the dollar store for their diesel. Platts assessed the spot market of benchmark US Gulf Coast ultra low sulfur diesel at exactly $1/gal on Wednesday, Dec. 16.

Not $1.0014/gal. Not 99.93 cents/gal. Not $1.0001/gal. Nope. $1/gal on the mark.

So for the same price as a 40-square foot roll of aluminum foil at a dollar store, you can also power your shiny European diesel car for up to 40 miles. Wrap your mind around that.

The cost of 10 party invites, 20 party napkins or a 12-foot banner can power your diesel generator for more than an hour. How’s that sound? (Besides noisy, I’d bet.)

What you’d pay for cheap sunglasses or 16 ounces of SPF 50, broad-spectrum sunscreen is roughly the same as what railroads brag they pay for the one gallon of diesel it takes to haul a ton of freight 500 miles. The future’s so bright.

It’s just odd. Spot markets don’t usually trade at a nice round number like that. Especially refined products, which trade at a spread — or differential — to a futures market, in this case the NYMEX ULSD January futures contract. Platts assessed the paper futures at $1.11/gal at 3:15 p.m. Eastern Time on Dec. 16, while the differential for physical Gulf Coast pipeline ULSD was assessed at an 11-cent discount to those futures based on seven trades by the likes of Trafigura, Koch and US Oil.

The futures are highly liquid instruments that trade two decimals past the penny and don’t land any more often on the 5 or 0 as the 1 or 7. So basically, there’s a one-in-five chance to match up with differentials, which trade almost exclusively in 5-point increments. Then again, they’d have to perfectly offset whatever cent and point discount or premium to the dollar was needed.

And they’d need to be close to the actual dollar, of course. That’s something new. A year ago on the same day, the flat price was at $1.6785/gal. Just a few months earlier, it was $3.0106/gal, on June 20, 2014. That was a typical price since a record high of $4.11385/gal on July 11, 2008.The fuel was only introduced in the mid-2000s, with Platts starting its assessments on May 1, 2006, at $2.2065/gal.

Platts has done 2,414 assessments since then for the widely traded diesel benchmark, and only 31 have landed squarely on the cent, without any fractional points afterward. This was the first to land on an exact dollar.

Mind you that, unlike dollar stores, it actually takes a lot of money to buy $1/gal diesel. That’s because this is the spot market, not the retail market where government data showed the US average for diesel at $2.338/gal on Dec. 14, 2014.

The spot market is where refiners, trading houses and end-users go to buy and sell 25,000-barrel lots that come out of production or out of storage or elsewhere before batches begin the distribution process, getting cut down to size for pumping 25 gallons into a car tank. And 25,000 barrels is slightly more than 1 million gallons. Even at $1/gal, that’s a lot of money. Slightly more than $1 million a traded piece, but far less than the $3 million a year and a half ago. Or the $4 million of more than seven years ago.

This Wednesday was only the third-lowest price ever paid for a gallon of Gulf Coast ULSD. Yesterday, Dec. 17, it was assessed at 99.90 cents/gal. The record low? That was 98.08 cents/gal, set Monday, Dec. 14, 2015.

Source: http://blogs.platts.com/

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Japan set for sweeping refining landscape change: Fuel for Thought

The Japanese refining industry is set for a landslide change as it aims to balance domestic supplies, stabilize its core petroleum business at home, and once that’s settled, expand overseas.

This is a markedly different strategy than before where Japanese refiners, and Japanese industry in general, could count on a stable domestic market and concentrate more on exports for growth. Now with greater export competition, and a shaky domestic market, there’s a need to get their domestic house in order before embarking on an ambitious and more risky overseas growth plan.

On the domestic front, Japanese refiners’ recent moves to integrate their businesses would mean that the local market will likely be dominated by two major refining groups in the next few years.

JX Holdings and TonenGeneral are to integrate by April 2017, while Idemitsu Kosan and Showa Shell are slated to do the same between October 2016 and April 2017.

Once integrated, the two refining groups would have a combined capacity of around 3 million b/d and could dominate roughly 80% of the 920,000 b/d domestic gasoline market. Gasoline accounts for a third of Japan’s 3.1 million b/d oil products demand.

The ultimate aim of these refiners, though, is not to dominate a dwindling domestic oil market, but rather to stabilize their core petroleum business, most of which is currently in Japan, by optimizing production and better controlling their domestic supplies to achieve sustainable growth.

JX and TonenGeneral’s integration would create a refiner with around 2 million b/d capacity and give the combined entity a share of more than 50% of the domestic gasoline market. However, JX and TonenGeneral would look to consolidate to reduce overlap in Tokyo Bay and western Japan.

Meanwhile, Idemitsu and Showa Shell’s merged company would have a capacity of a little over 1 million b/d and would control about 30% of Japan’s gasoline market. Idemitsu and Showa Shell, which do not have much overlap in refinery locations in Japan, have said the companies do not see the need to scrap or immediately integrate refineries.

Regardless of how refinery capacity optimization occurs, it should help restore balance in Japan’s oil fundamentals through greater efficiencies, at least in the short term.

Consolidate at home, expand overseas

In recent years, Japanese refiners have often suffered from cut-throat competition in the products market. The situation was worse in the years leading up to a round of capacity reductions, which were achieved by the end of March 2014. Prior to that, refiners would keep their crude runs propped up to reduce production costs, exacerbating the oversupply.

“Surplus capacity can be an obstacle because refiners tend to increase their output to reduce their costs,” Petroleum Association of Japan President Yasushi Kimura told a press conference in Tokyo on November 19.

Going forward, Kimura said the surplus capacity itself is not necessarily a problem. “It is about how to sell [oil products], essentially speaking.”

Maintaining a tight rein on domestic oil products supply while optimizing production and distribution through various options, including scrapping inefficient refining capacity and consolidating storage terminals, will be key for refiners to improve their earnings.

Growing competition in the international market from bigger and newer refineries elsewhere in Asia and the Middle East, is leaving Japanese refiners with limited options, which is why overseas deals will be a cornerstone of their growth.

In Vietnam, Idemitsu is a stakeholder in Vietnam’s 200,000 b/d Nghi Son refinery, which is expected to start up in the summer of 2017. JX is helping upgrading and expand Indonesia’s Balikpapan refinery to the 360,000 b/d capacity by 2022. JX is also looking to secure a license to retail gasoline in the country.

TonenGeneral is also developing a 230,000 kl (1.45 million barrel) fuel storage facility with a local partner at Port Kembla in the eastern state of New South Wales in Australia, where the facility is expected to be commissioned in the second half of 2017, after final approvals. The partners also entered into an agreement to acquire the fuel marketing and distribution company Petro National in Australia.

Such moves underscore the fact that Japanese refiners are strategically developing their downstream and midstream businesses in the markets where the demand for oil products supplies and imports are growing. This is a stark contrast to before when expanding overseas meant simply exporting more products on a FOB basis. — Takeo Kumagai

Source: http://blogs.platts.com/

Green targets drive demand for new forms of auto steel

The North American International Auto Show in Detroit is as big of an event for car enthusiasts as an Apple product launch is for techies. A car and tech enthusiast I am not.

But growing up in the Steel City and working on the Platts metals team has made me a bit of a metals enthusiast, and the Detroit auto show is a major event for metal enthusiasts, too.

Last year, the big news at the show was the aluminum-bodied Ford F-150 truck winning the prize for truck of the year. Some carmakers believed that aluminum would be key to helping US automobiles achieve Corporate Average Fuel Economy (CAFE) standards. In 2012, President Barack Obama tasked automakers to boost the average fuel economy of new cars to 54.5 mpg by 2025.

Fuel economy isn’t the only way to go green, though.

“There’s another consequence when you shift away from steel, and that’s on the environmental side,” Larry Kavanagh, president of the Steel Market Development Institute, told Platts this week during a break from the auto show. Kavanagh said aluminum production emits four to five times more greenhouse gas or CO2-equivalent emissions than steel production and requires seven times the amount of energy.

A University of California at Santa Barbara study found steel and advanced high strength steel primary production emits 2.3-2.7 kg of CO2 equivalent per kilogram of material, while aluminum production expels 13.9-15.5 kg of CO2 equivalent per kilogram of material. The study also found secondary production — or recycling — of steel and advanced high strength steel emits half the CO2 equivalents of recycling aluminum.

The Steel Market Development Institute said up to 30% of the total emissions for the internal combustion engine and hybrid electric vehicles are made during the production phase. Also, almost all automotive steel is collected and recycled, contributing to the more than 80 million st of recycled steel that’s made available each year to be manufactured into new products, according to SMDI.

Jody Hall, vice president of the automotive market for SMDI, said the association is raising awareness to automakers and regulators of the greenhouse gas emissions that are created even before a car hits the road.

There are new grades of formable advanced high strength steel that are being introduced to help steel win back market share in vehicles, notably in the chassis.

At the auto show, General Motors unveiled the 2016 Chevrolet Malibu. Its lower control arm is made of steel, whereas the 2012-2015 versions were made from aluminum.

A GM spokesman said the company opted to switch to steel because it met its goals for mass reduction, lowering material cost and cutting processing costs.

The 2016 Buick LaCrosse and all-new Envision also used steel in the lower control arm, which offered comparable light weighting performance to aluminum, if not better, according to a Buick spokeswoman. There are many examples, particularly in the LaCrosse, in which Buick opted to use steel instead of other materials, she said.

“Steel is really a new technology,” Hall said. “It’s not the old technology that people think.”

Source: http://blogs.platts.com/

US steel wonders if interventions are enough to keep imports at bay

A couple decades or so ago, Bethlehem Steel, then the USA’s second largest steelmaker, introduced a team of trade attorneys as it was about to embark on another round of massive unfair trade case filings against steel imports.

It wasn’t unusual for mills to have trade case attorneys, either in-house or on retainer, but Bethlehem was making a statement: This is how we roll. International steel dumpers, we’re coming to get you.

It was as though Bethlehem was establishing a new division as it prepared to continuously cast trade litigation. Its efforts and those of other US mills were not wasted. Multiple unfair trade case filings against multiple countries covering multiple steel products overwhelmed the US government, leading to multi-year blanket protection programs like America’s 7.5-year Voluntary Restraint Agreements on global steel trade in the late 1980s and the Section 201 market safeguards of the early 2000s.

Today it’s different. US mills still file trade cases, sometimes massively, but it seems the days when the government would step in to enact comprehensive solutions are over. Even standard remedies such as the establishment of anti-dumping (AD) and countervailing duties (CVD) against subsidized steel are not as robust as they used to be.

Witness the government rulings so far on the three 2015 dumping and subsidy cases filed against sheet imports: hot-rolled coil (HRC), cold-rolled coil (CRC) and hot-dip galvanized sheet (HDG). Earlier this week the US Commerce Department, usually domestic mills’ friendliest ally in Washington, dismissed the charges against two of three defendant countries in the HRC subsidy case — Turkey and South Korea — and put a relatively small CVD of 7.42% on HRC imports from Brazil. It was just a preliminary determination, but US mills had been used to virtual rubber-stamp treatment at this stage of the investigation.

US mills have a chance to turn the tables and argue for the imposition of stronger CVDs against exporters in all three nations for the final Commerce determination on May 23, but then the case goes to the International Trade Commission (ITC) for its final injury ruling. The ITC traditionally has been a much tougher customer for those seeking duties on steel imports.

Analysts at KeyBanc Capital Markets were underwhelmed by this week’s decisions regarding CVDs on HRC imports, noting that they were in line with Commerce determinations in the other sheet trade cases. “We expect a muted reaction for the group [of US mill petitioners] . . . considering expectations for uplifting trade case outcomes have largely dissipated following the recent de minimis CVD outcomes for countries involved, and the CVD outcome represents only a portion of an “all in” duty rate calculation as we wait for more clarity in [Commerce’s] preliminary antidumping determination in early March.”

KeyBanc said the more important duty determinations will be for dumping, but even there outcomes have been disappointing thus far. Just before Christmas, Commerce set a preliminary dumping duty of 256% on coated sheet steel imports from China. That whopper was in stark contrast to the provisional dumping duties set for other cited exporters: India (7%), Italy (0-3%), Korea (3-4%) and Taiwan (0%).

US sheet market players openly questioned whether these low preliminary AD duties, if finalized, would be enough to keep these imports out of the market, although additional CVDs of 3-8% on Indian coated sheet and 0-38% against Italian mills could help.

Bank of America Merrill Lynch deemed the late December coated sheet duty determinations “largely disappointing” and James Wainscott, CEO of US sheet producer AK Steel, said the non-Chinese preliminary duty determinations “do not appear to adequately address the dumping that we believe is occurring.”

The third sheet trade case, covering CRC imports, has been similarly disappointing. The ITC excused the Netherlands from the case after a preliminary investigation and no CVD determination was made regarding imports from Korea. CVDs for three other nations in the case, Brazil, Russia and India, were considered low at roughly 4-7%

Source: http://blogs.platts.com/

Against the grain: Agriculture grapples with price pressures

The gathering storm swirling around commodity markets augers of troubled times ahead. For agriculture, beset by the common concerns of currency fears, counterparty risk, an increased regulatory environment and once-bitten-twice-shy financial institutions, the climate is compounded by very real and entirely unique challenges.

Climate itself is amongst those challenges, but with growing population, increasing competition for land use, declining-to-stable crop yields and access to water, the question of how agriculture meets those challenges is occupying more and more thought.

The statistics are already eye-popping and, if true, the scale of the challenge ahead becomes more daunting. The UN’s Food and Agriculture Organization’s oft-quoted 70% increase in food production required by 2050 is a consistent headline grabber despite first appearing in 2009. In an article entitled “Barbarians at the farm gate” last year, The Economist stated “humans will need to produce [in the next 40 years] more food than they did in the previous 10,000 put together.”

The magazine wasn’t alone — around the same time, UK newspaper The Independentpicked up on a joint study involving Yale University, Michigan State University and Germany’s Helmholtz Centre for Environmental Research that floated the alarming concept of ‘peak food’.

Their research concluded that, for many staple crops, we’ve already topped out our maximum potential production.

That, physically, we cannot grow more. For cotton, dairy, eggs, corn, wheat, poultry, meat rice, soy, sugarcane, wheat — the list goes on, but you get the idea — we have passed the peak point.

Within a few months, Hollywood was at it too — the blockbuster “Interstellar” weaves a tale around humanity’s quest to survive after a mysterious blight kills off all crops except corn. The innate question of how to feed seven billion people has merged into the cultural mainstream in much the same way as harnessing electricity fired Frankenstein’s creature.

We’re living longer. We’re getting wealthier. There are more of us. And the climate is demonstrably changing.

If nothing else, the heady cocktail is likely to be reflected in volatility and increased risk to those looking to trade, and the era may prove to be a watershed for agriculture akin to the oil shocks of the 1970s.

Key to some of those changes was the adoption and development of new risk management tools, often powered by independent physical benchmark prices — assessed prices using a defined methodology and exposed to industry scrutiny which were able to represent values that the industry could use.

Established exchanges form a key element of the landscape and offer a number of robustly employed futures contracts, and will continue to form the spine of risk management strategies, but as some countries aggressively target expansion (largely through the old-fashioned way of bringing land into use — an option limited to a select few) growing production means the basis risks accrue further significance.

Agriculture isn’t oil though, and over years — despite leading the initial foray into trading, and lending key reference terms such as “exchange” to the physical institutions that are part of modern trading — has stood apart from the rapidly commoditizing international trading of metals, coal and energy.

However, with many of the core exchanges focused on key European or North American hubs, regions such as Australia, or the Russian and Ukrainian Black Sea incur a basis risk that may only grow increasingly onerous as volumes grow.

Market participants currently maintain hedging through a series of strategies including physical back-to-back sales or ill-fitting instruments that derive most price direction from other geographies.

Independent price reporting could facilitate a swap or other financial instrument that helps close that gap, trading as an outright price or as a differential to an established exchange.

It could also enable term contracts that cover long periods of time and maintain a link to the current market price.

And, with regulation and compliance playing an ever larger role in operations, the need to answer the question “where does this price come from?” looms ever greater in market participants’ minds.

Being able to cite the physical, market-tested indications that went into each day’s independent assessment enables those within the industry to keep track of their exposure, their mark-to-market values and auditing.

Russia’s current wheat production stands at some 60 million mt already — and is laying out ambitious plans to expand its non-GMO production and exports ever further.

And it’s not alone in that regard. As the volumes and the stakes grow higher, independent price reporting has a part to play in enabling market participants to at least better protect themselves from the uncertainties that lie ahead.

Source: http://blogs.platts.com/

Political promises squeeze Canadian oil industry

The oil industry had eight years of an energy friendly government in Canada and couldn’t get a single new export pipeline built.
Now, with newly elected Prime Minister Justin Trudeau keeping his campaign promise of banning tanker traffic off parts of Canada’s west coast, it put the already reeling industry further on its heels and could eventually force more production shut-ins and cuts in investment due to a lack of access to global crude markets.
The previous government, led by Prime Minister Stephen Harper, and industry put its eggs in the Keystone XL basket and in the end got sideswiped by the US government not approving Keystone XL while giving the nod to US crude exports. Apparently US shale development is less an environmental concern than Canadian oil sands.
Now the industry is pushing several new Canadian export pipelines, but has a new government to deal with that is seemingly tone-deaf to Canada’s oil industry challenges.
In mid-November, when Trudeau said an oil tanker ban would be implemented on the North Coast of British Columbia, it posed a major impediment to Enbridge’s proposed Northern Gateway pipeline. While the line already received regulatory approval from the National Energy Board, if a crude tanker ban is in place there would be no point in bringing crude oil to the coast, and no need for the pipeline. There are no solid plans for a refinery in the area.
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Work is already underway to develop a strategy to implement the ban, a Transport Canada spokesperson Natasha Gauthier said without indicating a timeline or the road map ahead.
She did not respond to pointed queries whether the ban would include condensate and LPG tankers and the LNG carriers that are expected to set sail from the ports of Kitimat and Prince Rupert from 2020 onward to navigate along the northern coast on their way to Asian markets.
If those products were included in the tanker ban, billions of dollars in projects would be at risk.
Extending ban southward imperils other projects
There is now talk of extending the ban farther south along the province’s coast and the transport minister has been asked to look into it, Carr said in November without elaborating.
A southern extension of the moratorium along the British Columbian coast would impact another major export pipeline project: the 890,000 b/d Kinder Morgan-backed Trans Mountain Expansion, for which an NEB ruling is due by May 20, 2016.
The expansion — which is already facing a two-year delay with a planned start-up now in fall 2019 — would allow an additional 29 Aframax crude tankers to load at Westridge in British Columbia and use existing shipping lanes from Port Metro Vancouver in the south coast to the Pacific Ocean, Kinder Morgan legal counsel Shawn Denstedt said recently at an NEB hearing in Calgary.
“It is pretty early to speculate what will happen [with the tanker ban],” Enbridge CEO Al Monaco said last month on a webcast. “We have heard the Prime Minister and federal Natural Resources Minister and we have also been told securing new markets is also an issue they will support.”
It will be difficult to secure new markets without new pipelines.
Another set of hurdles will soon emerge for Alberta’s oil producers with the federal government due to start a review of its regulatory process for approving crude oil pipelines, seek greater involvement of Aboriginal peoples and aim to reduce carbon emissions.
“A review of the approval process is in line with another election promise we made and will now be getting into a transition process with the NEB to take a close look at the existing procedures,” Carr said in late November.
“We are in the business of transparency, rather than guaranteeing approvals for pipelines. Our focus will be on a more robust oversight of the regulatory process and a thorough assessment and there will be a transition phase,” Carr said then.
If those changes were not enough for an industry on the ropes, the government is to soon unveil changes to its existing royalty structure.
Just as US politics doomed the Keystone XL pipeline, Canadian politics threatens more than that as election promises become reality. — Ashok Dutta

Source: http://blogs.platts.com/

Ethane cash cow a red herring for European petchems producers

In the next few weeks the first ship bringing US shale gas to Europe will arrive on the southern shores of Norway, marking an end to Ineos’ search for cheap feedstock to power its European petrochemical assets.

Plagued by $100/b oil, European petrochemical producers in 2012 were struggling with margins and started looking abroad for cheaper feedstock options. The contracting European margins coincided with plentiful and inexpensive supplies of ethane-rich natural gas in the United States.

Ineos’ $2-billion deal to build ships and storage facilities to import US gas for its flagging assets in Europe looked like a no-brainer. At the time, NWE naphtha was trading at a premium of $720/mt to Mont Belvieu,Texas, ethane, according to Platts data. This price differential was more than enough to cover the high logistical costs associated with moving volatile ethane some 3,500 miles across the Atlantic.

Fearing being left behind, Borealis, Sabic and Reliance rushed across the Atlantic to sign similar deals, pledging hundreds of millions of dollars to charter the as-yet unbuilt ships to transport the gas.

But as Ineos’ first so-called Dragon-ship docks at Rafnes steam cracker in Norway this quarter, the cruel irony is that the ethane cash cow has turned into a red herring as profits from bringing ethane across the Atlantic are now lower than simply cracking more traditional domestically produced naphtha.

According to Platts calculations, and using Mont Belvieu gas price of $113/mt and assuming logistics costs of $100/mt, the variable cost of landing US ethane in Europe minus the cost of selling any co-products associated with cracking the gas in Europe is $134/mt. The same calculation for European naphtha is $56/mt. This means that for the first time in history the marginal cost of producing plastics in Europe will not be determined by the value of crude oil, but by the price of US gas.

It’s a remarkable turnaround and the shift in the petrochemical merit order has everything to do with crashing oil prices and nothing to do with the price of gas so far.

So will it last?

Those that signed the deals have two defenses to claims that ethane purchase deals may be a bane rather than a boon for them.

The first is that the low oil price is temporary while ethane purchase deals stretch out for more than a decade. While it is undoubtedly true that most analysts expect oil prices to rise, many expect US gas to rise at the same time.

One metric to see ethane’s competitiveness to naphtha as a cracker feedstock is the crude-to-gas ratio. US ethane has had a close link to gas, while naphtha has a historically high correlation to crude oil. Therefore, a high ratio between the two products would indicate that naphtha is relatively expensive to ethane, and this would support ethane utilization over naphtha.

The ratio between crude oil and natural gas in the US averaged 29 in 2012 and the outlook was for crude prices to remain relatively strong to ethane. But the ratio has now fallen to around 15, a level not seen since 2009, when gas and ethane prices were much higher.

The outlook is for the ratio to rebound from current levels over the coming years but not reach the levels seen when ethane export agreements were first being signed. The ratio should average 21 in 2016 but fall to 17.2 in 2020, according to Bentek’s forecast for North American gas and Brent crude prices.

Furthermore, this shift is not a recent phenomenon. Naphtha has remained below the cost of landing ethane once all the co-products have been taken into account for about a year. It just hasn’t been relevant so far because exports haven’t started.

The second defense is that the landed cash cost of gas used in the chart above is not the same price that Ineos, Sabic, Borealis and Reliance paid for the ethane.

Company sources have said many of these deals were signed at a naphtha-related price, and as such may still be profitable as naphtha prices have collapsed. Indeed, one Ineos source said last year that providing oil doesn’t fall and stay below $40/b for a long period of time their deals will be profitable.

It’s currently a little over $34/b and analysts are split over whether it’s heading to $20/b or rising to $65/b.

Perhaps the biggest test as to whether the gold rush for US ethane is over is whether European producers will sign more deals to buy US ethane. At these economics, it’s not going to happen. And if they are in the future, they are unlikely to be structured at a discount to naphtha.

Source: http://blogs.platts.com/

China or Gulf: Which side of the force will prevail on CIS/Turkish steel?

The New Year has started for the CIS and Turkish longs steel markets with mixed signals, as the price sentiment in China increased slightly but the latest geopolitical uncertainty in the Gulf area raised concerns for the future market demand developments.

After a series of months characterized by falling Chinese steel prices, January started with billet offers from China increasing by up to $15/mt and similar increases reported by sources for other steel products. The Turkish scrap market and the CIS mills reacted quickly and the daily Platts assessment for imported scrap into Turkey and exported CIS billets both moved up some $2-$2.50/mt since the beginning of the year.

Is the force awakening in China? Much like the return of “Star Wars,” China remains the main driver of the steel market, but most steel markets have felt the pull of the dark side of the force due to the drop in prices during the last months.

While it is too soon to say if the current positive pricing sentiment in China will be sustained as the local currency is currently being depreciated further, it is important to notice that the 62% iron ore is currently holding above $40/mt CFR North China, after having hit a low of $38.5/mt CFR North China in mid-December. The daily Platts assessment for rebar exported from China also showed at the beginning of January its first uptick since beginning of August 2015.

But more uncertainties lie ahead in the global steel markets.

On a geopolitical level, the year started with worrying news about the tension between Iran and Saudi Arabia, quickly spreading to a number of other countries in the Gulf area. Sources in the Turkish rebar market noted that demand in the UAE and the Gulf area for steel products could suffer as a consequence of the increasing tensions, hitting directly the Turkish producers being historically very active in that part of the world.

Looking at the daily Platts rebar assessment for exports from Turkey we can notice that the increasing sentiment in China and the rumors of a possible cancellation of the country’s export rebate had pushed the assessment up slightly before the end of 2015, but the tension in the Gulf area quickly changed the sentiment in the market in the first days of January.

Can a recovery of Chinese prices be strong enough to overpower the uncertainties linked with the on-going tensions between Saudi Arabia and Iran? Only time will tell … meanwhile … may the force be with you!

Source: http://blogs.platts.com/

All eyes on 2017. Yes, 2017, if you’re in the metals world

Guess what, it’s official: 2015 was a terrible year for commodities. Analysis is starting to flow into inboxes of those involved in the business, and all appear to confirm that 2015 was a crushing year for commodities, with little joy forecast for this year.

The Bloomberg Commodity Index (BCOM), a measure of investor returns in raw materials, tumbled 25% in 2015, a fifth straight annual loss and the longest slide since the data began in 1991.

Cotton was the only gainer out of 22 individual commodity indices for the year. Crude oil was the worst performer, tumbling 45% on a supply glut.

Copper, aluminum, zinc, and nickel capped annual losses, with nickel dropping 43%, the worst performer in the Bloomberg Industrial Metals Index (BCOMIN).

Citi strategist David Wilson said that a “significant proportion” of refined nickel drawn into China throughout 2015 could have been used to meet growing financing demand for nickel, rather than real end-use demand.

In the year to November, China imported around 258,000 mt of refined nickel and 626,000 mt (gross tonnes) of ferronickel, volumes being up 108% and 146% on the year, respectively, “levels not consistent with the negative stainless melt rate growth trends seen within China last year.” Nickel is a key alloy in stainless steel.

The first day of trading in 2016 saw nickel prices fall by around $300/mt, continuing the price downtrend seen through Q4 2015.

The three-months nickel price closed the London Metal Exchange kerb session Monday at $8,505/mt. The metal started 2015 around $15,500/mt.

Adding to the woe, Monday saw Chinese stock markets hit limit down restrictions, meaning that trading was suspended until the close of play as the main exchange ditched 7%.

Broader commodity indices posted significant negative returns in 2015.

According to Bank of America/Merrill Lynch on Tuesday, for 2016, a strong US dollar “coupled with subdued global growth and inflation will remain significant headwinds for commodities, maintaining downward pressure on prices.”

In response to the price slide across metals in 2015, certain markets saw significant production cuts in order to help support the situation.

However, “despite nickel prices ending 2015 around 42% lower than the year open, nickel supply adjustments have been negligible outside of China,” said Citi’s Wilson.

He believes that a target of $8,000/mt is required “to drive necessary supply adjustments.”

With end of year positioning out of the way, a renewed focus on the weak Chinese market should see downward pressure remain on commodity prices, according to ANZ.

Macquarie said that, according to its data, the December aggregate manufacturing PMI for the leading industrial powers was unchanged from November at 50.1, its lowest since the end of 2012 and barely above the 50 mark that officially denotes contraction/expansion.

The outlook for commodities isn’t shaping up to be rosy. Are there any bright sparks amid the gloom?

Hmmmm…

“With gold and silver prices having been the best of a bad bunch in 2015, despite their losses, there is an argument that commodity investment index rebalancing in the coming days (January 8-14) could see a selloff in these metals,” said Dr Jonathon Butler, an analyst at Mitsubishi.

UBS’ Joni Teves struggled for a positive.

“Concerns about China following a weak PMI print, global equities selloff and geopolitical tensions in the Middle East have boosted gold’s safehaven appeal early this year. But given much disappointment with gold’s performance and reliability as a safe haven asset in recent years, investors are understandably hesitant,” said the analyst.

As one dealer said late last year, “It looks like most people have already written 2016 off…

Source: http://blogs.platts.com/

Once too little, now too much? US oil pipelines, projects, production and prices

An overabundance of investment capital has driven a wedge between US midstream asset valuations and actual shipping demand for infrastructure, and the imbalance looks to only be getting more severe as time goes on.
In the Permian, for instance, there are 2.16 million b/d of pipeline takeaway capacity, already above the 1.932 million b/d November production, according to Platts’ unit Bentek Energy.
But there is also 1.17 million b/d more capacity slated to come online in the form of new projects and expansions in 2016 and 2017, set against oil prices that may still be low enough to weigh on production.
The culprit behind both the overbuild and the severity of its impact is the commitment structure that supports the projects. Most projects have a dependable investment return in the form of take-or-pay contracts, under which shippers agree to move a certain volume of crude on the pipeline years in advance, and have to pay for the space regardless of whether or not they actually use the space.
That makes pipelines look like particularly attractive investments, and Plains All American CEO Greg Armstrong has pointed to the ready access to capital as the source of the overbuild in recent earnings calls. The available capital, fueled in large part by “irrational optimism,” Armstrong said.
That has driven up the value of the assets beyond their usefulness to the market.
“We definitely have an oil problem, but part of it has been driven by easy money,” Tony Starkey, energy analysis manager for Bentek, said. “There is still a ton of money around the world that wants to do something to earn a return.”
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But the imbalance can’t last forever — contracts or no, the declining growth in shipping demand and growing supply of space will have to push down tariffs eventually.
“The problem is that there aren’t that many great places to invest because, while easy money has done wonders to boost asset prices, it hasn’t done much to improve aggregate demand,” Starkey said. “Without which, the long run prospects for investments today look pretty grim.”
The take-or-pay contracts have, to some extent, insulated pipeline companies against competition from their neighbors — they still have to compete for spot volumes, but lengthy term contracts appear to lock in customers regardless of whatever low-cost options appear.
That was borne out to some extent in the second half of last year, during which time the spread between West Texas Intermediate crude at Midland climbed past its counterpart in Cushing as shippers were forced to move crude at a loss in order to meet contracted volumes.
That spread peaked when Platts assessed WTI Midland at WTI Cushing plus $2.75/b on Aug. 13, 2015, and Midland was stronger than Cushing on a total of 98 trading days in 2015.
But if midstream companies want to see growth — or even if they just want to avoid decline — they might have to allow some leeway in their contracts.
“When oil is in the $30s, ‘sticking it’ to the upstream guys doesn’t bode well for midstream if supply stops growing or falls,” Starkey said. “Yes, they are contracted to receive payment, but they also want growth on their systems, and seeing your counterparty go bankrupt likely isn’t in your best interest.”
On top of that, newer projects likely don’t have the same term length on contracts that the older ones did, since they are dealing with a “smaller and smaller supply group” and increased competition, Starkey said. That means less time until shippers can renegotiate their terms.
“I imagine the upstream folks have been less interested in locking in long-term contracts,” Starkey said.
That hesitance bears a contrast against the rabid pace of pipeline expansion that preceded the price decline of 2014. After the turn-of-the-decade shale boom sent inland production skyrocketing, the question for pipeline companies was less “how much will this cost?” and more “how quickly can we get this in the ground?”
But now there’s plenty of capacity, and prices have to shift to acknowledge that fact. Starkey said he thinks the market will turn to some combination of cancellations, consolidations and tariff deflation in order to relieve the pressure from the imbalance.
“Outright cancellations are possible for projects not too far along the completion process, consolidation could happen anywhere there is overlap, a la what happened with Saddlehorn and Grand Mesa in Colorado,” Starkey said. “Tariff deflation could occur if there is overcapacity out of particular regions, and midstream companies lower their transport costs to retain market share.”
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Source: http://blogs.platts.com/