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The dying embers of Britain’s blast furnaces

Blast furnaces across the UK are under threat as the steel industry bounces from one crisis meeting to another. And, as the last flames in the furnaces flicker in the headwinds, commentators are scrambling to find out what has gone wrong.

China is the easiest fall guy with its huge increase in low-priced exports flooding the international markets. But the scaling back of the British steel industry is as much down to historical bad decision-making as it is the current threat of foreign competition.

Indian-based Tata Steel is the largest producer in the UK, having taken on many of the British steel assets when it bought the European operation, formerly known as Corus, for a whopping £6.2 billion in early 2007. The UK division of that business is now a forlorn shadow of its former self with headcount diminished and many of the assets mothballed.

The company announced a further 1,050 job cuts Monday with the majority of jobs to be cut located at its blast furnace-based Port Talbot plant in south Wales. Talks are ongoing regarding the sale of its long products division, centered around two active blast furnaces in Scunthorpe, the assets of which have had their value written down to zero.

Sources close to the negotiations with Greybull Capital suggest that if Tata cannot sell the division by the end of March, then operations will be halted as the Indian parent company finally loses patience.

With the liquidation of the Teesside slabmaking business, SSI UK, in October last year, one of Europe’s largest furnaces was rendered another relic of a former industrial powerhouse. Undoubtedly it will face the same fate as Ravenscraig, a giant symbol of Scottish steelmaking that was closed in 1992 and demolished in 1996.

Sources suggest Port Talbot may itself run out of funding without a radical restructuring to restore profitability, hence this announcement of further job cuts.

The current chapter in the story of the British steel industry is one of accelerating rationalization as businesses find it increasingly difficult to compete in one of the world’s most globalized industries. But why is the UK, once the giant of the industry, such an uncompetitive place to produce steel?

The commentariat points the finger at imports, energy costs, business rates and government procurement policies. While these factors are accelerating deindustrialization, there are more crucial deep-rooted reasons why once proud production sites appear impotent in what are now critical times for the sector.

Throughout the escalation of this crisis, politicians and trade unions have called on the state to intervene. State intervention, much like protectionist trade measures, is booming in the global steel industry as governments look to save jobs.

The shadow chancellor John McDonnell used Italian steelmaker Ilva, Europe’s largest steel production hub, as a case study for positive state action. “The government intervened, they took over, they invested and turned the situation around,” he said.

In reality, the financial backing of the heavily-indebted steelmaker meant the company could lower sales prices without risk of bankruptcy. Tata Steel is among a host of companies competing with Ilva in Europe and it suddenly faced the prospect of competing on price with a huge local mill selling at Chinese prices. This drove the market down and hammered the margins of much of the European industry.

Even European steel producers’ association Eurofer has complained to the Commission about Italian aid for Ilva, saying it is against state-aid rules.

Tata Steel’s UK division suffers from legacy issues relating to its own former days as a state-owned, bureaucratic behemoth whose commercial decisions were influenced by political pressures.

The reason Port Talbot is such a production hub dates back to British Steel’s desire to shift investment and jobs to south Wales. This was as a result of a need to bring jobs to a particularly poor region suffering from high unemployment rather than any apparent commercial benefits.

The Teesside production site has a large dock and a huge blast furnace allowing it to benefit from economies of scale in both its production process and deliveries of raw materials. However, investment shifted away and the site was mothballed before its resurrection under Thai ownership.

This strategic misstep of spreading production facilities is critical in understanding Tata’s current difficulties in such a thin margin environment.

The company’s recently mothballed Scottish plate mills are supplied with slab cast miles away in Scunthorpe. The plate is then freighted back to the West Midlands where its main distribution hub is located.

Liberty Steel, the company behind the revival of another south Wales rolling mill, plans to buy the Scottish mills and supply them with competitively priced slab on the merchant market. It is likely the scale of the production would also be reduced to tailor the needs of the market, rather than the needs of government to provide jobs.

The subsequent privatization of British Steel presented new problems, with independent ports adding extra margin pressure with their cargo discharging costs significantly higher than those seen on the continent.

The direct comparison is Tata’s other major European production hub based in Ijmuiden, Netherlands. This unit of the business produces more steel, has its downstream operations on site and state-of-the-art technology after investment was centred on a single location.

It seems increasingly likely Tata will base its future operations at this division.

The UK industry is fragmented but the demand for steel means there is a future for steel processing companies. However, it appears the iconic blast furnaces, and the huge number of jobs that come with them, will soon be nothing more than ashes and dust.

A future for EAFs?

Perhaps electric arc furnace-based production has a future in the UK. The country has a reservoir of scrap; currently most of this is shipped to Turkey and Asia, which could be melted in domestic furnaces — as happens at Celsa.

Liberty, which is becoming the darling of the UK industry, continues to invest heavily in the steel industry. After restarting its hot strip mill in Newport, where it also says it will begin remelting, it has acquired a slew of assets from the stricken Caparo Group and is also in talks with Tata and Greybull over the Scottish plate mills.

Unlike Tata, Liberty has acquired all of its assets in a very tough market, and subsequently paid cheaper prices. Therefore it will not have to keep up high debt payments — Tata’s misery was compounded recently by a credit rating cut by Standard & Poor’s. (Standard & Poor’s, like Platts, is owned by McGraw Hill Financial.)

Liberty has also invested in a power station in Newport, which could theoretically reduce costs by supplying the steelworks, and is buying downstream assets such as Caparo’s tube business, guaranteeing it a market for its coil.

Others have taken this tack in the UK, notably Thamesteel and Celsa, to varying degrees of success; Thamesteel went out of business after one of its wholly owned fabricators ran into financial difficulty, and amid a lack of support from its parent company.

Celsa is still running, but the company’s financials are always a source of keen debate in the close-knit UK market.

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

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US ethanol seems to resist the siren song of low gasoline prices

US ethanol’s recent pursuit of gasoline’s nosedive has reminded me of the Gin Blossoms classic, “Follow You Down.” In the chorus of that 1996 hit, the band sings, “Anywhere you go, I’ll follow you down. I’ll follow you down, but not that far.”

That’s basically where US ethanol prices are at right now: Looking at gasoline prices, saying, “I’ll follow you down, but not that far.”

Ethanol maintained a discount to gasoline as long as possible, following gasoline all the way down to levels not seen in more than a decade.

As gasoline tracks crude into 12-year lows, ethanol has also ventured into its cheapest price since before the US Renewable Fuel Standard was originated in 2005, when the government began requiring blenders to use ethanol at escalating levels.

On January 13, the Platts benchmark Chicago Argo ethanol assessment reached $1.2650/gal, the lowest level since June 2005.

Meanwhile, the Platts CBOB Chicago pipe assessment was at 90.33 cents/gal, which was a fourth straight record-low assessment that was further topped in the ensuing four sessions, dipping to 82.25 cents/gal on January 20.

The ethanol assessment, on the other hand, shifted gears, stringing together its first five-day rally since October.

Ethanol seems to be putting its foot down, unwilling to go any lower. While gasoline wanders lower and lower, flirting with the treacherous $1/gal threshold, ethanol prices seem to have reached a floor.

Ethanol producers have seen the writing on the wall for a while now.

With all indications pointing to lengthy bearishness in the petroleum complex, US ethanol production was pushed to the limit as producers sought out maximum margin returns while they were still there.

Ethanol production finally topped the milestone 1 million barrels per day mark for the first time in November and has done so two more times since then, US Energy Information Administration data shows.

Because those mammoth production rates outpaced the escalating flow of exports, stockpiles approached 22 million barrels for the first time since March 2012.

The swelling supplies alongside the steady production allowed wiggle room for producers to continue to chase gasoline prices down toward the $1/gal mark, not to mention the fact that an ethanol RIN is still worth a healthy 65-70 cents to keep the blending incentive there.

But now that corn has taken an unexpected nudge north and China has again closed shop on the flow of dried distillers grains that helped prop up margins throughout 2015, holders of ethanol finally have a few reasons to be bullish.

Basically, without the extra help from DDGs and cheap corn, producers can’t afford to chase gasoline prices anymore.

The biggest question is, where do we go from here?

Do US ethanol producers continue to pump out 1 million b/d and seek export opportunities to thrive around the 10% blend wall?

E85 is steadily growing, but competing with gasoline prices near $1.50/gal is a far less-than-ideal environment to push higher ethanol blends, especially if you have to ask consumers to pay more for the fuel.

Until gasoline prices rebound significantly, US ethanol might be forced to settle into its new-found role as a costlier fuel option. Ethanol simply can’t follow gasoline down that far.

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

How quickly can Iran get its oil groove back? — Fuel for Thought

Iran’s speed of re-integration into the global oil market is a million b/d question mark hanging over the industry.

How much additional oil will flow from Iran will depend on how quickly Tehran can ramp up after several years that effectively shut in a chunk of its production and how fast it can make new inroads into an already crowded market.

The International Energy Agency is fairly bullish about Iran’s ability to get production up in the near term, suggesting that shutting in some production during the past few years will have increased well pressure, thus making it fairly easy for Tehran to achieve a quick volume boost. Indeed, it says, some of Iran’s core oil fields such as Ahwaz, Marun and Gachsaran may actually have been revived under the sanctions.

A bigger challenge for Iran, perhaps, will be selling the additional barrels in the volumes targeted by oil minister Bijan Zanganeh — 500,000 b/d in the immediate post-sanctions period and a further 500,000 b/d over the following months, leading to a doubling of the current 1 million b/d export level within six months of the lifting of sanctions.

Goldman Sachs suggests that the ramp-up in production may turn out to be more measured, noting that Iranian exports through the second half of last year held at a two-year low. This is more likely to reflect greater competition between Middle East heavy crudes than Iran’s inability to maintain output, it says. So, even if Iran does have the capacity to boost exports, it’s likely to have to offer discounts, and, the bank says, given already low prices, this could lead to a more gradual rise in exports.

The IEA also highlights the marketing challenge and expects Iran not only to be competitive in its pricing policy, but also to be open to crude-for-product swaps and deferred payment terms.

In the meantime, the IEA believes Iran has made considerable progress in readying its oil network and identifying prospective buyers and reckons an additional 300,000 b/d of crude could be flowing by the end of the March this year, although it does make the point that for now this volume is speculative.

It estimates that Iran increased production by 40,000 b/d between November and December to help fill storage tanks at the Kharg Island loading terminal in preparation for the lifting of sanctions and expects Iranian oil flows to rise towards pre-sanctions capacity of 3.6 million b/d within six months.

According to the IEA, 60% of Iran’s initial 500,000 b/d of new exports could be made up of Iranian Heavy, 30% of Iranian Light and the remainder consisting of a new heavy grade called West of Karun, which is due to make its debut in the second quarter.

Who will buy Iran’s oil?

The IEA thinks Iran will try to place around 200,000 b/d of additional oil with existing customers in Asia such as China, India, South Korea and Japan, and around 250,000 b/d In Europe, mainly with Mediterranean refiners that were traditional users of Iran’s sour crude.

Fereidun Fesharaki, chairman of consultancy Facts Global Energy, expects a 300,000 b/d export boost by end-March and another 300,000 b/d by end-June. Early volumes will head largely to Asia, where mechanisms for taking Iranian crude are already in place, he says in a note, while operational and banking issues will delay the European ramp-up to the second quarter.

Iran is unlikely to achieve its target of boosting exports by 1 million b/d within six months of the lifting sanctions because, he says, while Tehran wants to recover its market share, it doesn’t want an all-out price war.

Fesharaki says the first wave of exports is already placed but that further increases are likely to present more of a challenge, and that Iran’s marketing strategy is likely to evolve over the year ahead.

Fesharaki says the volume of condensate is somewhere between 30 and 50 million barrels whereas the volume of crude stored afloat is between 10 and 15 million barrels. The bulk of the floating condensate is likely to go to China, Japan and South Korea, he says.

Iran will need to free up its tanker fleet as soon as possible to deliver crude but selling these condensate barrels, given their “specialized nature,” could prove to be tough, the agency says. So, until substantial volumes of this ultra-light oil can be sold, Iran will likely concentrate on selling crude from Kharg Island. — Margaret McQuaile

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

Despite holding steady, North Dakota braces for oil supply crash

When North Dakota oil production broke above 1 million b/d for the first time in April 2014, many expected that the 2 million b/d threshold would be breached in relatively short order.
With WTI spot prices averaging over $100/b in the months that followed, some even speculated that 2 million b/d may be too modest of a goal for a state in the throes of a shale oil renaissance.
But prices, and those expectations, have come crashing down.
Now, rather than striving for 2 million b/d, state officials are hoping to maintain production above 1 million b/d.
And there are indications that a significant drop in Bakken supply may already be underway.
In November, less than 1.18 million b/d was produced, the state’s Department of Mineral Resources reported last week. Since December 2014, when North Dakota set an all-time production record of nearly 1.23 million b/d, statewide oil production has averaged just below 1.19 million b/d and has risen for two months in a row despite stagnant demand and plunging prices.
While Lynn Helms, the state’s top oil regulator, called recent production numbers “quite a surprise” amidst market shifts largely unsupportive of domestic production, he indicated the relative success would be short lived.
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“We cannot sustain production at sub-$30/b prices,” Helms told reporters following the release of the latest state supply data.
Helms believes that WTI spot prices will need to average roughly $50/b in order for current production to be maintained. If prices return to the $30-$40/b range, production will likely stay above 1 million b/d, but will likely stay just above that level and will fall steadily, by about 10,000 b/d each month, if prices do not climb above $40/b in the near term, Helms said.
There are indications that production may have already fallen off dramatically.
The rig count, long seen as a supply bellwether, fell to 47 on Monday, its lowest level since August 2009, when it was 45 and clearly on the rise. A year ago, North Dakota had 157 active rigs and four years ago it had 204.
Permitting has also declined substantially, dropping from 152 drilling permits in October to 125 in November and to 95 in December. The all-time high was 370 in October 2012.
Helms, who pointed out that permitting was last below 100 in May 2010, pinned the decline on “decreasing optimism” in short-term oil prices.
Prices have also impacted flows out of the Bakken.
According to data released by the North Dakota Pipeline Authority last week, about 52% of Williston Basin oil, or roughly 645,000 b/d, was exported by pipeline in November while 41% was exported by rail. The data marks the first time since June 2012 that a higher percentage of oil was moved out of North Dakota by pipeline than rail.
According to the data, 6% of Williston crude was refined at the state’s two refineries and about 1% of the crude was sent to Canadian pipelines by truck, both percentages that have held steady for years.
Since 2012, the last time pipeline and rail traffic reached parity, the percentage of Williston crude shipped out by pipeline fell as low as 17% in April 2013, when total pipeline capacity was about 515,000 b/d, and 75% of oil was shipped by rail, when rail capacity was 1.15 million b/d. Pipeline’s share of total Williston transportation averaged about 23% in 2013, 31% in 2014 and 39% in 2015.
The trend towards pipeline and away from rail is likely to continue amid current market fundamentals, according to Justin Kringstad, director of the North Dakota Pipeline Authority.
“It will shift more and we will see even more barrels moving on pipelines,” Kringstad said Wednesday.
The share has increased mainly due to the shrinking WTI-Brent spread, which has caused waterborne imports to become cheaper than railed Bakken crude for East Coast refiners.
How dramatic and sustained that shift will be remains to be seen.
And while it’s unclear where prices and, in turn, North Dakota production will ultimately wind up, the shift in fundamentals has altered the conversation.
Now, instead of breaking through the 2 million b/d threshold, many are waiting for the 1 million b/d level to be fallen through.

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

California’s contrarian gasoline market reverses trend again for 2016

The US West Coast market is strange. Disconnected from the rest of the US, it’s a bit of a red-headed stepchild, especially for gasoline.
While the Gulf Coast can send refined products up to the Midwest or Atlantic Coast via pipeline, creating natural, obvious arbitrages, no infrastructure extends westward past the Rocky Mountains. This isolation (and strict environmental mandates in California) makes the West Coast one of the most volatile gasoline markets in the world.
That unpredictability was exasperated in February 2015, when ExxonMobil was forced to shut the gasoline-producing fluid catalytic cracker at its 149,500 b/d Torrance refinery after an explosion.
From the time the explosion occurred through the end of August, the differential for Los Angeles CARBOB gasoline saw a day-on-day price change of at least 10 cents/gal 43 times. During the same period in 2014, the price moved at least 10 cents/gal just five times.
brown-la-carbob
The summer is always a busy time for gasoline markets, but that period in 2015 was a different kind of beast for the West Coast. High demand, inconsistent imports and refinery outages created even bigger daily moves than even the most experienced traders were accustomed to seeing.
So, naturally, West Coast gasoline differentials have done nothing but fall since the start of 2016. CARBOB’s day-on-day change has averaged around 6 cents/gal over futures since January 1, but most of that has been trending lower instead of dropping one day and jumping the next.brown-west-coast-gasoline-stocks
While the Torrance refinery hasn’t fixed its FCC issues (if or when it does, there’s an agreement in place for PBF to buy the plant) other refineries along the West Coast have ended planned and unplanned turnarounds, boosting production and pushing gasoline inventories to an 11-month high.
Furthermore, trading has been very illiquid lately relative to normal patterns, with summer-grade specifications set to take place in mid-February.
If historical trends are any indication, 2016 prices for CARBOB could continue to fall through March before seeing a slight rise in April that will carry to August. But if there’s any lesson to take away from the West Coast over the last year, it’s to never expect anything at all.

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

Good news, bad news for US biodiesel industry in 2016

Traders, marketers, producers and other stakeholders of the US biodiesel industry have converged on Tampa, Fla., this week for the 2016 National Biodiesel Conference to review the last year and look ahead to what 2016 brings.

Despite spending 2015 awash in uncertainty due to the US Environmental Protection Agency’s delayed decision on the Renewable Fuel Standard blending mandates, the biodiesel industry ended the year with a few key victories.

First, the EPA in late November finally released the blending mandates for 2014, 2015 and 2016, giving the industry guidance into how much biodiesel will be required to be blended into US fuel stocks.

Second, the industry for the first time in three years enters 2016 with the federal $1/gal blenders tax credit already in place. Congress reinstated the credit in December through the end of 2016.

Finally, biodiesel production remains strong.

Data released by the EPA late last week showed that biomass-based diesel volumes reached 1.814 billion gallons, breaking the previous record of 1.79 billion gallons set in 2013. That number far outpaces the 1.73 billion gallons called for in the 2015 RFS mandate.

Furthermore, the RFS mandates call for an increase of biodiesel to 1.9 billion gallons in 2016 and 2 billion gallons in 2017.

Joe Jobe, the chief executive officer of the National Biodiesel Board, told reporters on Tuesday in Tampa that domestic producers have more than 3 billion gallons of standing production capacity registered with the EPA.

But while the industry has secured some milestones, all is not well.

The free fall in oil prices and refined products continues to impact the biodiesel industry. Each drop puts biodiesel at a competitive disadvantage to diesel fuel.

NYMEX ultra-low sulfur diesel futures fell to 86.57 cents/gal on Jan. 21, the lowest level in more than 10 years.

Meanwhile, feedstock soybean oil futures remain in the 30 cents/lb range.

The difference between the feedstocks and heating oil futures means that the boho factor, which measures the relationship between biodiesel and diesel fuel that producers use to determine margins, has jumped dramatically in recent weeks.

On Jan. 20, the boho factor reached $1.33/gal, the highest level since June 1, 2011.

Low ULSD futures put biodiesel at a competitive disadvantage. It doesn’t make financial sense to obligated parties when diesel fuel is so cheap. Obligated parties often find it more prudent to buy Renewable Identification Numbers to satisfy RFS blending mandates.

For biodiesel to be competitive again, sources tell Platts, a few things could happen. First, ULSD futures could rise, cutting into the boho and making physical biodiesel more attractive.

Crude oil prices have rebounded slightly in the last few days, but no one can say with confidence that the market has hit rock bottom and prices will rise.

Second, soybean oil prices could fall, lowering feedstock costs and making biodiesel cheaper to produce. This could allow producers to lower offers to make the fuel more competitive to diesel fuel.

The final option would be a rise in RIN prices. In February, the EPA will release its first set of renewable fuel production numbers for January 2016.

If production is low, RIN prices could be forced to rise as obligated parties start buying up RINs before they become scarce.

Regardless, traders will be paying a lot of attention to several markets — not just biodiesel — hoping for a clue as to what comes next.

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

Lay-ups loom in the dry freight market

I stare out my office window on the 23rd floor and there they are, stretched out as far as my eyes can see, dry bulk vessels sitting pretty in the Singapore strait.
Although each vessel is of a different shape and size they all have one common enemy — unemployment.
With the engines running and crew on board, these vessels are burning fuel into thin air, literally waiting for orders.
Owners are holding steady, with many unwavering in the face of historical lows in the freight market.
The time charter equivalent of current Capesize freight voyage rates is around $1,000-$2,000/day in the Pacific, and operating a Capesize vessel even with the current bunker market rout, costs around $6,000-$7,000/day, depending on the vessel specs of course.
With these sorts of numbers, do the economics make sense for owners to park their vessels in cold lay-up, i.e. turn off the engine, move the crew onshore, and employ two watchmen to sit on deck?
According to sources, the cost of cold lay-up only makes sense if the vessel is squared away for at least a period of time.
The upfront fixed cost of putting a vessel into lay-up is high, considering the cost incurred to remove and reinstate the crew and ballast the vessel to and fro.
If a vessel is locked in Malaysia’s Labuan, the daily cost of the lay-up was heard to be around $1,000-$2,000/day, over a minimum of six months. In order to bring the vessel back to life, it would take from two weeks up to one month.
At the moment, there’s a trickle of vessels calling it quits and heading to rehab, but many more are waiting for a recovery in the market. In effect, it’s like putting a plaster on a cancer cell.
The absorption of tonnage has to be significant, culling out the long tonnage currently drifting in North China and Singapore, in order to see rates go back to black.
Owners are looking for divine intervention – such as weather disruptions at discharge ports, or a surge in positional tightness from an increase in energy needs in Europe after an unseasonably hot summer.
And as the Goddess of Fortune looks down from the Singapore river into the sea, one can only wonder when the tides will return in favor of owners.

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

Where’s the silver lining? Metals market airs concerns over global benchmark process

Regulation. Regulation. Regulation. Once again it is being blamed for the London Bullion Market Association Silver Price — operated and administrated by CME Group and Thomson/Reuters — settling around 6% below the spot price January 28. A matter of some contention across the market.
The jury is well and truly out on whether or not it is the fault of the system, or just another headache embedded by over-regulation.
The LBMA Silver Price settled January 28 at $13.58/oz. When the daily auction process kicked off the spot price was $14.42/oz.
Questions were raised about the process across the metals market January 6, after it took 60 attempts to settle.
One trader said January 28 that he would point the finger of blame at over-regulation of the market.
“I would not say it’s anything technical — the auction was functioning as programmed,” he said. “I’d say it’s definitely to do with regulations and supervision.”
He said that an arbitrage as wide as the spot and settlement, with nobody picking up the slack, “suggests all dealers/market makers, or whoever, were not allowed to input non-client-related orders.”
A bullion banker agreed.
“People are too scared to change their orders in the middle of the process so it got stuck,” the banker said. “In the old days, banks would step in and take positions in order to balance the process. No-one dares do that anymore, as then they have to answer to compliance etc.”
In July 2014, following a market consultation, CME/Thomson Reuters was chosen to provide a technology, administration and governance package for the calculation of the London silver price.
Participants include HSBC, JPMorgan Chase Bank, The Bank of Nova Scotia, Toronto Dominion Bank and UBS.
“The system is broken,” said one precious metals dealer. “In the old days, if it was out of line, someone would have bought the fix [now known as the LBMA Silver Price] and then sold the futures. It’s a joke — that’s all I know.”
One trader jumped to CME’s defense: “The CME is not at fault here. They don’t charge anything for people to trade on it. Market participants merely have to sign up to be a fixing/agreement member. People can amend orders as the fix is progressing. They don’t tell people not to buy. Blame the regulators.”
The official line from the CME was:
“The LBMA Silver Price is established through a transparent electronic auction mechanism designed to adjust the price until there is equilibrium between buy and sell orders. Given the orders placed in the auction today by five participants, the buy and sell orders became balanced after 29 rounds and the LBMA Silver price was established at a price of $13.58.”
However, an email was circulated, allegedly from the CME to clients, and passed to Platts, saying:
“The platform worked as it should, in fact perfectly. It’s as good as the orders the participants enter. If you are a client of a ‘participant’ I guess you should direct this question at them. If you want individual flexibility, become a participant.”
A banking source questioned that argument as “nonsensical.”
“If you want individual flexibility, become a participant. As their own rules state:
A participant has to be a Full Member (Ordinary or Market Making) of the LBMA. The participant also needs to have a Loco London Clearing account. Applicants to be a Full LBMA Member must demonstrate that they actively trade spot, options or forwards in the London Bullion Market, pass KYC procedures and declare conformance with the Non-Investment Products Code.
How many producers or consumers meet those criteria?”
The blame game, and guessing, continued January 29. Whatever the case, let’s hope this issue doesn’t continue, as the end-users of the global benchmark could be the ones that feel the real impact at a time when producers are struggling along at best.

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

Miami meeting looks to Asia to help buoy demand for met coal

Metallurgical coal market traders and miners who met in Miami this week see Asia’s promise perking optimism after a run of price declines and bankruptcies.

Japanese and South Korean buyers of US met coals are said to be keeping up stable volumes, especially of high-vol, high-fluidity types. Colombian high-vol traders are sniffing out further Japanese business and trying to expand sales in Europe outside Turkey.

Japanese trading groups and Asian steel mill executives were in abundance at Coaltrans, to keep tabs on changing dynamics in the US and negotiate new contracts.

As Daniel Kimura of trading group Mitsui & Co. explained, the need to blend with lower quality coals has pushed up use of high-fluidity coals, and depletion of the Gregory mine in Australia is keeping interest up for US coals. Blackhawk and Arch Coal have signed new deals in Japan and South Korea.

For Europe, US met coal demand in on the wane, as some coke technicians have reduced usage of high-fluidity coals by experimenting more and not prioritizing CSR as much during weak steel utilization.

Tata Steel, a stalwart US coking coal buyer, is reducing volumes fast, with US PCI use in Europe under threat on Russian and Australian competitiveness.

Asian interest is good for now, with historic lows in freight rates, helping make the case for US high-vols being shipped halfway around the world.

As for shifts in the US industry footprint to accommodate lower demand, a miner said to expect big changes in the year ahead.

After several coking coal mine acquisitions and Chapter 11 filings in the past year, the market remains on a roller coaster ride.

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

Pemex reform efforts in Mexico hobbled by oil downturn: Fuel for Thought

Falling crude oil production, falling refined product output and falling income have led many to believe that the sky is falling on Mexico’s state-owned oil company Pemex.
The perilous situation for Mexico’s energy industry — and Pemex is Mexico’s energy industry — has not been lost on officials who are trying to reform the company and, by extension, the nation’s energy landscape.
Mexican officials have long argued that a strong Pemex would be a major feature of its energy reform. The company, they said, would metamorphose into an efficient, market-oriented, financially autonomous state enterprise that is able to compete on equal terms with international majors in the private sector.
Unfortunately, the deep dive in the price of oil has put Pemex on an even shakier footing, with the company now losing money on crude production, its core business, for the first time since it emerged as a major producer in the late 1970s.
For years, the profitable upstream division of Pemex shouldered the losses of petrochemicals, refining and other businesses. No longer, says Arturo Carranza, senior analyst of the Mexico City-based Solana consultancy.
“To my surprise, during the first three quarters of 2015, the upstream division was making a loss, just like the others,” Carranza said.
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The first barrels of oil from private-sector newcomers following Round One of the reform effort are not expected until at least 2018. This makes arresting steadily falling crude production difficult as low oil prices have deprived Pemex of investment capital of its own.
Mexico’s crude oil production fell to 2.275 million b/d in December, down nearly 12% from 2010, according to Pemex data.
Pemex is not only starved for E&P money, all segments of the company are looking for investment dollars.
This is why Pemex recently opened up most aspects of the company, from storage and distribution terminals to pipelines, refineries, and petrochemical plants to outside investors.
Pemex paying price for years of regret
Unfortunately for Pemex, the need for investors comes when asset prices are low due to low commodity prices and the company’s hardware likely needs plenty of upgrades to bring them up to speed.
Since Pemex favored the crude production side of its business over others, the downstream refining business is in sore need of repair. This is one reason the company’s refined product output has decreased over the years.
At the end of December, Pemex produced 1.283 million b/d of oil products, down from just over 1.415 million b/d in 2010.
The result of this was Pemex needing to import more products, which, in combination with weak oil prices, made Mexico’s trade gap balloon to nearly $10 billion in 2015.
In addition to bringing in private sector money, Mexico is also trying to transform its energy pricing to more market-based prices.
Pemex first tried to do this in the 1990s with natural gas by tying it to the US benchmark Henry Hub. This was thought to not only give Mexico a market-based price but allow for hedging as well.
However, one of the complications with that change was that the price did not accurately represent Mexico’s domestic natural gas fundamentals.
This is now changing with the Los Ramones pipeline that will allow Mexico to import natural gas from US shale plays. Not only will the pipeline bring gas to a Mexican market hungry for it, but now the US price will have an
element of the Mexican market.
“But it should have been started about 10 years ago, when the demand signals began to emerge,” said Houston-based energy consultant George Baker. “When demand began to exceed supply for gas within Mexico, there was almost no
way to meet it. Hence, industry was disrupted in much of Mexico for some years. Only now, as Los Ramones progresses, gas supplies are meeting current demand, though demand is likely to grow.”
Mexico is set to further expand the reform of domestic market-based prices by using spot prices across its energy sector from upstream oil and gas to downstream derivative products.
Pemex has a long road to reform ahead and while the sky may not be falling the clouds got a little darker at the end of last week when S&P downgraded its credit profile due to “expected lower hydrocarbon prices.”

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