heatingoilinfo

US ferrous scrap market players take a gamble on April’s prices

Every other April, ferrous scrap dealers descend upon Las Vegas for the annual Institute of Scrap Recycling Industries (ISRI) convention, held there every two years.

With the event held at Mandalay Bay Resort and Casino this year, there were numerous nearby opportunities for convention-goers to gamble. Roulette wheels, blackjack tables and sports books where the NCAA Basketball and Master’s Golf Tournament broadcasts were being shown, were all within earshot of the convention hall.

Before even touching down at McCarran International Airport, five miles south of the glittering Vegas strip, many scrap dealers had already placed their first bets.

Those scrap dealers were betting on the market, which lately would be the equivalent of betting on the forsaken Cleveland Browns in American football or the woeful Aston Villa team in European football — which is to say, your chances are not very good.

However, the US scrap buy week, typically the first week of each month, was shaping up differently for April. The US scrap supply chain had been recently beaten down from consistently low prices, to the point where the volume flow had become a trickle.

And suddenly, mills had healthy April scrap wish lists, bolstered by higher finished steel prices in the wake of import-limiting unfair trade cases and improving order books.

The convention was scheduled to begin April 2. Not the best timing for ferrous scrap buyers or sellers who traditionally transact all their monthly scrap sales during a frantic few-day period within the first week of the month (a unique quirk of the industry and perhaps worthy of a blog post for another day).

With the possibility looming of having to transact scrap deals in their hotel rooms in Las Vegas, missing out on presentations and meetings, working on Eastern Standard Time while in Pacific Standard Time, combating the three-hour time difference and everything else that comes with an extended stay in Las Vegas, the prospect of finalizing sales the week before the convention was enticing.

Mill scrap buyers may have sensed as much. During the week of March 28, several days before most would depart for Las Vegas, buyers were making inquiries about early deals.

Some floated offers with prices attached — up around $30/lt from March levels. Some sought April scrap commitments on a pricing-to-be-determined (TBD) basis, a very common occurrence in the market (and perhaps worthy of yet another blog post for another day).

Dealers wanted larger increases, $40, $50, maybe $60 more than March. Dealers did not want to begin shipping scrap on a pricing TBD basis, losing most of their leverage against scrap-starved mills.

So many dealers made a slight gamble. They left the $30/lt on the table, made no TBD commitments, turned their cell phones off and left the office on Friday, April 1.

Some dealers stayed home, others went ahead to the ISRI convention. By Tuesday afternoon of the convention-week-turned-buy-week, the market was up $50/lt almost uniformly throughout the US.

The waiting game had paid off and dealers had their long sought-after price bump.

Of course, this is 2016, and all good news is met with a certain skepticism. Dealers were asking, “What is the catch? When will the other shoe drop? Was up-$50 too much?” as any significant market rally brings with it the concern of an immediate correction.

And there were the usual concerns about the sustainability of the strong scrap price increases as well: Can the recent success of US finished steel price increases be sustained? Will China’s steelmaking overcapacity crush hopes for US mill pricing once again? Are recently surging US scrap export volumes and prices sustainable?

However, the up-$50/lt scrap price boost is not causing material to flood the market immediately. Scrap flows have the ability to be shut off like a faucet but rarely, if ever, do they turn on like a faucet.

The strong US dollar, the bane of US scrap dealers for the better part of 2015 and 2016, has softened. The weakening dollar has allowed exports to recover and has helped mute steel imports.

Chinese billet prices have gone up and availability has gone down, leaving a void for international steel mills who will seek to fill their input needs with scrap.

Prime scrap grades are tight in the US and steel mills are issuing more and more price increases.

Now might not be the time for scrap dealers to double-down on black, but it also does not look like the time to run from the table.

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

Discount Heating Oil Prices is a company where one can find the lowest home heating oil prices. The company also provides delivery assistance to your home punctually and securely. Just visit the official website, enter your zip code, browse the lowest price available on heating oil in your place and click on the “buy now” button. Gettingdiscount heating oil in Massachusetts is now just a click away from you

About these ads

Central Asian oil: destined to disappoint?

The stagnation pervading Central Asia’s oil industry could be alleviated by a couple of big announcements in the coming months, on the Kashagan and Tengiz fields.

But industry veterans are more heedful of the numerous obstacles presented by the region, from the geological to the bureaucratic, and an unpromising global context.

Home to some of the world’s largest oil and gas fields, ex-Soviet Central Asia and particularly Kazakhstan was once an exciting frontier for the industry. But of late Kazakh oil production has stagnated at around 1.7 million barrels per day, partly because of a decade of delay starting output from the giant Kashagan project.

A consortium led by Chevron has also delayed plans to increase output at Tengiz from around 600,000 b/d to nearly 900,000 b/d, a project that could cost tens of billions of dollars.

In neighboring Turkmenistan, planned gas exports to Europe have made little headway due the cost of building a trans-Caspian pipeline, doubts about European demand, and difficult regional politics.

Turkmenistan’s gas exports have increased — the International Energy Agency expects it to have pipeline capacity for 80 billion cubic meters/year of exports to China by the early 2020s — and it has hopes of eventually building another pipeline across Afghanistan to South Asia.

But for now Turkmenistan is increasingly reliant on China as a sole client. More marginal projects, in Tajikistan and Uzbekistan, are languishing.

Kazakhstan might have thought it need not worry, until oil prices collapsed. But its economy is at a standstill and state finances suffering.

State producer KazMunaiGaz has been at daggers drawn with its upstream subsidiary, a semi-independent entity listed in London.

A row over the parent company’s under-payment for crude appears to be resolved on April 4, but the subsidiary’s scrapping of dividends for 2015 disappointed investors.

Confidence could get a boost if Kashagan starts producing. Foreign executives and Kazakh officials involved in the project have said it will start toward the end of this year.

The project has been dubbed a “failure of the industry” by a top official from France’s Total, chief financial officer Patrick de la Chevardiere, after leaking pipes forced the Kashagan consortium to abort an attempted startup in 2013.

The World Bank has warned that low oil prices increase the chances of further delay.

Whether Kashagan will be trouble-free once it starts producing is also unclear. The field is still at the frontier of what the industry can handle, due to high sulfur levels, which led to the leaks, and intense pressures below the Permian salt layer.

Estimates of how much Kashagan will produce following startup vary. Theoretically it will have a capacity of 370,000 b/d, but Platts has been told the “real” level will be 300,000 b/d annually, reflecting the fact that staff will be barred from the main artificial island used for operations when well intervention work is under way, due to the risk of hydrogen sulfide poisoning.

Once the field starts up, President Nursultan Nazarbayev’s leadership is likely to need additional projects to absorb Kazakh labor and materials. But Kazakhstan’s reputation as a place to invest has been tarnished by sluggish administration, the lack of an independent judiciary and use of strong-arm tactics.

In the latest dispute with investors, the state is demanding $1.6 billion from the consortium that runs the giant Karachaganak oil and gas field. Operated by Shell and Italy’s Eni, Karachaganak produced 390,000 b/d of oil equivalent last year, about 60% being liquids, and is also due for expansion.

The parties “are determined to find a consensual solution and to peacefully resolve the issue,” Kazakhstan’s energy ministry has said.

Above-ground difficulty

Paradoxically, some executives argue in private that the tightening of international anti-bribery regulations has made it more difficult to operate in Central Asia.

The story of the former Soviet Union’s oil sector has long been tainted by claims of corruption, ranging from the mundane giving of fax machines to, in the case of Kazakhstan, transfers of fur coats, speedboats and payments for Swiss boarding schools.

Some reasons for disillusion are less controversial. Geologically, the north Caspian and Kazakhstan’s coast have been thoroughly explored and where resources might still be abundant, corruption is not the only issue.

Tajikistan has hopes of uncovering subsalt resources near the Afghan border perhaps akin to the Galkynysh gas field in Turkmenistan, thought to be the world’s second largest.

But in impoverished Tajikistan even basic letter writing skills are lacking among younger officials, let alone industry or economic competence, a foreign oil executive told Platts, requesting anonymity.

The joint venture conducting a 2D seismic survey across a swathe of Tajikistan has found it hard going. The survey has involved drilling deep holes for the laying of explosives in order to get clear seismic images from beneath the salt layer, adding to costs “significantly,” Julian Hammond, the chief executive of Tethys Petroleum, said.

Tethys, which set up the joint exploration venture with Total and China’s CNPC in 2013, is now under pressure to withdraw due to its inability to meet its share of costs.

While a vibrant mix of large and small companies might revive Central Asia’s oil sector, in reality smaller companies, lacking connections, financial weight or expertise, have struggled.

Reports from London-listed Roxi Petroleum outline numerous difficulties involving the need to pump vast amounts of drilling fluid into its deep, high pressure wells in Kazakhstan to keep them under control, resulting in them becoming clogged, as well as various objects getting stuck thousands of meters below ground.

Others have been overwhelmed by a licensing system that stipulates long periods of “trial” production when oil must be sold domestically at controlled prices.

Getting permission to export typically involves building facilities for eliminating flaring, but this can be difficult when the state forbids the raising of additional funds on stock exchanges without its permission.

The pricing issue was a major reason why Australian independent Jupiter Energy shut down its production in February. It says it could be producing 2,500 b/d of oil from its existing wells, but would fetch just $3-6/b.

“The company continues to endure a frustrating operating environment,” Jupiter said last month.

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

About these ads

Acquisition set to increase Alaska’s jet fuel buying, but still outpaced by majors

The last decade of consolidation in the US airline industry has created some of the world’s largest airlines but the most recent move, the purchase of Virgin America by Alaska Air Group, makes a smaller splash from a jet fuel buying perspective.

The $2.6 billion price tag will give Alaska more of a foothold on the East Coast and help solidify its role on the US West Coast by giving it a larger share of the California market with Virgin America’s slots in San Francisco and Los Angeles. The move has the added benefit of keeping JetBlue, which Alaska says it has now surpassed, from buying Virgin America and adding to its West Coast portfolio.

But even as Alaska says that it is poised to become the fifth largest US airline, it still has a ways to go before it starts to rival the big four, American, Delta, Southwest and United — at least in terms of jet fuel buying.

In terms of fuel consumption and management, the addition of Virgin America’s fleet and routes represents 21% of Alaska’s total fuel usage. In 2015, Alaska used 508 million gallons of jet fuel, paying $1.88/gal, according to the company’s financial reports. Virgin America, on the other hand, used 169 million gal and paid $2.07/gal. Independently, Alaska had been increasing its own fuel consumption, adding 8.3% to its annual fuel buying in 2015.

Despite the addition of Virgin America, Alaska’s fuel consumption still tracks slightly behind JetBlue and significantly behind the other major US carriers. Even if the buyout results in further growth and not slight consolidation of routes, there is a wide gulf between fourth and fifth place. Southwest Airlines was the fourth largest airline in terms of fuel use in 2015, consuming 1.901 billion gallons, according to its financial reports. In total, US carriers used 16.73 billion gallons of jet fuel in 2015 for scheduled service, according to the Bureau of Transportation Statistics.

Rank	Airline	2015 Fuel Consumption (gal)	Average Cost ($/gal)	% of Expenses
1	Delta	3.988 billion	$1.90	23.0%
2	United	3.886 billion	$1.94	23.0%
3	American	3.611 billion	$1.72	21.6%
4	Southwest	1.901 billion	$1.90	23.0%
5	JetBlue	700 million	$1.93	25.9%
6	Alaska	508 million	$1.88	22.0%
7	Spirit	255 million	$1.82	28.3%
8	Hawaiian	234 million	$1.78	22.1%
9	Virgin America	169 million	$2.07	25.7%

Source: Airline Form 10-K annual reports

International routes obviously help the top four airlines with their extra billions of gallons of fuel consumption. Alaska’s international routes currently only include Canada, Mexico and, as of last year, Costa Rica.

Of course, airline mergers can take a significant amount of time to impact trends. It was only last October that US Airways flew its last route, nearly two years after the merger first occurred. Virgin America reportedly already issued a tender for its 2016-17 jet fuel supply. Considering the often-lengthy process of airline mergers and acquisitions, market sources believed that each company’s respective fuel management policy would continue for now, likely delaying any potential and significant changes to the airline’s fuel buying and management strategy.

“So far they [Virgin America] will stick with their own process of bidding alone,” one industry source said. “[They will need] time for the merger to be validated and so on. We have time.”

While Virgin America issues tenders to supply fuel, it outsources its fuel management to World Fuel Services. Alaska manages its fuel in-house, according to market sources.

“Tough to tell which way management goes,” a trader said.

Despite consolidation and some overlap in routes, some in the jet fuel market did not think that there would be a large change in overall industry jet fuel consumption because of the merger.

“Overall the aviation market is growing anyway despite of merging,” added the industry source who said Virgin America is sticking to its bidding process. “I don’t really see real impact here.”

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

About these ads

California’s tough rules a blessing and curse for refiners: Fuel for Thought

Refiners operating in California expect a tough environmental regulatory permitting process. This has been a bit of a curse at times, causing long delays and restrictions on modifying their plants.

But it has also been a blessing. While the strict rules make the fuels more expensive to make, it also limits the number of suppliers who can supply the fuel to California, giving regional refiners virtually unlimited access to demand in a state where gasoline demand is greater than any other and growing.

Give this backdrop, it was interesting to see what may have been a brief loosening of restrictions in Southern California because of a personnel change open a window of opportunity for the restart of ExxonMobil’s Torrance refinery.

That reopening, which had been slowly moving through the environmental regulatory process before the ouster of the longtime head of South Coast Air Quality Management District, was necessary before ExxonMobil could sell its Torrance plant to East Coast refiner PBF Energy.

Long-time head of South Coast Air Quality Management District, Barry Wallenstein, was voted out in a 7 to 6 vote taken by the regulatory agency’s 13-person board during a closed session on March 4.

The vote to oust Wallenstein occurred after January’s appointment of two board members shifted the balance of power to the Republican camp, a move which was expected to result in “a loosening of requirements” and less rigorous air quality policies, according to sources familiar with the situation.

The timing of the board change will help facilitate the sale of ExxonMobil’s Torrance refinery to PBF, which is contingent on the proven performance of the refinery’s gasoline-making FCC unit, shut February 2015 after an explosion and a fire.

Wallenstein had headed the agency since 1997, and his removal caused dismay among environmental groups, who feared any loosening of regulations would bring back the nasty smog, which plagued the Los Angeles Basin for years.

In early April, following Wallenstein’s departure, agency approval was given to restart the 87,000 b/d FCC unit at ExxonMobil’s 149,500 b/d Torrance, California, refinery.

The restart was a bone of contention among Torrance residents, due in part to ExxonMobil’s failure to notify the community of a hydroflouric acid pipeline leak last September, an action for which it was fined by the state.

While the Torrance restart plan has multiple stringent and rigorous monitoring requirements, it expects refinery emissions levels would exceed permitted levels because it will not use pollution control devices known Electrostatic Precipitators (ESPs) during the restart process.

“This limitation on use is necessary to ensure the safety of the start-up procedure but will minimize excess emissions to the maximum extent feasible,” the agency’s order of abatement said, referring to not using ESPs continuously during the restart.

Personnel change doesn’t mean looser rules

Industry participants caution in assuming an agency change in Southern California means a loosening in the state’s environmental regulations.

“Our mandate is to ensure petroleum refining activities are done as safely as possible,” said Paul Penn, Emergency Management and Refinery Safety Program Manager at the California Environmental Protection agency.

The California Environmental Quality Act, passed in 1970, requires extensive review of project impacts, using 18 environmental factors to determine whether to issue permits.

Despite the personnel change in Southern California’s air quality regulatory body, the state’s strict guidelines are not under threat — and neither is PBF’s deal for ExxonMobil’s Torrance refinery.

The state’s strict CARBOB gasoline and diesel specifications make the fuels more expensive to produce, it also limits the number of suppliers who can sell the fuel to California drivers.

The higher production cost, combined with logistical issues such as lack of pipelines bringing in product from outside the region and the expense of fixing a Jones Act vessel from other US regions, give regional refiners the upper hand in supplying California and surrounding states like Washington and Arizona, who have opted in to using California spec fuels.

And while other refiners have said at various times they want to leave California, it helps explain why PBF’s iconic executive chairman, Tom O’Malley had been on the look out for a California refinery.

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

About these ads

California’s tough rules a blessing and curse for refiners: Fuel for Thought

Refiners operating in California expect a tough environmental regulatory permitting process. This has been a bit of a curse at times, causing long delays and restrictions on modifying their plants.

Long-time head of South Coast Air Quality Management District, Barry Wallenstein, was voted out in a 7 to 6 vote taken by the regulatory agency’s 13-person board during a closed session on March 4.

In early April, following Wallenstein’s departure, agency approval was given to restart the 87,000 b/d FCC unit at ExxonMobil’s 149,500 b/d Torrance, California, refinery.

Personnel change doesn’t mean looser rules

Industry participants caution in assuming an agency change in Southern California means a loosening in the state’s environmental regulations.

The California Environmental Quality Act, passed in 1970, requires extensive review of project impacts, using 18 environmental factors to determine whether to issue permits.

The state’s strict CARBOB gasoline and diesel specifications make the fuels more expensive to produce, it also limits the number of suppliers who can sell the fuel to California drivers.

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

About these ads

As Chinese steel starts to call its own

With Chinese steel prices on a steady recovery since the Lunar New Year holidays, supply and production allocations have swung firmly towards serving the domestic market.

Buyers overseas have meanwhile found it hard to play catch up with Chinese offers, as delays or attempts to be coy with sellers are usually met with unwelcome news the next day that prices have climbed even higher.

Feedback from participants on both sides of the market suggested that they did not think this bout of price increases is showing any signs of losing steam just yet.

For Chinese suppliers, who have been blamed for everything from dumping to the demise of the UK steel industry, the past few months have perhaps seen them undergo a coming of age of sorts, as they realize the tremendous influence they exert on global markets.

This was in plain view at a recent industry conference, where at least two speakers pronounced Chinese steel’s position as global price setter, by virtue of the nation being the biggest producer, consumer and exporter, as well as its futures exchanges, home to the most liquidly traded steel contracts.

“There’s no need to look at overseas demand,” declared an official at a government think tank in his speech. “Once domestic prices go up, global prices go up.”

Another official from the Shanghai Futures Exchange boasted how they have recently been swarmed by visits from the CME, LME and SGX, all keen to understand the reasons behind the explosion in volumes traded in its hot rolled coil contract.

In the physical market, those who have cried foul against unfair trade have moved to establish formidable barriers to Chinese exports. But it is ironic to note how overseas buyers are now starting to bemoan the disappearance of Chinese offers in the market.

This is particularly evident in markets such as galvanized sheet in Europe where the disappearance of Chinese offers of thin gauge material has resulted in severe shortages in the market.

The complaints of end-users who are no longer able to secure cheap Chinese steel will surely sound insignificant against the macroeconomic backdrop of governments and central banks worldwide, scrambling to avert a seemingly inexorable deflationary spiral.

But who really knows what might come next, or when the release valve might open again if Chinese domestic demand falters?

As the international markets await the faltering of Chinese domestic demand, what appears certain is that the world should get used to working with the whims and fancies of Chinese Steel.

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

About these ads

RIN generation is up, but more biofuels mandates are on the way

With the latest batch of EPA Moderated Transaction System data due to be released in the next few days, giving some insight into RIN trading in the US, now seems like an appropriate time to take a dive into the current RIN situation.

US renewable fuels and RVOThe 2016 Renewable Volume Obligation under the Renewable Fuel Standard calls for 18.11 billion gallons of renewable fuels to be blended into US transportation fuel stocks. Each of three categories of renewable fuel has their own individual mandates within that overall mandate, with the remaining allotment generally taken by ethanol.
Last year, the biofuels industry produced 16.72 billion gallons of renewable fuels, generating 17.88 billion RINs. (Under the RFS, each gallon of biodiesel generates 1.5 RINs; hence the discrepancy between volume produced and RINs generated.)
Through the first two months of 2016, 2.844 billion total RINs have been generated on 2.687 billion gallons of renewable fuel. Compared with the same time frame in 2015, RIN generation is up 5% year on year.
The biggest gain, percentage-wise, comes in D4 biodiesel RINs, which have increased 40% year on year through February. What’s most interesting is that, traditionally, biodiesel production and RIN generation is typically lowest in January and February. That could indicate that there could be quite a plethora of RINs by the end of the year, if previous production trends continue.
US D4 RIN generation, 2014-2016
Since D4 biodiesel RINs can be used to satisfy three different portions of the RVO – the biodiesel, advanced biofuel or renewable fuel mandates – they are particularly useful in the RIN market. Hence, they’re priced higher compared with D5 and D6 RINs.
That robust RIN generation could be sorely needed. D5 advanced RINs are currently behind last year’s pace, at approximately 8 million RINs compared to last year’s 9.7 million through February. That’s most likely a reflection of the decrease in sugar cane ethanol imports into the US through the early part of the year. But the advanced mandate this year calls for 1.48 billion gallons of advanced fuel outside of the cellulosic and biodiesel mandates. Last year, advanced RIN generation came in at 146 million RINs, far below the 2016 mandate.
Meanwhile, ethanol RIN generation is ahead of last year’s pace, 2.426 million RINs compared with 2.333 million RINs in 2015. But February RIN generation fell to 1.18 billion RINs, below the 1.2 billion RINs per month needed to meet the 14.5 billion gallon mandate. But February usually is the lowest month for RIN generation as ethanol plants begin to shut down for maintenance.
US ethanol production, 2014-2016
Of course, the RIN market will be affected by more than just RINs generated this year. There’s still a large amount of RINs left over from 2015 that can be used to comply with up to 20% of this year’s RVOs. Published reports have placed the number of these “carry-over” RINs at 544 million D4 RINs and 1.46 billion D6 RINs.
Two key questions, though, will have an impact on RINs for the rest of the year.
First, will biofuel production and RIN generation continue at its current pace or slow down? At its current clip, biofuels RIN generation will come about substantially short of the required mandates. A large chunk of that deficit is in the advanced mandate, and certainly some of the robust biodiesel RIN generation can satisfy that burden. If production slows, however, obligated parties will have to tap into those banked “carry-over RINs,” taking away some of their flexibility.
Second, what will the EPA propose for its 2017 mandates for cellulosic, advanced and renewable fuel in June? (The EPA already released its 2017 biodiesel mandate, at 2.0 billion gallons.) The most volatile time for RIN prices comes in June and November, when the EPA publishes its proposed and final RVOs. If the 2017 mandates continue to climb, and if the number of carry-over RINs is liquidated to cover 2016 RVOs, it seems inevitable that RIN prices would be affected.

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

About these ads

Qatar’s OPEC MAX meeting and the oil price rout that wasn’t

There was much gnashing of teeth as Qatar’s grand meeting of oil producers failed to reach agreement April 17 to freeze production at January levels.

Commentators predicted a collapse in oil prices and some discerned the demise of OPEC itself.

But since then the expected rout in prices has yet to materialize, stock markets have been unfazed, and the outcome from the point of view of OPEC’s dominant Arab Gulf members may not be unsatisfactory.

No doubt some delegates found it annoying to needlessly spend 12 hours cooped up in a five-star hotel in Doha, albeit with a visit to pay their respects to the emir of Qatar, Sheikh Tamim bin Hamad Al Thani.

The failure of the talks was an embarrassment and will be felt by OPEC’s weakest nations, particularly Venezuela, which is in a state of crisis and badly needs oil prices to rise.

That prices did not immediately fall more than a couple of dollars owed something to a strike by oil workers in Kuwait, which caused the country’s production to fall initially to just 1.1 million barrels per day, barely a third of normal levels.

In the aftermath of the talks, Russia, which had invested much effort trying to broker a deal, indicated it would continue pumping at record levels, above 10.8 million b/d, helping to cap prices.

Amidst the failure to agree a freeze and Russia’s determination to boost output, there were reasons for markets not to panic, at least for the time being.

Markets had after all not given much credibility to the proposed production freeze. And production prospects are now depressed not only for Venezuela, but a number of countries worldwide.

Some observers are starting to doubt Iran has much more to offer the market for the time being than the increase it has managed since sanctions against it were lifted in January – generally estimated at 300,000-350,000 b/d.

Investment bank Tudor Pickering Holt said April 18 that further significant increases from Iran would require more capital expenditure, which was “not likely in the current environment.”

More fundamentally, the economic impetus for a production freeze has somewhat waned since the idea was first proposed in February. Back then, prices were around $10/b lower than when the April 17 meeting came round, and had recently hit $27/b, amid generalized worries about the global economy and China in particular.

Since then, the outlook for the world economy can’t be said to have transformed. But in terms of oil demand, some of those jitters have eased, as documented by successive monthly reports from the International Energy Agency.

In February the agency was talking of a “false dawn” for oil prices, in March this had changed to “light at the end of the tunnel.”

By this month it was predicting oil markets would come “close to balance” in the second half of this year, with supply exceeding demand by just 200,000 b/d in the third and fourth quarters.

Oil demand in China, India and Russia has been robust, the IEA added. Why then sweat to get a deal in Doha?

The question was pertinent for OPEC’s core Arab state members and above all Saudi Arabia, which had given mixed signals about the proposed freeze.

Saudi Arabia has cast doubt on the desirability of oil prices rising much further, sometimes framing the issue in terms of diversifying its economy.

In terms of oil markets, one question is how far prices can rise without causing a rebound in US shale oil production. The answer, with hundreds of US shale wells drilled but sitting idle – uncompleted and waiting for prices to rise – may be not much.

“As things get back into the $40-45 range then we would start completing the drilled but uncompleted wells,” James Volker, chief executive of Whiting Petroleum, which has around 150 such wells in the Bakken and Niobrara shale, said in February.

But the April 17 meeting in Qatar was about more than prices. For some participants the idea of sealing a major pact on supply management outside of normal OPEC boundaries – brokered by Russia, with help from rising regional power Qatar – may not have been attractive.

Granted, the collapse of talks was a blow to participants’ prestige, but what might have been worse for some would have been a deal that effectively replaced OPEC and its six-monthly meetings in Vienna, and put Russia in the driving seat of a larger, more nebulous group, with the Gulf Arab states’ control diluted.

Qatar’s rise as a diplomatic force, financed by the latest big thing in energy markets, liquefied natural gas (LNG), has raised hackles among some Gulf states.

Probably more significantly, Russia’s flexing of its muscles in the Middle East has not made for comfortable viewing for a Saudi regime that has made clear where its international focus lies. That is not Russia. Saudi Arabia’s Deputy Crown Prince Mohammed bin Salman made this evident in an interview with Bloomberg ahead of the April 17 talks, saying: “America is the policeman of the world, not just the Middle East. It is the number one country in the world and we consider ourselves to be the main ally for the US in the Middle East.”

Tellingly for those heading to Qatar, he added: “I don’t believe that the decline in oil prices poses a threat to us.”

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

Electric vehicles: The impact on oil and electricity

Ross McCracken, managing editor of Platts analytical monthly newsletter Energy Economist, has been analyzing global crude markets since 2001. Using this experience, he looks ahead in this post to assess what could be the most profound shock both to global oil and electricity markets in their history: the electrification of road transport.

The number of electric vehicles (EVs) on the world’s roads hit the one million mark in third-quarter 2015 and sales are growing fast. If, and it is still a big if, EVs demonstrate an exponential rate of deployment, similar to solar PV panels, it could have a profound impact on both oil and electricity demand, and by extension the very basis of world primary energy supply.

Recent forecasts have suggested that at a 30% annual growth rate in EV sales would result in as much as 2 million b/d of oil demand being displaced by 2028, while at the same time adding 2,700 TWh to electricity demand globally by 2040.

An EV, which means plug-in hybrid vehicles (PHEVs) and battery-only vehicles (BEVS), uses 0.3 kWh of electricity per mile. So the total electricity demand in a year equals the number of EVs times the number of miles travelled annually times 0.3.

The amount of oil demand displaced in barrels/day equals the number of EVs times the number of miles travelled in a year divided by the average miles per gallon of internal combustion engines (ICE) divided by 365, divided by 42, the number of gallons in a barrel.

As such, the critical variables are the growth in the number of EVs on the road, the evolution of mpg and the number of miles each EV is assumed to travel.

Fuel efficiency is expected to rise in both high and low EV penetration scenarios driven by regulation, from somewhere around 17-24 mpg in 2015 to 45 mpg in 2040. So, although a major variable, there appears to be a rough consensus about its evolution.

The number of miles travelled is more contentious and has a huge impact on the expected outcome. In a recent report by Bloomberg New Energy Finance, the miles travelled per EV is assumed to rise on average from 8,700 a year in 2015 to 22,420 in 2040. BNEF sees all ICE Light Duty Vehicles travelling 23,500 miles a year in 2040.

This huge increase in miles travelled comes about as a result of autonomous driving, ride sharing services and other new mobility business models, according to BNEF. However, it is a big assumption; the trend is in fact down not up. The number of miles driven per car per year in the UK, for example, fell from 9,200 miles in 2002 to 7,900 in 2014, according to the RAC Foundation.

The number of EVs on the road is also open to question. Oil major ExxonMobil – a conservative counterpoint to BNEF’s enthusiasm for all things renewable – sees 50 million EVs on the road by 2040, compared with BNEF’s 400 million. Exxon’s assumption still represents growth in the number of EVs of about 14% a year on average out to 2040. The oil company assumes widespread adoption of conventional hybrids as the most economic option for consumers.

As a result, the range of possible outcomes is huge. If mileage is assumed to be flat then under Exxon’s scenario, oil displaced by EVs in 2040 amounts to a meagre 0.83 million b/d. At the other extreme, if BNEF’s high growth rates/high mileage assumptions are adopted then the figure comes out at a headline grabbing 13 million b/d.

The impact on global electricity demand would be again be minor in Exxon’s scenario, and much larger in BNEF’s at 2,700 TWh in 2040, equivalent to 11.4% of global electricity generation in 2014.

If a compromise is reached – say flat mileage of 11,500 in line with current LDV usage in the US, and BNEF’s high growth rate is adopted – the impact is 6.7 million b/d of oil displaced in 2040 and an additional 1,385 TWh of electricity consumed.

However, even this does not provide the whole picture. BNEF considers only LDVs, but there is a lot more to transport than that – heavy-duty vehicles , trains, planes and ships. Moreover, Exxon says this is where the growth in energy demand for transportation will come from, not from the LDV sector.

Global GDP will double by 2040 based on fairly conservative economic assumptions, so there will be a huge expansion in commercial transport. Exxon does sees electricity and natural gas making inroads, but not sufficiently so to overcome the increase in demand for oil from the growth in commercial transport.

If this part of the forecast proves correct, then the impact on oil demand of higher EV sales, even combined with higher mileage assumptions, could be swallowed up by the overall expansion in transport so that oil use continues to grow. EV growth and fuel efficiency will both retard oil demand, but they do not necessarily mean that oil demand will contract.

EV sales and driving patterns are clearly key variables to watch. As the cost of lithium-ion batteries falls, regulatory support grows and consumer sentiment shifts, they could produce the kind of exponential growth curve that other disruptive clean technologies have shown.

This would provide a new area of electricity demand growth for an industry sorely in need of one, at least in the OECD. It would create a massive amount of storage capacity. And it would put a significant break on oil demand growth. But as to the overall impact, it is better not to leap to conclusions just yet.

A fuller analysis of both the ExxonMobil and BNEF scenarios for the transportation sector is available in the April 1 edition of Energy Economist.

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

Turkish steel shifts gears and futures contracts appear to draft off market uptick

The Turkish long steel supply chain has been reminiscent of one of the more brutal ‘hors catégorie’ Tour de France climbs of late — a surprisingly fast ascent up an alarmingly steep mountainside.

Onlookers can’t quite believe the magnitude of the rise and participants are hanging on for dear life, because once you get dropped it’s a rapid backslide.

Prices of Turkish premium heavy melting scrap I/II (80:20) imports have risen over $100/mt since the start of February, from $177/mt CFR on February 1 to $280/mt CFR April 19, according to Platts market data.

Over the same period Black Sea billet export prices have gained nearly $150/mt, from $243/mt FOB on February 1 to $391/mt FOB April 19.

Such cost rises look almost unthinkable, particularly in a global steel market where the mainstream media’s discourse has focused largely on bad news — problems in the UK amid a whopping and growing global overcapacity being addressed by the OECD, for example.

But the hefty cost increases are being passed off in mills’ product prices; Platts benchmark FOB Turkey rebar assessment has risen from $320.50/mt on February 1 to $477/mt April 19.

Initially higher export offers gained little traction, and mills were supported by the strong domestic activity — domestic activity continues to be good, and large mills are still looking to pass off further cost increases to home buyers.

A lack of competitive alternatives globally has undoubtedly led to these overseas offers being more widely accepted by buyers in the Middle East and US.

China is still present in the export markets, but its offers have moved up at breakneck speed on brisk domestic demand, and undoubtedly a good degree of speculative buying by traders.

While the China Iron & Steel Association is warning rising output — with March production in China up — could curtail the gains, most participants appear more bullish. Stocks are low and the weather is warm, aiding construction and infrastructure spending, they suggest.

The now renowned flower show in Tangshan is undoubtedly filtering into more bullish sentiment, with the potential for supply curbs propping up prices.

Some mills are making as much as Yuan 600-800/mt on their crude steel production, according to sources. At the same time Beijing is pushing hard to achieve its gross domestic product for the year, with some thinking it could announce stimulus measures that may further boost the steel market.

What does the precipitous climb in the Turkish market mean? Well, for one, the London Metal Exchange is having some success with its embryonic rebar and scrap futures contracts. The scrap contract traded 15,330 mt in March, or 1,533 lots, while rebar traded 2,480 mt, or 248 lots.

Neither number looks huge if you’re trying to hedge a large vessel, but all contracts have to start somewhere, and both have curves going out over a year with market makers and liquidity providers submitting numbers daily.

One market maker suggests the LME’s “aggressive” traveling and meeting of banks and end-users has broadened participation in the contracts, alongside recent volatility.

“As someone who has been on the trading and physical side, it is starting to look like the physical side is opening up to participation in these type of instruments,” the source said.

Phillip Price, head of market risk management and derivatives trading at Stemcor, also believes mills and merchants are starting to trade the scrap contract.

“Particularly encouraging is increased activity in intramonth spreads, which can be considered a sign of a contract that is being utilized by participants in the physical supply chain such as mills and merchants. Anecdotally, there are a number of mills now actively trading the contract as well as several ferrous scrap suppliers and a number of traders,” he said.

Scrap liquidity is spreading along the curve with usage from a variety of stakeholders looking to manage exposure to price volatility, he added.

“The timing is optimal, particularly given the very rapid price increases we have seen across the segment over the past few months and many physical operators are understandably looking to protect themselves from the risk that prices will retrace their recent gains,” Price concluded.

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