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The Eastern Mediterranean Basin showing promise for oil, gas: Fuel for Thought

Ask an oceanographer about the Eastern Mediterranean Basin, and he might mention a sea-floor dotted with mud volcanoes spewing gas and sometimes oil into the benthic environment.

Ask a geologist, and she may wax lyrical about sediment columns up to 12 km thick, generously capped by “evaporite,” i.e. dirty rock salt.

Both sets of observations have led to speculation that the entire region bounded on three sides by the politically fractious arc of Greece, Turkey, Syria, Lebanon, Israel and Egypt may be a cache for gigantic oil and gas deposits trapped in generous formations of porous carbonate rock beneath impermeable salt.

That theory is coming up trumps following a series of massive sub-salt gas strikes since 2007 offshore Israel, Cyprus and Egypt.

They culminated late August when Eni discovered the Zohr gas field, offshore Egypt’s Nile Delta, which had such a thick pay zone that the company had no qualms about issuing an initial resource estimate of 30 trillion cubic feet of gas, equivalent to about 5.5 billion barrels of oil.

Immediately following the announcement, Egyptian and company officials huddled to sketch out an accelerated development scheme, aiming to deliver on Egyptian president Abdel-Fatah el-Sisi’s promise to end Egypt’s troublesome domestic gas shortages.

There is also hope large oil deposits lurk beneath Mediterranean salt, especially in the north of its eastern basin, where oil seeps from mud volcanoes have been noted.

The US Geological Survey first assessed an Eastern Mediterranean area known as the Levant Basin, extending from Egypt in the south to Turkey in the north, in 2010, estimating its mean undiscovered, technically recoverable resources at 122 tcf of gas and 1.7 billion barrels of oil. However, there was upside potential for as much as 227 tcf of gas and 3.8 billion barrels of oil.

Perhaps because of the potential for oil discoveries as well as gas, a May 2013 move by Lebanon’s Ministry of Energy and Water to launch the country’s first licensing round for offshore exploration attracted considerable interest, with 12 companies being pre-qualified to bid including international heavyweights ExxonMobil, Chevron, Shell and Total, and regional specialists Eni and Repsol. But the Lebanese cabinet delayed issuing decrees delineating offshore blocks and has so far failed to provide a model exploration and production agreement.

Nothing further has been heard about the proposed Lebanese licensing round since the extended bid deadline of August 14, 2014, passed just as international oil prices began a steep descent from which they have not recovered.

The new era of low oil prices has seen international oil companies slash spending while taking pains to direct what remains of their exploration budgets towards opportunities in regions that could pay off with major discoveries, and where political and logistic barriers to development are low.

Politics hinder oil development, majors focus on natural gas

The unexplored waters offshore Lebanon could still attract attention under the first criterion, but not the second, given the country’s dismal track record in recent decades of government mismanagement of resources along with deeply embedded political tensions between neighbors in the entire northeastern Mediterranean region. Those include especially intractable disputes such as Lebanon’s with Israel, and Turkey’s with Greece over Cyprus, which have left many of the region’s maritime international borders in dispute.

Instead, international oil companies now seem to have turned their attention to the altogether gassier prospects offshore Egypt. In October, BP, Eni and Total between them snapped up three new EGAS offshore concessions. One license, in which BP has a 100% stake, is for a large area immediately southwest of Eni’s Shark Block, on which Zohr is located.

Edison and Petroceltic are poring over 3-D seismic data from Egypt’s promising North Thekah deepwater Mediterranean block, awarded by EGAS in 2013, planning where to drill the first well.
For the moment, gas exploration in the south seems the safer proposition, especially with potential markets to Egypt’s north and south.

Ironically, there is now a distinct possibility that large volumes of Egyptian gas could in future find their way to Saudi oil fields for injection into mature reservoirs that have lost their oomph. In the long term, Riyadh’s ability to continue with its current policy of pumping up the kingdom’s crude output to protect market share could be heavily dependent on further sub-salt gas discoveries off Egypt’s Mediterranean coast. — Tamsin Carlisle

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

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Twice as nice: Could London gold groups join forces for the greater good?

The possibility of the London Bullion Market Association and World Gold Council collaborating more closely to promote the development of London gold trading seemed less of an alien concept this week than before, with some saying it would be in the best interests of London’s financial sector for the two to join forces.

There has been talk in the market since the launch of a WGC initiative with five banks, still not publicly announced but well known in the market, followed by the LBMA’s “request for information,” that the two may collaborate. The WGC declined to comment.

The WGC represents the miners, thus firmly on the sell side, while the LBMA represents a variety of market counterparts, mainly refiners, and acts as a proxy regulator in an age of increasing audit trails.

The LBMA now owns the intellectual property of the London Gold, Silver, Platinum and Palladium Prices — the refined and digitized rebirth of the old telephone “fixing” processes or price discovery/benchmark.

Both entities in reality are in the game of selling gold, with the LBMA overseeing the good delivery list, another form of benchmark for gold bar standards.

One senior market source said that the best result for the market would be for the two to join to signify that London is working as one moving part towards evolution.

“The US has COMEX, China has the SGE, why would London want to be fragmented?” he said.

The five banks said to be working with the WGC are ICBC/Standard Bank, Societe Generale, Citigroup, Goldman Sachs and Morgan Stanley. The banks declined to comment.

The fear from the industry appears to be that whatever the WGC are proposing will be in its financial interests rather than in the interests of the actual London bullion market.

“They will be in it for the money,” said one trader.

“Regulators want everything moved to an exchange, London isn’t like that. It’s over the counter; interbank, bilateral. Why don’t the regulators look to hire more people from the industry who knows what is needed?” the trader added.

The big problem appears to still be that the market itself doesn’t know what it wants.

Still, a banker said there was no way he’d move into regulation, no matter how much it paid.

“I’ve heard it’s so dull,” he said.

The main reason for all of the change is the increasing governance of the markets aimed at improving both traceability and accountability.

Ross Norman, CEO of bullion broker and information provider Sharps Pixley, said via email: “Where it would make sense is in so far as each addresses a completely different constituency within the bullion market; the miners at the WGC and the professional market, refiners and others at the LBMA. On the other hand, they each have very different modus operandi and cultures and I could see difficulties in bridging that gap.”

Others suggested the same, that perhaps where the clashes would come from would be inside each organization.

Some sources close to the situation firmly believe such a partnership will never happen.

“I just don’t know if it would work with the personalities involved,” another source said.

Still, a strategist was more positive on the benefits, saying “the WGC has offices the ground in Asia. It could expand the LBMA’s reach.”

A trader agreed: “It makes sense for them to join forces, but whether or not it will happen is the $64,000 question.”

The LBMA is due to update the market November 16, although this is likely to be a simple outline of respondents rather than a glimpse at the future of the market.

Those widely touted to be interested are CME Group, the London Metal Exchange, ICE and a handful of technology companies including EBS [part of brokerage ICAP], Autilla, itBit and Trioptima.

The LBMA and the companies declined to comment.

Overall the market seems still seems divided on the winner of a tie-up between the LBMA and WGC, although more voices are starting to suggest that at least it would prove London is on a steady footing in whatever changes take place.

An LBMA/WGC merger “is the best answer to send a message to the global market,” said one source.

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

The pig and the python: How American refineries are dealing with the oil glut

Record US crude oil inventory levels in 2015 reminds us of a pig crossing paths with a python. The pig is consumed by the snake, bulging in the reptile’s stomach as it goes through the digestive process, and is a handy parable for oil markets.
In 2015 US refineries took unprecedented bites out of the US crude oil glut that was largely the result of higher domestic production levels. But while these python-like refineries have increasingly been built to take a more variable diet, the pigs are getting larger and possibly outgrowing the refineries’ ability to digest the upcoming portions.
rayborn-python-barrelIf we follow the path of the American oil python as it chomps down on the 2015 crude glut, we’re left with questions about what it means for 2016. Will the fat oil glut prove too big for the mighty refinery python? Or will the refining sector just end up with a New Year’s hangover and a bad case of indigestion?
Assessing the prey
The reticulated python of Southeast Asia is known to swallow its prey whole after squeezing the life out of it. However, before starting the swallowing process, the python must wait for the right opportunity to ambush its prey, wrap around it and clench hard.
The refinery python found easy prey in 2015. US crude oil production has grown so much that it is higher than the rest of the global incremental growth combined. Total US crude stocks reached record highs in the first quarter of 2015, resulting in record refinery utilization levels. In just the PADD III region along the US Gulf Coast, year-to-date crude oil stocks jumped 19% compared to year-ago levels to stand at 230 million barrels – or 27% higher than the five-year average.
r-l-crude-stocks
For the American refiner, the rising production and lower prices came as a feast as they managed to squeeze out proportional superior refining netback margins. Netback margins for LLS and Mars in the US Gulf Coast doubled year-on-year when analyzed as a percentage of the crude’s outright value.
r-l-refinery-netback-margins
To make a comparison, after lean years of hunting for mangy rodents and the occasional stray cat, the python stumbled on a porker practically asking to be devoured. So the python obliged as US refineries took more crude volumes into their daily diet. Refinery inputs of crude in PADD III are up 10% when compared to 2010 and 7% higher than the five-year average.
rayborn-pig-python
r-l-refinery-inputs
The big question for many in the oil industry this summer was whether the 2015 catch was actually a pig or something more fierce and destructive – like this alligator swallowed by a python in Florida.
Swallowing the pig
The 2015 crude supply is shaping up to be a formidable feast thus far, and although the python has become quite effective at digesting the meal, the food is piling up. PADD III crude oil stocks during the fourth quarter are 29% higher than year-ago levels and are on the way to beat the 2015 record highs. At a modest 13% growth, we could expect crude stocks in PADD III to reach 280 million barrels by the second quarter of 2016.
r-l-stocks-growth
Although the crude glut reached a record high in Q2 2015, it has not translated into a comparative refined products glut. Combined refined products stocks in the US Gulf Coast reached 275 million barrels during Q2 2015, and although it is significant, it represents just 5% more than the five-year average and it is actually marginally less than 2010 levels. So what gives? Where did the pig go?
r-l-refined-stocks

Make way for a bigger snake
US refined products exports in 2015 have more than doubled since 2009 and are 8% higher compared to year-ago levels. But crude oil stocks continue to build.
rayborn-python
The good news for the American economy is that both US refiners and drivers have increased their capacity to consume in 2015.
“Luckily, the python appears to be getting fatter, with total US refining capacity expected to grow another 300,000 b/d year-on-year in 2016,” said Tony Starkey, manager of energy analysis at Platts unit Bentek Energy.
US gasoline demand went from strong to stronger in 2015, as consumers leapt on lower gasoline and diesel prices and purchased larger vehicles. Refined products demand growth also appears strong in the world’s key growth regions: India and China.
“The real question is whether demand can continue to grow at the breakneck speed at which it did in 2015, or was this largely a one-off boost due in large part to the elastic demand for oil?” Starkey said.
It appears that US consumers are not the only ones paying attention to prices at the pump. Global investors are putting the brakes on capital spending that would otherwise bring additional crude volumes online.
If we see less crude oil on the market in 2016 and continued strong demand growth, we may see the market draw closer to a new supply-demand balance. The fat python may be here to stay.

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

India is looking for its economic rainbow through thick smog

Delhi is choking again. Levels of PM2.5 — fine particulate matter in the air known to cause heart and lung diseases — routinely swing between the “unhealthy” and “hazardous” ranges on the Air Quality Index, with the measurement spiking to an eye-popping 999 on November 27.
An estimated 24 million residents of Delhi and its surrounding areas in the “National Capital Region” are clothed in a perennial haze through the winter months, breathing a toxic mixture of dust, construction dust, smoke from agricultural stubble being burnt in the nearby states, and vehicle exhaust.
Chennai, a state capital in the south, is sometimes worse than Delhi, thanks to petrochemical works, car factories, and coal-burning power stations spewing pollutants into the air.
Doctors are reporting a sharp rise in respiratory illnesses, especially the chronic obstructive pulmonary disease, in which patients’ airways are blocked by the soot and carbon particles they have inhaled.
Prime Minister Narendra Modi, heading into the COP21 climate talks in Paris, has argued for the “advanced countries” to assume greater responsibility in reducing emissions.
“We are striving to meet the aspirations of 1.25 billion people, 300 million more of whom will soon have access to modern sources of energy while 90 million gain running water,” he wrote in a Financial Times op-ed piece Nov 30.
“Justice demands that, with what little carbon we can still safely burn, developing countries are allowed to grow,” he asserted.
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Invoking Mahatma Gandhi’s advice, the country’s cultural heritage, ancient texts, sacred groves and community forests, the prime minister sought to assure that Indians are pre-disposed to being environment-friendly.
If only history and ancient culture could comfort the coughing, wheezing, gasping millions, or the children in Delhi and its neighborhood who will never regain their full lung capacity.
A country deserves to use all the tools available to it to drive economic growth, create jobs and prosperity, and importantly, meet the “aspirations” of its people. But the endgame has to be providing quality of life.
India’s cities and towns are piling cars and two-wheelers on already congested roads at double-digit growth rates — a dubious achievement for the users that spend ever-increasing hours on their daily commutes. And there is more poison in the air for anyone not in the comfort of an air-conditioned car on those roads.
Modi wants to provide electricity to the 300 million in the country still living without it. But if coal is going to be the only or even the predominant fuel to achieve that, he may need to provide face masks to millions more and ask them to accept donning them outdoors as a way of life.
Sure, India’s per capita carbon dioxide emissions, at 1.6 mt per person in 2012, are among the lowest compared with 16.4 mt per person in the US and 7.1 mt in China. The country’s renewable energy program and ambitions to achieve a third of installed electricity generation capacity based on solar, wind and water by 2030, is widely cited and lauded.
What is lamentable and should be unacceptable — to Modi and to the 24 million NCR residents — is Delhi topping the WHO’s list of the world’s most polluted cities. And even more tragically, for India to be home to 13 of the world’s 20 most polluted cities.
Pollution in India is pervasive, across air, water and land. Of the three, air pollution is arguably the most insidious and inescapable killer.
It’s ironic, but what Modi is arguing for on the world stage is India’s right to become the world’s factory and sprint its way to stronger economic growth on compromised lungs.

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

Capex cuts: the road to rebalance or rebound? — Fuel for Thought

The supply response of US shale output to lower oil prices has garnered more than its fair share of news headlines over the last year.
Where the collapse of US drilling rates have been straightforward to track, the longer term consequences of more conventional, bigger-ticket spending cutbacks has been tougher to gauge. Outside shale, the much longer lead times and investment cycles of projects means the fallout of upstream cuts now — while no less real — is less tangible.
With low prices sapping investment dollars in new sources of supply, the scene is perhaps being set for a potential future price rebound rather than a sustained rebalancing of market fundamentals.
Oil producers have certainly been digging deep to cut their capital spending in a hectic bid to future-proof balance sheets from thinning cash flows projections. And the numbers have been stacking up.
Industry wide upstream spending is down 20% this year, according to the IEA and spending by the supermajors alone in 2015 is down by $22 billion, BP calculates.
But the headline capex cuts should not be mistaken for a proportional drop in activity levels — as part of the reduction is explained by falling costs. Since the oil price dive, the industry has become — understandably — fixated on capital efficiency and technology gains. Companies are doing more with less so the read across from outright spending to future production is not a straight line.
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According energy investment bank Tudor Pickering Holt, some 150 oil and gas projects have been delayed or cancelled globally over the last 18 months, jeopardizing a combined 13 million b/d of future oil production. The bank believes the deferred projects — which exclude US shale — hold some 125 billion barrels of oil equivalent of resources, of which 60% are liquids and the rest gas.
Given average lead times and production lives of non-shale projects, the timing of the production impact would likely be felt from around 2020 for a period of 10 to 20 years, according to TPH’s Anish Kapadia.
Oil will still flow, but the question is: when?
But the deferrals don’t mean the reserves will stay in the ground. Many represent a re-phasing of investment, pushing fresh supply into future when price do recover.
“A bunch of projects will still go ahead, but some of the 13 million b/d will be pushed to the right in terms of timing,” Kapadia said. “A lot of these are price dependent — many struggled at $80-100/b, but costs and breakevens will come down and they could come back into play at a lower price.”
Kapadia sees ExxonMobil as most exposed to deferred projects in terms of reserves and production. Having deferred volumes equivalent to 60% of its proven reserves, ExxonMobil has effectively sidelined some 2.5 million boe/d of future production capacity from 25 projects, the bank calculates.
The IEA last month predicted that Russia, Brazil and Canada would bear the brunt of the medium-term supply hit, revising downwards it estimate of non-OPEC output in 2020 by 1.1 million b/d.
So how does all this stack up for oil market balances in the coming years and is the market facing an acute price rebound at the end of the decade?
Were it not for a slowdown in global economic growth, the expected demand boost from lower oil prices over the same period would certainly result in a sharply tighter market.
The IEA’s new long term energy outlook predicts a tipping point from 2020 when years of stellar non-OPEC oil supply growth is effectively thrown into reverse. Non-OPEC supply is expected to top out at 55 million b/d in 2020 before shrinking by 2.1 million b/d over the following decade.
Over the same period, world crude oil demand will grow by almost twice as much to 100 million b/d, the IEA believes, with the balance of supply thrown over to OPEC producers.
But the oil market downturn has accompanied more pedestrian assumptions of global economic growth. A year ago, the IEA saw both world oil demand and non-OPEC supplies above the current projections. The difference now is that upstream spending cuts today means OPEC will enjoy a bigger slice of the market in the future. For many, that switch of fortunes alone could stoke bullish sentiment over the oil price recovery. — Robert Perkins

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

Australian biofuel use to plummet despite Queensland ethanol mandate

A decision by the Queensland government to mandate the use of ethanol in regular unleaded gasoline sold in the state may provide a small uptick in demand for the blendstock. But it will not put a dent in a forecast crash in Australia’s overall use of biofuels, mainly expected due to falling biodiesel imports.

The parliament of Queensland, in Australia’s northeast, passed legislation on December 1 mandating that ethanol make up 3% of regular gasoline sales in the state from July 1, 2017, rising to 4% on July 1, 2018. The Liquid Fuel Supply (Ethanol and Other Biofuels Mandate) Amendment Act 2015 also requires biodiesel and renewable diesel to make up 0.5% of total diesel sales in Queensland from mid-2017.

The ethanol mandate goes further than the 2% proposed under the bill which went to parliament, but the implementation time frame has been delayed by a year to enable consumers and fuel retailers time to prepare for the change. The government is also currently conducting public consultation over options to increase the mandates going forward.

“In practical terms, the mandate will require E10 to make up 30% of regular petrol sales in Queensland in 2017,” said the state’s Minister for Energy and Water Supply Mark Bailey.

Queensland is currently Australia’s third-largest gasoline market by state, with total sales of 3,852,481 kiloliters in the year to June 30, 2015, according to figures from the Office of the Chief Economist in the federal Department of Industry, Innovation and Science. Sales of regular unleaded gasoline in the state were 2,509,598 kl, with sales of ethanol-blended gasoline, or E10, recorded at 376,887 kl.

Based on the government’s figures and assuming consumption remains steady, Queensland’s demand for fuel grade ethanol would rise by around 75,000 kl when the mandate is implemented in 2017, and again to 100,000 kl in 2018.

Queensland currently has two ethanol plants, one operated by United Petroleum at Dalby and a smaller facility operated by Wilmar at Sarina. Dalby and Sarina have nameplate capacities of 90,000 kl/year and 60,000 kl/year respectively.

According to a recent report by APAC Biofuel Consultants, prepared for the Queensland Department of Energy and Water Supply, the two plants are operating at only around 85%, for a total of about 128,000 kl/year. In addition, APAC assumed United Petroleum was supplying around 40,000 kl/year of ethanol to its interstate operations, leaving Queensland’s total supply currently at around 88,000 kl/year and sufficient to meet the 3% mandate.

The national market is also supplied by Manildra Group’s 300,000 kl/year ethanol facility at Bomaderry in Queensland’s neighboring east coast state of New South Wales.

Queensland’s initial bio-based diesel mandate is also expected to be met by existing producers. Queensland’s consumption of diesel over the period from the 2011-2012 financial year to 2014-2015 was 6,500,000 kl, APAC estimated.

Installed biodiesel and hydrotreated vegetable oil capacity at nine plants in Australia reached 555,000 kl/year in 2009, the consultancy said. There are currently, however, only three biodiesel plants with nameplate capacity of about 110,000 kl/year operating across the country, and these are producing just 70,000 kl/year, APAC estimated.

In a recent report from APAC, the consultancy estimated Australia’s consumption of fuel grade ethanol in the 2014-2015 financial year at 246 ML, down 4.6% from the previous year and 23% lower than its peak of 319,000 kl in 2010-2011. Consumption of biodiesel was 164,000 kl and renewable diesel was 278,000 kl for the year, which in aggregate was up 445% since 2010-2011.

APAC estimated that Australia’s demand for biofuels rose 38% year on year in 2014-2015 to 688,000 kl, driven for the second year in a row by record imports of subsidized bio-based diesel.

But this high level of aggregate demand is set to be short-lived due to lackluster motorist enthusiasm for E10 gasoline and the mid-2015 introduction of excise on bio-based diesel imports, which has reduced Australia’s intake to a trickle, the consultancy said.

“We estimate biofuel demand in Australia next year will revert to pre-2010 levels of less than 360,000 kl,” APAC Joint Chief Executive Officer Mike Cochran said. “This will be mainly driven by the expected sharp decline in biodiesel imports, no significant growth in domestic biodiesel production and maybe a similar up take of ethanol-blended petrol in the lead up to the implementation of the Queensland mandate.”

New South Wales is the only other Australian state with an ethanol blending mandate, but demand for the biofuel is on the wane there as drivers switch away from E10 unleaded gasoline to other grades.

Under New South Wales’ Biofuels Act 2007, the state’s mandate for ethanol is 6% of all gasoline grades and the mandate for biodiesel is 2%. The Act has provisions for exemptions, however, and the targets have not yet been met, with ethanol currently comprising around 2.9-3% of all gasoline sales and 5% of regular unleaded sales, Cochran told Platts.

New South Wales is Australia’s largest consumer of gasoline, with total sales of 5,812,483 kl in 2014-2015, including 1,649,754 kl of regular unleaded and 1,727,201 kl of E10, the government’s figures showed. Victoria, which does not have any biofuels mandates, posted total gasoline sales in the last financial year of 4,772,701 kl, including 3,585,401 kl of regular unleaded and 89,865 kl of E10.

Sales of diesel in New South Wales in 2014-2015 totaled 4,736,568 kl, according to the government’s figures. Diesel sales in Queensland for the year were 6,312,523 kl.

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

Ticket to ride: Energy outlooks and the few who benefit

If you’ve been involved in any conversations about energy in 2015, there’s very much a sense the industry is gritting its teeth and just trying to get through this period of sustained low prices. And if you’ve looked at any forecasts about prices, supply, demand and production into the near future, it’s clear why there’s a prevailing sense of grim determination.

The Platts Global Energy Outlook Forum was held today in New York, and while there was still a feeling of caution about what the future will bring, there were also glimmers of hope for growing energy consumption to support producers. Well, glimmers of hope for some countries, anyhow.

The recent OPEC meeting in Vienna and the United Nations-sponsored climate talks in Paris (you can see some headlines here) have thrown the spotlight on a few countries that have the most sway on the future of energy. The various forum panelists and speakers added to that view.

The forum, in its ninth year, drew about 150 attendees and preceded the 17th annual Platts Global Energy Awards program. The year’s title was “Money Talks: Shifting Energy Landscape Calls New Players.”

Paul Sheard, executive vice president and chief economist at McGraw Hill Financial, spoke at length about China and India as two counties crucial in determining the future of energy. When economists talk about outlook, it can quickly devolve into a list of worries, he said, when a more appropriate response is to look at likely outcomes.

It’s likely that China will continue to see its growth slow, he said. Many, especially in the energy industry, had hoped that China would be a continued source of growing consumption long into the future, but it’s no longer going to be as big of a consumer as previously thought.

Seven or eight years ago there was discussion of whether China or India would be that powerhouse of growth, and the stage is now set for India to provide some hope for the energy industry. The country’s demographics are positive, it’s at an earlier stage of economic development with lots of growth ahead, and there’s good hope for political reforms to support consumption, Sheard said.

But while China’s role as a consumer-savior may be changing, there’s a new place for it to take a leading role when it comes to climate change, said Helima Croft, global head of commodity strategy at RBC Capital Markets. At the same time, India’s role takes on a more double-edged quality.

In talking with US officials, Croft said she learned that the US sees cooperation on climate change as one of the best ways to work with China. The choking smog that envelops Beijing and other cities is recognized as a national security risk, she said, and the country is committed to tackling it. That challenge would involve changing the economy from being based on industry/infrastructure (which in turn buoyed consumption) to a more consumer/service economy.

But India, she said, is in the position of wanting as much energy as possible, regardless of commodity, to lift its population. And that, in turn, means that curbing climate effects is not as high on the list of priorities, she said. (Platts’ Vandana Hari talked of India’s own smog problem earlier this week.)

Besides India and China, the US will also continue to have a position of power when it comes to energy. John Kingston, president of the McGraw Hill Financial Global Institute (and former editor of The Barrel), opened the forum and mentioned the link between emissions and economics, seen in the US’ case in the natural gas revolution displacing coal. Later, he spoke with Sheard about how oil is not as stimulative to the US economy as it used to be; the US’ success with shale is part of the reason why oil prices are so low.

But that doesn’t mean the US is hindered. Even with restrictions on US crude oil exports — panelist Wouter van Kempen, chairman, president and CEO of DCP Midstream, called it a “complete missed opportunity” — the US is in a power position in part due to quibbling within OPEC and economic pressure on some members.

For example, Croft pointed out that subsidy reforms in various countries, including the United Arab Emirates and Saudi Arabia, could influence energy consumption and more. Saudi Arabia’s population expects cheap or free and abundant energy, she said, and there have been contentious moves to try to cut down on domestic demand in order to preserve the country’s hefty exports.

Then there are the OPEC members that want production cuts to boost oil prices.

The various panelists touched on many, many more topics, ranging from more straight economics to borderline inside-baseball energy talk. But it was clear that while the energy industry has been on a bit of a roller coaster over the past year or so, there have been some who have – and still can – enjoy the ride.

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

Russia-Turkey wheat trade up in the air as war of words continues

Diplomatic fallout between Moscow and Ankara has dragged on all week, following the shooting down of a Russian jet by the Turkish air force. Business between the two has been put on hold temporarily as emotions and uncertainty have come to replace the long-standing trading relationship between the two countries.
Talk at the moment surrounds a time-tested Russian policy of hurting its enemies economically with agricultural imports. Russia’s food inspection watchdog is currently targeting Turkish pomegranates and cucumbers imported into Russia. These apparently random phytosanitary issues have a tendency appear at the most convenient of times, having been used in the past to stop Georgian mineral water, Moldovan wine, Ukrainian chocolate and – most recently – European cheese from entering Russia during periods of geopolitical tension.
A ban on imports of Turkish fruits and vegetables is ready to become official policy. A list is currently being drawn up and approved by the government, Deputy Prime Minister Arkady Dvorkovich said on Monday. Whether this goes the other way and Russian exports to Turkey will be limited in the coming weeks remains to be seen. It would be big news if it did. Russia sold over 4 million mt of wheat to Turkey in the previous marketing year, making it the single largest destination for Russian wheat.
The early signs last week were not positive. Russian customs reportedly stopped three vessels from setting sail from Yeisk to Turkey last week despite the lack of official government guidance. As other Azov Sea ports were reportedly operating as normal despite the tensions, it should be assumed that someone in Yeisk opted to take matters into their own hands. Given Russian port authorities history of selective (and sometimes over-zealous) enforcement, this should not come entirely as a surprise.
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Turkish authorities, meanwhile, were accused of halting Russian-flagged vessels in the Bosporus. Ostensibly this was for routine checks on vessels over a certain age, but did not stop rumors that Turkey would shut the Dardanelles to Russian traffic on the grounds of the 1936 Montreux Convention. While some in the market were busy dusting off their history books, heavy traffic in the Sea of Marmara and foggy conditions were probably more likely to blame and only added to this week’s confusion.
Looking at the longer-term impact of this issue, Russian farmers, traders and shippers will struggle as they are forced to look for alternative market for their supplies. Suppliers have already been sounding out the Southern and Eastern Mediterranean as well as North Africa for potential buyers, but the market for coaster sellers is not as big or well-developed there. Furthermore, the annual shutdown of the Kavkaz transhipment due to poor weather will only compound the impact on small vessels.
The milling industry in Turkey would also suffer. Turkish millers need alternative supplies to Russian wheat, and are particularly in need of a high-protein content to blend with local reserves. Typically buying Russia’s high-quality, low-cost wheat on a hand-to-mouth basis, any supplies that they have will now be depleting currently and a restock will have to happen eventually.
Who could help? The Ukrainian government and its grain industry have graciously volunteered to step in and sell its produce and act as a guarantor of Turkish food security. However, there are notable quality issues that cannot be overcome. Bulgarian and Romanian wheat has been touted as a possibility, although again the same problem exists, along with concerns about remaining volumes after a hot, dry year.
One of the more interesting options that Turkish suppliers have apparently been sounding out this week is the Baltic Sea. This is a potential solution, but it would require a significant rethink of the way in which the buy side conducts its business.
First, Baltic wheat – while of sufficiently high quality – is much more expensive than its Russian equivalent. Latvian or Lithuanian 12.5% protein wheat for January shipment is currently in the region of $196/mt FOB Klaipeda. Similar quality Russian wheat can be picked up for the same delivery period at $194/mt on a CIF Marmara basis, when the two sides choose to trade with each other. In order to make up for this difference, additional capital will have to be found somewhere in the first place. Higher flour costs, meanwhile, could in time push Turkey’s East African downstream flour market into the hands of alternative Middle Eastern producers in the Gulf States.
Second, the Russian deliveries take place on coaster vessels, while Baltic wheat is typically sold on the much larger handysize. The difference between buying 3,000 mt at a time and 30,000 mt is significant and would require the additional infrastructure to handle and store these deliveries. This creates an additional intermediary step in the market that would raise costs for buyers and most likely outweigh any positive impact of millers spreading their risk between each other as they pool their procurement policies.
All in all, it is probably better for the grains industry if both sides settle their differences as both sides need each other. Indeed, by Tuesday morning it was already apparent that the diplomatic standoff had got too much for some in the industry, as four coaster vessels were heard trading for December and January shipment.
This could be the beginning of the end, as the industry decides it does not want to play out politicians’ battles and instead choose to focus on the things that they are good at. What happens next, however, is probably more likely to be decided in Moscow and Ankara than in Krasnodar and Istanbul.

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

Yes, Virginia, there is a turnaround for the steel sector

Once the US Thanksgiving holiday passes it is never too soon to summon the Christmas spirit. The American steel industry, suffering persistently low prices, high inventories and weak demand, could use a Christmas boost right about now. The following is reprinted from the late American Steel Review, based on the famous 1897 editorial reply “Yes, Virginia, there is a Santa Claus.”

Yes, Virginia, there is a turnaround

Dear editor,

I am a young professional in the American steel industry and cannot believe the market will ever rebound. Some of my friends say there is no turnaround, but my papa, a long-time steel executive, says, “If you see it in The American Steel Review, it’s so.” Please tell me the truth, will there be a turnaround for the steel industry?

— Virginia O’Magarac

Virginia, your friends are wrong. They have been affected by the skepticism of a skeptical age and do not believe what they cannot see.

Yes, Virginia, there is a turnaround. It exists as certainly as money and conspicuous consumption and Hummers exist, and you know that they abound and give to your life its highest beauty and joy.

Alas! How dreary would be the world if there were no turnaround! It would be as dreary as if there were no low-priced slabs from Russia. There would be no childlike recycling, no hot-rolling, no tension-leveling to make tolerable this existence. We should have no enjoyment, except in aluminum beer cans and titanium dental implants. The eternal light with which consumers fill the world would be extinguished.

You might get your papa to hire outside contractors to watch all the blast furnaces on Christmas Eve to catch the turnaround, but even if you did, what would that prove?

Nobody sees a turnaround, but that is no sign that there is no turnaround. The most real things in the world are those that neither importers nor exporters can see.

Nobody can conceive or imagine all the wonders there are unseen and unseeable in the marketplace.

No turnaround! Thank God it lives and lives forever! A thousand years from now, Virginia, nay, 10 times 10,000 years from now, it will continue to make glad the heart of the steel sector.

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

Keeping the hope for more offshore power afloat with wind turbines

The evolution of floating wind turbines mirrors almost exactly that of offshore oil exploration and production structures. Norwegian oil company Statoil’s decision to build the first floating wind farm represents a carbon risk hedge in an area in which it can deploy its considerable offshore expertise. If costs can be reduced, floating wind farms would hugely expand the exploitable wind resource. Ross McCracken, managing editor of Platts’ Energy Economist, explains.

Wind energy is developing a new avenue of expansion, one which should hugely increase the technically, and possibly economically, exploitable wind resource. Wind is going further offshore.

The problem to date has been that further offshore means deeper water and bigger foundations, raising costs, but the industry needs to move in precisely the opposite direction and reduce costs. However, the oil and gas industry has already confronted and resolved this dilemma, moved from fixed platforms to semi-submersibles and then, particularly in the Gulf of Mexico, to spars.

These are huge structures, which use a central, floating, ballasted cylinder to provide stability. The Gulf of Mexico now hosts some 52 permanent deepwater structures in water depths of between 300 to 2,500 meters.

This technology is being applied to offshore wind. Norwegian oil company Statoil is to build a 30 MW floating wind farm off Scotland, using a spar structure, while the WindFloat consortium plans a 25 MW farm off Portugal using a semi-submersible design. Both are based on successful demonstration projects, which used ‘off the shelf’ turbines of 2.3 MW and 2.0 MW respectively. The larger planned farms will use 5-6 MW turbines and will be the first floating wind farms in the world. Completion is expected in 2017/18.

Scaling up turbine size reduces costs, but floating wind turbines have additional potential for cost reduction. Production and installation of the substructure of a conventional offshore wind turbine represents up to 20% of the total cost. Floating wind turbines can be fully constructed onshore and in sheltered conditions, which should facilitate factory line production and assembly. Towing out to site fully assembled reduces offshore operations and allows for the turbine to be brought back to shore for maintenance if required.

Given the expectation that wind turbine size will continue rising to at least 10 MW, offshore wind has considerable cost reduction potential on top of the gains already made. Moreover, floating turbine technology would allow wind farms to be sited in water depths of between 50 and 226 meters, compared to the current limitation of grounded substructures of 40-50 meters. So – potentially at least – lower costs and more sites, suggesting wind energy has a lot more to give.

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