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Live in New Orleans, it’s the National Ethanol Conference!

One of my absolute favorite conferences that I attend every year is the National Ethanol Conference put on by the Renewable Fuels Association, this year running from Feb. 15-17.

They’re always loaded with fiery speaker sessions and passionate speeches on issues both benefiting and plaguing the US ethanol industry.

This year, in my fourth National Ethanol Conference to attend, I’ll be speaking as part of a panel on “High Octane Fuels: Economic & Environmental Benefits,” on Wednesday morning from 8:45-10 a.m. So if you’re at the conference, please be sure to stop by and say hi.

My presentation will focus on ethanol’s bare-knuckled fight against competing octane boosters in this upside-down oil price climate. I’ve already had one guy tell me that session will be “too early” for him, given that we’re in one of America’s most notorious party cities.

To that, I told him, “Come on, man, Fat Tuesday was last week. New Orleans is back to being on its best behavior now.”

Take that how you will, but being from nearby Houston, New Orleans is a city that’s very near and dear to me, and I’m thrilled to be here along with the industry’s best and brightest.

The networking that goes on at the NEC is always fascinating to me, with traders, brokers, producers and analysts all converging to share insight and strategy. If you’ve never been, I strongly, strongly endorse it.

If you are here, please be sure to seek out your friends from Platts. I think we have more than a dozen representatives here, a far cry from the two of us who attended my first NEC in Las Vegas back in 2013.

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

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98 is the number to remember for US gasoline in the 2020s

Gasoline and ethanol are joined at the hip. They’re like lamb and mint. Macklemore and Ryan Lewis. Frodo and Gollum.
And nope, you are not going to get me to say which one is Gollum.
What I will say is that I, as a gasoline editor, do not feel like the enemy here (as some have suggested) at the National Ethanol Conference in New Orleans, where Platts is one of dozens of sponsors and where the big talk this week is how to get octane of gasoline up near 100 at the pump. (You know octane from the little yellow sticker that says “R+M” on it. You probably buy gasoline at 87, 89, 91, 92 or 93 octane.)
Octane helps your engine resist knock, the tiny explosions happening nowhere near where they are supposed to happen in your car. (1) Knock, knock. (2) Who’s there? (3) Engine. (4) Engine who? (5) This isn’t a joke. It really is your engine. Start buying the right gasoline.
Anyway, I’m just here for the octane. Researchers from Ford and the US Department of Energy and a longtime consultant on fuel economy talked Tuesday morning at the Hyatt Regency about the march toward higher-octane gasoline and the cars that will burn them. Also on the table: how much of that gasoline will be comprised of ethanol beyond the 10% seen in most US markets today.

Deep thoughts needed.
“Some deep thought is needed on flex-fuel vehicles and higher octane,” said Dave Hirshfeld of the two-person MathPro Inc. energy consulting shop in Washington, D.C.
Ethanol cares about this because ethanol, at 113 octane, is a great way to get your octane level higher. It’s the double-shot latte of the gasoline blend. But our biofuels analyst — Jordan Godwin, the guy who asked me if I felt like the enemy — said ethanol’s contribution to fuel economy is a bit sketchy. That is for another blog post and points to a broad issue that Godwin told me this morning that not many here in New Orleans are talking about.
The consensus at the panel is that 98 octane is the best target for US gasoline, and Hirshfeld said it would take about eight years to get there if there is political willpower to get it done. The next president no doubt will have something to say.
Gasoline at 98 octane probably would cost 15 cents/gal more than gasoline at 92 octane, researchers said.
Tom Leone, Ford automotive fuels researcher and the most optimistic member of Tuesday’s three-person panel, said he foresees a day when 98 octane gasoline is the US standard, like 87 octane is today for regular gasoline. He said Ford is interested in building cars that use the gasoline of the people, as it were — the most widely available fuel.
“We can deliver a vehicle that runs on any kind of fuel. But we need to know what that fuel will be,” he said.
Beyond 98 octane gasoline lies the “octane frontier,” Hirshfeld said. Those gasolines would require more and more ethanol and likely would not be viable in the market.
Leone said premium gasoline today, the fuel at 91 octane and up, is more of a marketing concept than an economic need. Buying premium gasoline delivers 1% to 2% better fuel economy but that gasoline typically costs 10% more, Leone said. Few are willing to pay that beyond owners of sports cars and luxury sedans.
So what next? Getting the various interests in the octane debate to agree may be as complicated as, say, organizing a nude opera.
Outlandish ideas are likely be proposed. Leone said one rejected technology involved a car where the driver had to fill two tanks with different gasolines. And fuel standards will draw political scrutiny.
“No one likes to be regulated,” Leone said.
But he said there are “societal gains” to be found in higher-octane gasolines, particularly in fuel economy. “It is hard to see market forces alone getting us there,” he said.

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

The Bakken oil production decline officially begins

For months, analysts have said that reports of the death of the Bakken oil boom have been greatly exaggerated.

Despite the historic collapse in oil prices and North Dakota’s rig count falling to levels not seen since 2009, producers have largely maintained steady supply levels as they employed better technology in the most promising geology.

While production wasn’t nearing 2 million b/d as some statewide officials had dreamed of a year earlier, it was holding stable in a range of about 1.16 million b/d to 1.21 million b/d throughout much of last year and even increased from one month to the next five times throughout the year.

When monthly production did fall off, it was incremental and often blamed on secondary factors, like flaring reduction targets or oil conditioning rules.

But the long-awaited drop in Bakken production may have officially begun, as data released by North Dakota’s Department of Mineral Resources this week shows.

Daily oil production averaged just over 1.15 million b/d in December, down 29,506 b/d, or 2.5%, from the previous month. It marks the lowest daily production level in the state since August 2014 and the first real downturn in statewide oil supply caused by the persistent dip in prices.

“This looks like it’s a real number, based on real activity,” said Lynn Helms, the state’s top oil and gas regulator.

The mantra for North Dakota oil producers has become “lower for longer” as operators brace for oil prices which may make drilling uneconomic in nearly every part of the Bakken play, Helms said.

Helms this week released quarterly breakeven numbers which show that only two North Dakota counties, Dunn and McLean, remain economic to drill amid current prices. Dunn, where the state estimates breakeven prices average $22/b, had seven active rigs Wednesday, while McLean, where breakevens average $25/b, had just one.

McKenzie County, which leads the state with 20 active rigs, has an average breakeven of $31/b. The statewide breakeven average is $40/b. (We considered the question of how low prices can go in the Bakken last summer in an episode of Capitol Crude: The US Oil Policy Podcast.)

While Helms said that while he expects statewide production to remain above 1 million b/d throughout early 2017, maintaining that level will require WTI spot prices to average about $45/b. This is possible, according to US Energy Information Administration projections, which show WTI averaging about $37.59/b this year, but climbing to an average of $50/b next year.

But there’s much uncertainty in those projections, according to Howard Gruenspecht, EIA’s deputy administrator.

The EIA actually forecasts a range of prices, between $20/b to over $100/b by the end of 2017, due to a variety of uncertain factors such as social unrest in oil dependent countries, a dramatic OPEC move, a rise in unplanned outages or Iran exceeding export expectations.

“There’s a lot of reasons that prices could be higher, there’s some reasons prices could be lower,” Gruenspecht said during a Center for Strategic and International Studies event this week.

Still, the EIA’s production forecast echoes those in North Dakota.

The EIA expects US crude production to fall from an average of 9.43 million b/d in 2015 to 8.69 million b/d this year and fall further to an average of 8.46 million b/d in 2017, according to the agency’s most recent Short-Term Energy Outlook.

While the yearly average will be lower next year, the EIA sees production bottoming out in September 2016 at 8.31 million b/d, falling from 9.04 million b/d this month and representing a steep 730,000 b/d drop over seven months.

The forecast shows that the EIA believes that the US oil renaissance clearly peaked in April of 2015 when production averaged 9.69 million b/d, but also that producers may be nearing a steady, long-term supply level.

In North Dakota, where the number of drilling permits continues to fall and the number of inactive wells continues to grow substantially, producers remain pessimistic in the near term.

But there is some more long-term optimism, Helms said, as venture capitalists and hedge funds have begun to buy up Bakken assets. Nearly 700 wells were in the process of being transferred from one operator to another, Helms said.

“They think this is a fantastic purchasing opportunity,” he said.

Helms said only time will tell if that translates into a supply rebound or “lower for longer” for even longer.

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

Ethanol and the race to higher octane standards in the US: Fuel for Thought

With the US likely to raise the gasoline octane standard in the next decade or so to achieve greenhouse-gas emissions regulations and fuel efficiency targets, the domestic ethanol industry is promoting its product as the most cost-effective and environmentally friendly way to meet those higher requirements.

In fact, that was the main thrust of the Renewable Fuels Association’s National Ethanol Conference in New Orleans last week.

While the conference in recent years has focused primarily on the regulatory uncertainty surrounding the US biofuels blending mandate, this year’s stressed the need to look beyond that statute for growth.

And one way the RFA aims to do that is to highlight ethanol’s octane benefits, given its price and environmental advantages to petroleum-based additives, such as alkylate and reformate.

“The world is octane short, and with a blending octane rating of 113, ethanol offers more engine knock resistance per dollar than any other gasoline additive on the planet,” RFA President Bob Dinneen said in his state of the industry address.

The current standard for most of the US is 87 octane for regular gasoline. The higher the octane, the lower the engine “knock,” or misfiring of the gasoline within the engine, improving efficiency and lowering emissions.

In tandem with raising the octane of gasoline, automakers could redesign their engines to improve their compression ratio to further enhance efficiency.

But significant challenges remain to simply blending more ethanol into the US gasoline pool to raise its octane.

For one, vehicle engines would have to be redesigned to tolerate the more corrosive higher ethanol blends.

While many automakers have begun to warranty their vehicles for E15 — a 15% blend of ethanol with gasoline — experts say blends of E25 or E30 would likely be necessary to meet the higher octane standard.

Ethanol also has a higher Reid Vapor Pressure than some other blendstocks, which makes it more challenging to meet the Environmental Protection Agency’s summer gasoline specifications.

On the other hand, using reformate or alkylate to boost octane would require refineries to invest significantly in their capacity to produce those blendstocks, which are significantly more expensive than gasoline.

Valero, Marathon Petroleum and other US refiners have already announced plans to increase alkylation production to take advantage of strong demand and sizable margins.

Platts has assessed alkylate FOB Houston as high as 38 cents/gal above Gulf Coast conventional pipeline gasoline in recent days, while reformate FOB Houston has been assessed as high as 65 cents above Gulf Coast gasoline.

Chicago Argo ethanol, meanwhile, has traded about 43 cents/gal above CBOB gasoline recently. But the Argo-CBOB spread has been volatile, with ethanol spending most of 2015 at a discount to gasoline.

Tom Leone, a technical expert on powertrain evaluation and analysis with Ford Motor Company, said so far there has been a lack of consensus among automakers, refiners, fuel distributors and government and standards organizations on which pathway to follow.

Bumps in the ethanol road

“The transition will be difficult,” he said. “To get the biggest benefits, the engines need to be optimized to take advantage of the high octane fuel. Whether it’s higher ethanol blends or increasing octane at the refiner level in E10, there are challenges to both approaches. There are investments required on both sides. It’s not an obvious choice for us.”

Count John Eichenberger, executive director of the Fuels Institute, as a skeptic that higher ethanol blends can be the solution to raising octane.

“30% ethanol will be a problem,” he said. “If [the new fuel] is restricted to new vehicles, there’s not going to be sufficient demand for retailers to put it in. The question is, what is that threshold?”

Whatever the solution to the higher octane problem, it will almost certainly be a lengthy transition process. The switchover from leaded to unleaded gasoline took 12 years before leaded gasoline was fully phased out in the US.

The RFA is hoping to get an early edge on the process.

Dinneen noted that Europe has a standard of 95 research octane number, or RON, which is a different calculation than the US uses but is nonetheless higher than the US’ standard.

He said the RFA would push US regulators to adopt that European standard. Once the new regulation is adopted, ethanol would have to compete in the marketplace.

“A higher octane fuel would enable the auto industry to increase engine compression to improve fuel economy and performance,” Dinneen said. “In a competitive octane environment, everybody wins.”

–Herman Wang in Washington

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

The Disunited Kingdom and what it could mean for commodities

The United Kingdom’s In/Out referendum on continued membership of the European Union on June 23 may serve as a welcome distraction from the interminable circus of a campaign that precedes every US presidential election, with wall-to-wall coverage throughout the world, but it may also have some significant and unexpected consequences for the British economy and the goods it creates, including metal products.

Sterling fell dramatically on Monday, once it became clear over the weekend that the ruling Conservative Party is as split as it was in the 1990s under Prime Minister John Major. Major referred to the so-called Euro Sceptics within his ranks back then as “bastards” and it was the fault line through the middle of the party over Europe that contributed significantly to it losing the general election of 1997 by a landslide and the ascendancy of Tony Blair’s New Labour into power.

But the fall of the pound could prove to be a mixed blessing for the UK economy in making exports of its manufactured goods more competitive on international markets, including elsewhere in the EU and also in the US. The EU and the US are the UK’s main trading partners.

The downside is that the weakness of sterling will make it more expensive for UK manufacturers to import raw materials. But that downside may be limited, given China’s ability to flood the world with more steel and aluminium than we know what to do with.

The weakness of sterling, if sustained, may also prove to be a boost to the UK financial services sector — a pillar of the UK economy. Legal fees and investment banking fees from law firms and investment banks based in London are likely to become a lot more competitive compared with the fees charged by their counterparts in New York, for instance, for any company considering an acquisition, merger or an IPO.

Given the general climate of international financial and economic uncertainty, an IPO or an acquisition may not be too high on the agendas of many companies, but competitive costs of financial services in London may help encourage such activity at a time when it would otherwise be highly unlikely.

Given the complete unreliability of the opinion polls in last year’s referendum in Scotland on whether it would remain part of the United Kingdom, it is reasonable to say the likely outcome of the EU membership referendum is a total crapshoot.

What happens if the referendum results in a “leave” vote? Will the UK automatically become a member of the World Trade Organization, and will its goods sold in the EU and elsewhere be treated fairly, or will they be subject to hefty tariffs? Will a UK outside of the EU automatically be considered a part of the European Free Trade Association again, preserving its tariff-free, free market trade status with the European Union and the rights of its citizens who have chosen to live and work in other parts of the EU? Or will those people suddenly find themselves out of work and out of immigration status and be forced to move back to the UK? Likewise, what happens to all those people from other parts of the EU who have chosen to live and work in the UK?

The UK was one of the founding members of EFTA but left it when it became a member of the European Economic Community — a precursor to what is now the EU — in 1973. It is unclear whether the UK would automatically regain EFTA membership, or whether it would be dependent on the four remaining members — Norway, Iceland, Switzerland and Lichtenstein — to vote the UK back in.

There is a parallel to last year’s Scottish referendum, given there are so many unanswered questions from the “leave” campaign, before we even get to issues such as defense, border security, agriculture subsidies, social welfare and the UK’s budget contribution to the EU. Uncertainty, market turbulence and pressure on sterling appear to be the only certainties between now and June 23.

If the UK votes to remain in the EU, sterling and the euro are likely to rise sharply and any benefit manufacturers see on the export markets, or London’s financial services sector sees, will be washed away. If the UK leaves, more uncertainty and sterling weakness is likely, until such time as the UK figures out how to go it alone.

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

Pemex’s balance sheet calls out for investors in oil, gas and power sectors

Pemex, Mexico’s state oil company, is hoping that an infusion of capital from private equity firms and other foreign investors will help it stave off a pressing liquidity crunch.

Pemex, which is going through a number of key reforms, is suffering from not only lower oil and natural gas prices, but also has had to increase its debt to fund outflows for taxes, duties and capital spending, all while seeing a roughly 6.7% year-over-year oil production decline.

The company, which has a new director general and is responsible for providing close to 25% of the Mexican government’s annual budget from its operating cash flow, posted a $10 billion loss in the third quarter 2015, making it the 12th consecutive quarter in which losses were reported. In the first nine months of 2015 the company reported a loss of approximately $19.4 billion.

In a late 2015 ratings action, Moody’s Investors Service said Pemex’s liquidity was “tight.” It said that in 2014 Pemex’s $9.1 billion of cash flow from operating activities “fell well short of covering $15.1 billion in capital spending outlays.”

After noting that Pemex has or will have $11.8 billion of debt come due from the latter part of 2015 into and throughout 2016, while having an estimated $4.5 billion of cash at the end of 2015, Moody’s on Dec. 16 cut Pemex’s global scale senior unsecured rating one notch from A3 to Baa1.

Said Moody’s, “The actions were prompted by Moody’s view that the company’s current weak credit metrics will deteriorate further in the near to medium term

n early January, the Mexico City-based Pemex announced the layoff of as many as 10,000 oil service workers from its total work force of approximately 142,000, a rare thing in heavily unionized Mexico. The move was a cost-cutting measure, and more layoffs could follow.

On Feb. 17, the Mexican Finance Ministry said the government would reduce spending this year by approximately $7.2 billion, or 0.7% of gross domestic product.

Pemex, whose new Director General José Antonio González Anaya holds a Ph.D. in economics from Harvard and served until Feb. 8 as director general of the Mexican Institute of Social Security, is committed to cutting spending by $5.5 billion.

The Pemex investment budget for 2016 is expected to be $17 billion, down from $22.5 billion in 2015 and $26 billion in 2014. For its 2016 budget, Pemex has reportedly used an average Brent crude price of $50/b. For the month of February, Brent has been trading in the $33/b range, while Mexico’s Mayan crude has been trading in the low-$20/b range.

Pemex, which saw its average production fall to 2.266 million b/d in in the third quarter of 2015 compared to 2.429 million b/d in Q3 2014, will thus be more reliant than ever on partnerships with and investments by the foreign private sector as it tries to keep its opening of its oil, natural gas and power sectors on track.

On Monday, President of Mexico Enrique Peña Nieto opened the IHS CERAWeek conference in Houston by assuring the energy-heavy audience that Mexico “will maintain the rhythm of contracts for hydrocarbon extraction” that it started two years ago.

Peña Nieto said he came to Houston to announce that “the fourth call for bids of Round 1 will be issued in the first days of December, which corresponds to deep-water deposits.”

On Tuesday, the Pemex chief González Anaya said at the same meeting in Houston that “two years ago there was just one oil company operating in Mexico. Now there are 30 contracts with 30 companies.”

González Anaya said he was headed to New York to further discuss Pemex’s investment needs with Wall Street bankers.

Active private equity and foreign investors

Pemex, which was formed in 1938, has stayed clear of foreign investors for more than 70 years. Over the past 12 months, though, a number of transactions have been announced that reflect a significant break from the past.

One deal announced originally in May 2015 took shape last week. Bankers for the private equity firm KKR launched a $1.35 billion package of three loans and a credit revolver that would fund a sale lease-back agreement that involves an assortment of energy infrastructure assets owned by Pemex.

While KKR declined Monday to identify the assets, it did not dispute earlier press reports that 11 pipelines in Mexico, a set of subsea cables, two non-drilling platforms and one gas compression facility are to be bought by KKR from Pemex and then leased back to the oil company for a 15-year period. At the end of that time, Pemex will buy back the assets from KKR.

Analysts have described the lease-back deal as a way for Pemex to monetize assets and use the proceeds to either pay down debt or reduce its borrowing needs.

Almost a year ago, in March 2015, private equity firm First Reserve and investment management firm BlackRock partnered with a Pemex subsidiary and eventually took a $900 million, 45% stake in the north and south sections of the 446-mile Los Ramones Phase II natural gas pipeline.

Sempra Energy’s Mexico-based subsidiary IEnova offered in July to pay $1.325 billion for Pemex’s 50% stake in the natural gas pipeline joint venture Gasoductos de Chihuahua.

In December, Mexico’s newly configured anti-trust unit, the Federal Economic Competition Commission, delayed the deal after determining that Pemex had not sold a stake in a liquefied petroleum gas pipeline as it had been required by the previous anti-trust agency.

Some who have followed the recent Pemex moves have wondered, however, if the Mexican government’s ultimate intent is to break the company apart and privatize its parts. Given the long anti-foreign bias, that just feels like a step too far.

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

IHS CERAWeek: By dismissing OPEC cut, did Saudi Minister Naimi outline the path to one?

Saudi Oil Minister Ali Al-Naimi this week told a massive Houston crowd that the oil-rich kingdom wasn’t interested in solving the global market’s problems, telling them he saw no point in a coordinated production cut.

While he said no cut, is that what he really meant?

Maybe not.

Many attendees at the IHS CERAWeek conference pointed out that while Naimi said he sees a coordinated cut as an entirely useless endeavor, he didn’t rule it out.

“Perhaps he meant no cut … for now,” said Mohammed bin Hamad Al Rumhi, the oil minister of Oman, a non-OPEC country which has pledged to cut production by as much as 10%, or roughly 100,000 b/d, as long as OPEC members commit to the same in order to rebalance the market.

Echoing the sentiments of several others at CERAWeek, Rumhi said Naimi’s comments leave open the possibility of a production cut at June’s OPEC meeting.

“If circumstances change, this will change,” Jamie Webster, a senior director with IHS Energy, told Platts. “It’s not like this is done and there’s no more discussion.”

In his comments, Naimi dismissed the use of a production cut since there was “less trust” that member countries would comply.

“There is no sense in wasting our time seeking production cuts,” he said.

Webster said this was a reference to compliance issues with a 2008 OPEC production cut. As he seemingly dismissed the purpose of a cut, Naimi backed an agreement to freeze production at January levels, which he called “the beginning of a process.”

Naimi’s comments echo those made Monday by OPEC Secretary General Abdalla Salem El-Badri who called a proposal to freeze production a first step to attempt to counter a global supply glut and low prices and said more steps were likely if the freeze was successful.

“This is a first step to see what we can achieve,” El-Badri said during a CERAWeek press conference. “Maybe if this is successful we can take other steps in the future, I don’t know.”

Analysts said the most likely next step after a coordinated freeze would be a coordinated cut.

Dave Pursell, managing director with Tudor, Pickering, Holt & Co., told Platts that Naimi may have been subtly, but publicly, offering OPEC members a deal: join the agreement to freeze production and Saudi Arabia can talk about a coordinated cut at the June meeting to counter $30/b oil.

“You’ve got to quit adding before you can start subtracting,” Pursell said. “So part of that is [Naimi saying]: ‘You show me you’re not adding, then we can talk about subtracting.’”

Matt Reed, vice president of Foreign Reports, a firm analyzing oil markets and Mideast politics, said Naimi’s comments show that Saudi Arabia is still willing to cut, they just do not want to pursue that path alone.

“Naimi said a cut won’t happen but he was speaking generally, not specifically about Saudi Arabia,” Reed said in an email. “He has good reason to be skeptical about any cuts when the Iranians are promising to make today’s glut worse.”

Iran, which is looking to ramp up production with the end of sanctions, has criticized the pact reached by Russia and Saudi Arabia, the world’s top two oil exporters, and OPEC members Venezuela and Qatar to freeze production at January levels if other key producers did the same.

Reed said the freeze agreement represents an important first step since it shows that the world’s top producers are, at a minimum, focused on solutions to the oil price collapse and global supply glut.

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

The next stage in America’s evolving ethanol landscape targets five countries

2015 was a difficult one for US ethanol producers, prices came down from an eight year high in 2014 to a near-eleven year low in January of 2016. As with any market, when times are hard, it’s essential that players can adapt and evolve to keep business alive. So, eyes turn to export opportunities and to five countries in particular.

Traditionally, once supplies reach around 20 million gallons, cargoes start getting booked. Supplies are currently at around 23 million gallons. With sustained record high production levels putting downwards pressure on domestic prices, at the most recent National Ethanol Conference in New Orleans, US ethanol industry participants were readily eyeing export opportunities to provide the market with a much-needed boost in the form of buyers, and ultimately, revenue.

For both ethanol and biodiesel, rhetoric around the industry has shifted from a nearly one-sided focus on the Environmental Protection Agency (EPA) and Renewable Fuel Standard (RFS) to now touting the benefits of other biofuels. For biodiesel, it was touting its ability to reduce carbon emissions; for ethanol, it’s the benefits for octane-boosting.

The change is due, partly, to the fact that the new blending mandates are in place now, giving some stability and allowing both industries to focus on other aspects. However, the change in sentiment is also due to the fact that both fuels are at a disadvantage economically compared to fossil fuels.

So, as a way to address this evolving landscape, the industry is lining up five countries as key to the US export market: Brazil, the Philippines, China, India and Mexico. As the largest buyer of US product, Canada is already a well-established market, requiring less business development.

The big five

Brazil: Conveniently located, Brazil offers the US an export market that can be accessed with relative ease. In 2015, Platts-Kingsman estimated that the US exported around 440.4 million liters of fuel ethanol to Brazil, second in imports of US product behind Canada and a 4% uptick compared with exports to the region in 2014. Participants have described the Brazilian ethanol market as being in a constant state of either “feast or famine.” This supply uncertainty offers the US an opportunity to be the reliable constant supply of fuel into the country and it is one that US producers are looking to capitalize on.

The Philippines: In 2015, the Philippines were the third-largest importer of US fuel ethanol, increasing their buying power by 6% from 2014 and importing around 270.3 million liters. The cost of shipping, easy logistics and good demand in the region make the Philippines an ideal destination for US product. The low cost of shipping to the area is key for sellers; one US producer said that it costs as much to take ethanol from Iowa to Seattle as is does to take product from the West Coast to the Philippines. With such a strongly established trade route, market participants were keen for this to continue over the coming years.

China: Weighing in at No. 4 on the biggest importers of US fuel ethanol in 2015, China was the biggest mover on the list, increasing its imports by an astounding 1994% from 2014. As a country with a rapidly growing population, clamor is building from the widening band of middle classes to lessen the reliance on fossil fuels and improve air quality. Ethanol is seen as an answer to these calls, a positive sign for US exports. But the relationship is not an easy one. Most recently, China launched an anti-dumping probe into US DDGS imports, a by-product of ethanol, which saw imports fall by 9.6% month-on-month in December. The risk-reward premium of sending product all the way to China to potentially have it sit in a dock for an indefinite period of time is high. But when the going’s good, China is a veritable cash-cow of a market for US ethanol.

India: Following his election in 2014, Prime Minister Narendra Modi increased the blending mandate for ethanol in India, moving from E10 in 2015 to E20 by 2017. But in 2015, India’s effective blend rate fell far below the E10 mandate, reaching just 4.34%, and the country lacks the capability to produce sufficient ethanol domestically to meet the requirement. Alongside the blending mandate, at the 2015 COP21 summit, India also announced plans to cut its CO2 emissions per unit of GDP by as much as 35% from 2005 levels by 2035. To do this, India will need external support, and imports, and the US will be a main contributor on both fronts.

Mexico: At only ninth place on the list of importers, Mexico may not come across as an obvious country to focus energies on. But from 2014 to 2015, Mexico increased its buying of US ethanol by 14%, up to 116.2 million liters. The country, much like India, is going through energy reform and will need help to hit its mandates. They too lack the infrastructure to meet ethanol targets and the US is perfectly positioned, both geographically and logistically, to step up to the plate.

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

So demanding: US gasoline marketers zero in on potential future growth areas

You can’t take a practice swing with a 6-iron here at the BPAMA gasoline marketers’ convention in Doral, Florida, without nearly hitting someone who is optimistic about gasoline.

Not crude, mind you. There is plenty of sour feeling about that. But about 450 regional fuel executives have gathered this week at the Trump National golf resort at Doral, with Platts as one of the sponsors of the event. (The attendees will miss the really big show, which happens in a few days when resort namesake Donald Trump is expected as part of his campaign tour.)

Things are funny at the far end of the supply chain. Cheap gasoline has its champions. Sure, profit margins are smaller. But pump prices south of $1.50/gal are seen as a lure to get the folks out to the gasoline station on the way to far-flung adventures. Who knows, maybe it’s even time to take the family to that new Harry Potter thing in California.

And if you buy a frozen-ice slush creation for 99 cents on the way, more power to you. Just keep it off the upholstery, Rusty.

“It’s funny how lower crude is a good thing for us,” BP Fuels Chief Operating Officer Doug Sparkman told about 400 regional “jobbers,” the execs who buy fuel from the majors on the way to getting it into your tank. “There is a good story on the demand side. We don’t see $100/b oil in the near future, but we are bullish on demand.”

Sparkman said growth in US gasoline demand will offset losses to stout fuel economy that will be required in US vehicles in the 2020s and 2030s.

Also boosting demand: a shift to bigger cars

“The US is switching back to SUVs, and drivers are putting their hybrids up for sale, and you can count me as among the people who are happy about that,” Sparkman said.

I thought that statement might need a reality check. Edmunds.com, which tracks vehicle sales, backed Sparkman up. (Edmunds is not at the conference in Doral.)

“The data is very conclusive,” Edmunds analyst Jeremy Acevedo said. “SUV market share is at its highest ever level and our nation’s preference for utilities continues to grow. Hybrids and plug-ins have seen their market share tumble to the lowest levels since 2011. It’s important to note that in this SUV renaissance, the soaring popularity of more efficient compact SUVs are powering the segment to these record levels.”

The one segment of the gasoline market where few are optimistic is premium product: the fuel at 91 octane and up. Many I am talking to here are saying the grade is dead or dying, with a few exceptions. In northern Florida and southern Georgia, I am told that many stations are eliminating premium gasoline. That also means 89 octane is gone at those stations, too, because you can’t have the 89 without the 93. At most fuel pumps, 87 and 93 are mixed just seconds before they reach your car to make 89.

We’ll be preparing a story on this for Platts soon, as well as another story on what I like to call “the unicorn”: the ethanol-free gasoline at 93 octane about which we are hearing of pockets of strong retail demand.

Meanwhile, BP is telling the people who buy its fuel to be ready to hold out longer in an era of cheaper crude, and to keep looking for positives.

“Our view has been ‘lower and longer’ for oil, and now we have revised that to ‘lower and even longer,’” Dan Filo, BP’s Midwest US fuel supply manager, told attendees.

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

Rough seas for dry bulk shipbrokers as commissions tank

It’s carnage out there for the dry bulk shipping market. Anyone and everyone connected to this market are bleeding profusely with freight for moving dry commodities offering negative returns for over a decent period of time now.

While it’s a matter of life and death for the dry bulk shipowners, who are struggling to cover even their operational expenses, the current crisis is pushing shipbrokers to the edge.

Almost gone are the days when shipbrokers used to pride themselves as “CEOs,” a pun-intended acronym in the shipping world for “chief entertainment officer.”

With incomes from commissions drying up due to rock-bottom freight levels, which is just three digits in some cases, shipbrokers are now asking for a lump sum amount as commission, instead of a percentage-based brokerage rate from shipowners.

So is the entertainment spree by the shipbrokers for their clients, that’s almost non-existent these days.

Shipbrokers are a vital cog in the commercial shipping market. They not only help match a shipowner’s vessel with a charterer’s cargo, but also provide their clients a wide range of market intelligence and constructive advice.

The massive slowdown in the dry bulk market has brought in a do-or-die situation for the shipbrokers. They are earning a pittance from commissions received for fixing ships.

The practice of asking a lump sum amount as commission has been prevalent for a few months now with a broker commission based on 1.25% of the total freight bill offering a paltry sum as brokerage, according to a few shipowners and ship-operators.

While this is not a shipping industry norm yet, it is practiced on a case-by-case basis and depends largely on the relationship between the shipbrokers and the shipowner as well as the trade route.

“Sometimes when we fix a short voyage, we offer to pay on a lump sum basis. So far, only seeing it on voluntary basis, but wouldn’t be a surprised if brokers start insisting for a minimum lump sum going forward,” said a shipowner source.

The fact is that the volume of business that brokers are doing is shrinking.

“Owners are mostly looking to place their own vessels for own cargoes,” said a shipowner, adding that there was very little margin to pass on to anyone in this market.

A shipbroker summed up the current situation by saying that the dry bulk shipping industry will change after the present crisis not because of ship charterers or the shipowners, but due to the slim chances of shipbrokers surviving the depressed market conditions.

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