The Distillation Column

A weekly blog by Robert Sharp looking at refinery market dynamics

About This Blog

This blog is about where the space between chemicals and refining economics intersect. It gives deeper insight into the US gasoline, blendstock and feedstock markets – and relates them to chemicals. Robert Sharp, the editor of PetroChem Wire's Daily Refinery Focus, is the author of this blog. He brings more than 35 years of experience covering the refined products markets. Robert can be reached at Robert@petrochemwire.com or (713) 828-2145.

 

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Refinery reacts to bunker fuel changes, puts coker on hold

HOUSTON, August 30, 2018 (PCW) -- An unexpected implication of new bunker fuel regulations regulating sulfur levels developed this week, as Gunvor decided to forgo a new coker at its 88,000 b/d Rotterdam refinery.

Instead, the refinery will keep making what will likely end up as bunker fuel, rather than make a massive investment in a coker, which would cost $500 million or more.

The shipping industry is unsure what of several paths it could take to meet the new regulations with options ranging from installing onboard sulfur scrubbers or mixing heavier fuels with lower sulfur lighter fuels. Until answers are found, it may be the wiser course for a refiner to do nothing--for now

In the past refiners have concentrated on making more light ends, such as gasoline and diesel. The delayed coker planned by Gunvor would have made mostly diesel, as well as naphtha, market sources said, and petroleum coke, a coal-like product that is used in the production of cement, anodes for metal manufacturing and even power generation.

Premiums to Bunker

Gasoline and diesel, and even petroleum coke typically trade as a significant premium to heavy bunker fuel, but the price relationships are likely to be radically altered come January 2020. It is likely that bunker fuel – especially low sulfur, but even high sulfur will come close to the price of diesel.

Therefore there is less incentive to build a costly unit.

January 2020 ships on the open seas will be required to burn a fuel with a sulfur content of 0.5% (by weight) instead of the current 3.5%. Inside of 200 miles of the shoreline, they are currently required to burn a 0.1%S fuel.

The ship owners have the option of installing exhaust gas scrubbers, which would allow them to use the current high sulfur bunker fuel. So far only about 3,000 of the existing 70,000 ships in the world are estimated to have installed scrubbers.

Scrubbers Not Favored

Shipping companies such as Maersk and Odfjell have indicated they are not in favor of scrubbers.

The regulations were drawn up by the International Maritime Organization; enforcement in the US will be done by the US Coast Guard. Ship owners face penalties for using non-compliant fuels.

One shipper complained that the compliance burden is on ship owners not refiners; he pointed out that when the US imposed a 10 ppm requirement for US diesel, refiners were required to make it.

“Why not require refiners to supply this fuel?” he asked.

But refiners cannot simply wave a wand and make low sulfur bunkers. In the US especially billions have been spent to turn high sulfur heavy residual oils into light environmentally acceptable products (diesel and gasoline) – using cokers, fluid catalytic crackers, reformers and hydro-treaters.

Those products historically have garnered a significant premium to bunker fuel. On Aug. 29, diesel in the Gulf Coast was assessed by the PetroChem Wire Daily Refinery Focus at $2.21/gal, or $92/bbl; IFO 380 cst bunker was put at $434/mt or about $68/bbl.

January 2020 Changes

January 2020 this could all change, however. By most views, to make the new fuel will require sellers to blend a significant volume of low sulfur diesel (10 ppm, or 0.01%S) into some heavier material at the very least.

Just using today’s economics this means that the bunker fuel will have some kind of a percentage of fuel in it that is one-third more expensive than current bunker fuel.

But it gets better. This fuel, if it is blended with 30 API diesel will have less BTUs than current bunker fuel. Heavy oil has about 150,000 BTUs gallon while diesel is about 139,000 BTUs/gallon, so the lighter fuel will deliver less “gas mileage” to the ship.

So it will cost more to make (and presumably cost more to buy), but be less valuable to the buyer.

Even if the heavy oil and diesel were the same price, ship owners would prefer the heavy high sulfur (if they have a scrubber) because it has more BTUs, and therefore gets better “gas mileage.”

Spec Confusion

But it gets better still. Refiners with different configurations in different ports will likely make different products that can meet a bunker fuel specifications but are not necessarily fungible. One marketer said this may not be acceptable to ships owners who fear that different fuels, while on specification, may require some engine settings to be adjusted, or worse yet, create engine problems.

In the end, some say, ship owners could opt for using diesel, which has a specification that is consistent around the world. Today they would pay another third higher, but what will happen when diesel demand goes higher?

Prices could go up even more, not just for ships but for trains, trucks and tractors. The commercial world after all, runs on diesel.

But all this is up in the air. The world is frankly unprepared for the new low sulfur world.

It is possible that there may be delays in implementation if the low sulfur fuel is not available in sufficient volume. The IMO is determined to go ahead but, no one really knows.

 

VGO weakens on lower gasoline prices and strong crude runs

HOUSTON, July 23, 2018 (PCW) -- The fall of gasoline and high refinery runs have pushed vacuum gasoil lower in recent weeks, and hurt fluid catalytic cracking margins as well.

“Everybody thought gasoline was going higher and turned up the refineries,” suggested on market source.

VGO is a feedstock that is inputted to an FCC; it produces 70% gasoline and 30% diesel, and a 10% increase in volume. An FCC is often referred to as a major gasoline-producing unit in a complex refinery.

VGO does not trade on an outright basis, but rather as a differential to WTI, which is how it is assessed by the PetroChem Wire Daily Refinery Focus.

In recent months VGO differentials have been up and down, but lower overall. On May 1, VGO was assessed at WTI plus $10/bbl, and rose to a high of $14/bbl on June 19, before falling to $9.75/bbl on July 12.

The VGO differential was assessed $1/bbl higher July 20 at crude plus $11/bbl, but that was because the market changed to trade off September rather than August WTI, and the former settled at $1.22/below the latter, essentially a wash.

FCC Margin Drops

The weakness in VGO is in stark contrast to last year, when the market was strong in the high-gasoline-demand summer. The Focus assessed VGO at crude plus $7.80/bbl on May 1, 2017; it rose to $8.65/bbl on July 19, 2017.

One might think that lower VGO prices – less expensive inputs to a refinery FCC – would result in higher profitability, but the reverse has been the case. The FCC margin is calculated as the value of 70% of the US Gulf Coast gasoline, 30% diesel, plus 10%, and subtracting the outright price of crude.

On May 1, the Focus calculated the FCC margin at $16.26/bbl; on July 19 it fell $3.09/bbl to $13.17/bbl. Again, this is in contrast to 2017, where in the same period margins went from $10.89/bbl to $15.84/bbl, up $4.95/bbl.

So what is the difference between 2018 and 2017?

One reason is weak gasoline, a driver of VGO prices; most (me included) had been predicting strong gasoline (and crude oil) prices for the balance of 2018.

However, gasoline was assessed by the Focus at 200.75 cpg on May 1, and 198.1 cpg on July 19, a drop of 2.65 cpg; however gasoline has been much higher with 209.60 on June 9, a drop of about 9 cpg.

Again, this is the opposite of 2017, when gasoline was 146.50 on May 1 and up about 10 cpg July 19, 156.50 cpg.

The proximate reason for the weakness in gasoline is high production. Early on, most thought gasoline was going higher, so runs were ratcheted up. In fact, per the US Energy Information Administration, for the week ended July 6, domestic production hit a record 10.699 million bbl/day.

Refinery runs as a percentage of capacity have gone up, hitting a high of 97.6% in PADD 3 (USGC) for the weeks of June 22 and June 29 (in 2017 the figures were 93.7% and 95.1%, respectively), and 97.5% nationwide on June 22 (in 2018, 92.5%).

In PADD 2 (the Midwest) on June 1, the inputs to refineries were put at an almost unheard of 101.3%!

Higher Capacity

But total domestic refinery capacity has also gone up; despite the often spoken notion that the US “has not built a new refinery since the 1970s,” total crude distillation capacity is now 4.092 million b/d, up from 4.013 million for January 2018, and 3.957 b/d for January 2017.

So a higher refinery percentage is now compared against a higher overall capacity.

Throw in weakness in crude, and the end of driving season, and you have resultant products’ weakness.

Early in the summer, when the US imposed sanctions against Iran, and when technical problems affected imports from Canada, many expected tightness in crude, but indications of increased production from Saudi Arabia and now Libya coming back on stream have pushed the market lower.

Weaker Gasoline

Now that we have passed July 4, the market looks at October gasoline with a higher RVP, which tends to be less expensive than low-RVP summer grades – the October NYMEX RBOB is 14 cpg below August and 11 cpg below September.

Post Hurricane Harvey, gasoline was somewhat tight, with inventories below the previous year. As of July 13, the EIA showed supplies 4.9 million barrels over last year at the same time. We are long going into the fall when demand slows and it becomes cheaper to make finished gasoline.

Thus, going forward, it is very hard to argue for stronger gasoline prices, and that directly affects VGO.

 

Brent/WTI spread collapses, taking VGO with it

​HOUSTON, June 28, 2018 (PCW) -- The Brent/WTI spread, which had blown out over the past few weeks, came crashing down this week, likely partly the result of a Canadian crude oil infrastructure problem.

Last week, a power outage at the Suncor Synthetic crude facility in Alberta effectively took out about 10% of the country’s exports, or 360,000 b/d of oil, barrels that are directly shipped to Cushing, Ok.

The cutback in crude supply is likely to last through July, market sources said this week

The result is that the Brent/WTI spread which had briefly hit $10/bbl in early June, dropped to under $5/bbl on June 27.

One immediate effect of the tightening Brent/WTI spread was on Vacuum Gasoil.

The US VGO market is in part supplied by Europe, which sells on a Brent-related basis; when the barrels arrive in the US they tend to be sold on a WTI-related basis. The high spread effectively prohibited European VGO from coming to the US Gulf Coast, pushing the market up.

The collapse of the spread has pushed VGO lower; in the past week VGO has fallen $1.50/bbl to WTI plus $12.50/bbl on Wednesday.

During the same period, gasoline in the USGC has shot up about 6 cpg. VGO makes 70% gasoline and 30% diesel plus 10-15% volumetric increase when inputted to a Fluid Catalytic Cracker, so one would think higher gasoline prices would mean stronger VGO.

More RGP

Lower VGO prices might result in increased inputs to FCCs, which, could increase production of refinery grade propylene, a by-product, and significant petrochemical feedstock

In March, the US imported about 3.5 million b/d of crude from Canada. This specific supply issue is likely not yet reflected in the US Energy Information Administration statistics. But the market has note it and responded accordingly.

The government inventory numbers released June 27 showed an already steep drop in domestic crude supplies, 9.9 million barrels, for the week ended June 22.

Part of the reason for the crude draw is the extraordinarily high inputs to refineries, over 97% of capacity in the entire US. In fact, the total crude inputs for the week ending June 22, 17.816 million b/d, was a record.

The other reason for the drop in supply is exports, 3 million b/d for the week ended June 22, also a record. Last year at this time the US exported 528,000 b/d.

Cushing Oil Supplies

Supplies in Cushing itself have started to fall, dropping 2.7 million barrels this week to 32.9 million. This, in that it is the delivery location for the WTI NYMEX contract, has the effect of driving up the benchmark crude in the US.

Only a few weeks ago WTI looked weak in that the deliveries to the Gulf Coast from Cushing were said to be “topped out” because the pipeline capacity for delivery was at its maximum.

A continued draw in Cushing inventories, say to 22 million barrels, might cause severe decreases in the crude delivered to the USGC, one market source said.

 

Strong Brent/WTI spread roils VGO markets

HOUSTON, June 1, 2018 (PCW) -- Vacuum gasoil differentials shot higher this week, and are likely to head higher, not due to any particular supply/demand issue, but because of quirks regarding crude benchmarks.

VGO is a refinery feedstock, which, when inputted to a fluid catalytic cracker, yields 70% gasoline and 30% diesel, and a 10-15% volume yield. It is priced in the US Gulf Coast as a differential to WTI, in Europe vs. Brent.

The fluid catalytic cracker is often referred to as the major gasoline-producing unit at a refinery.

This week the low sulfur VGO market as assessed by the PetroChem Wire Daily Refinery Focus was July WTI plus $13.25/bbl, up $3.50/bbl since May 17, and $3/bbl on the week.

There were no telling supply/demand issues this week. Shell had a FCC go down for turnaround in Convent, La., which would be bearish, but it was planned and it is likely that the company will manage the excess VGO by storing most of it or shipping to its other Gulf Coast refineries; Chevron had brought back and FCC in Pascagoula, a bullish indicator.

The reason for the weakness is the nature of the pricing benchmarks for VGO, and higher crude production that ends up stored in Cushing, Oklahoma. The issue is not so much the level of stocks, but the ability to get the oil out of Cushing to other markets.

The overall crude market is backwardated (prices decline as the year goes forward), meaning owners of oil want to move it and not store it – but the movement capacity is limited.

As mentioned, US VGO is priced off the NYMEX WTI contract; European VGO is priced off Brent.

European Imports

A significant percentage of VGO run in the USGC is imported, from Europe. In fact, historically, US refineries are configured with large FCCs, which require more feedstock (VGO).

The US VGO is priced on the NYMEX contract, whose delivery point is Cushing, not Houston or the Gulf Coast. In recent weeks, high US crude production has pushed the capacity of the pipelines from Cushing to the Gulf Coast to its limits –- we are at the maximum that can be delivered.

One might think that the limits on deliverability would be bullish for crude except that the pricing of the crude (WTI) is based on Cushing; in the current situation, Cushing-based WTI is “landlocked” and therefore is cheap.

One indicator of the situation is the US Energy Information Administration refinery crude oil input rates, as seen in the Weekly Status Report. This showed that Midwest refineries (including Oklahoma) were running at an almost unheard of 100% of capacity.

The Gulf Coast refineries ran at 93.4% of capacity.

During this period Brent – relative to WTI – has gone up. The widely looked at Brent/WTI spread has gone from $5.19/bbl on May 3 to $10.55 on Thursday.

What this means is that a buyer of European VGO buying on a Brent-based differential will be paying a price that is based on a $10.50/bbl spread over WTI – roughly $5/bbl more than they expected to pay early in the month.

At the same time that seller will be offering to the Gulf Coast based on the cheap Cushing based WTI price. An international trader that has bought in Europe would likely hedge his deal by selling Brent crude and buying WTI.

If that happened early in the month the bringer of European VGO would lose money on European “short” and the US “long” position, exactly the opposite of what they would want – the hedge used to protect themselves would cost them on both sides.

Looking for local barrels

In practical terms this means that incremental VGO from Europe is less likely to head to the Gulf Coast; it is not economic to bring it here, to say the least. Buyers will look for local barrels, and push prices higher.

Per the EIA, in 2017 the UGGC imported just under 10 million bbl/m of VGO (“Heavy Gasoil”). Europe is that source of our extra VGO.

Anecdotally, one trader said that the last time the Brent/WTI spread got to $10/bbl, VGO hit $17/bbl over WTI.

The issue is not likely to be resolved any time soon. Crude production is up, but pipeline delivery capacity, while higher, is not adequate. Other ameliorating factors such as friction reducing chemicals in the line and rail delivery are possible, but will not happen fast.

 

Isobutane premium to normal butane widens on alkylate demand, squeeze

Guest column by Samantha Hartke

HOUSTON, May 17, 2018 (PCW) -- Gulf Coast spot isobutane’s premium over normal butane widened to multi-year highs this week, as did the former’s outright price, thanks to strong alkylate demand and equally robust prices.

On May 15, the iso-normal premium stood at 34.25 cpg, levels last seen in January 2012, according to PetroChem Wire prices. On Tuesday and Wednesday as well, isobutane was assessed at 140 cpg, a level last seen in February 2014.

A wide iso-normal spread is not uncommon and tends to appear at the end of the month when book-squaring dynamics come into play. Operational issues, such as an outage at an isomerization unit caused the last major spike in the spread.

This time, the premium began noticeably widening on April 26, when it came in at 10 cpg. About five days prior, an explosion at Valero’s 225,000 b/d Texas City refinery occurred at its 12,000 b/d alkylation unit (isobutane is used as a feedstock in alkylate production). The unit is expected to remain offline for four months.

The explosion came at a time when alkylate prices were aggressively moving higher, on the back of stronger gasoline values and the onset of the summer gasoline blend. Gasoline has increased 44.4 cpg, or 25%, since Jan 1 with the bulk of gains seen in recent weeks as the US opted to withdraw from the Iran nuclear deal. During the same time frame, alkylate values gained 44.2 cpg, or 22.9%.

Since the Texas City refinery explosion, alkylate has risen 16.4 cpg (7.4%) and RBOB gasoline has gained 13.7 cpg (6.6%). Traders have said that since the explosion, other alkylation units have been running harder to compensate for the supply shortfall. In the markets, spot alkylate values have seen stronger bids on a daily basis, with offers nowhere to be seen, suggesting values could only move up.

Adding to the bullish pressure is the onset of the summer gasoline blend, when alkylate becomes the primary blendstock, comprising anywhere between 15-25% of the mix. Other market sources said because of the intense demand, some short positions have gotten squeezed, which has only piled on to the bullish sentiment.

How long this inflated premium will last is unclear at this point, although the forward curves suggest it should not last beyond this month. The May/June isobutane spread is in deep backwardation, moving from a 10 cpg discount to a 30-plus discount over the last few weeks.

 

FCC margins push higher after refinery fire

Tom Sosnowski also contributed to this report

HOUSTON, May 3, 2018 (PCW) -- Fluid catalytic cracking margins in the US Gulf Coast hit $16.26 on Tuesday, the highest level since Hurricane Harvey, and well above last year at this time. On Wednesday, the margin fell about $1.00/bbl to $15.25/bbl, still well above last year’s $11.32/bbl.

The reasons the margins are so strong is the perfect storm of tight gasoline and diesel in the US and a downed FCC unit at Valero's Texas City refinery.

Vacuum gasoil is the feedstock for an FCC, which makes 70% gasoline and 30% diesel, along with a 10-15% volume increase.

VGO trades at a differential (usually a premium) to WTI. Low sulfur VGO was assessed Tuesday at WTI plus $10/bbl; as recently as April 23, the market was crude plus $13.50/bbl.

The fall in VGO prices was a direct result of an incident at a unit adjacent to the 12,000 b/d alkylation unit at the 225,000 b/d Valero Texas City refinery. The alkylation unit is expected to be down for four months.

When it became known that the alkylation unit was going to be offline for that length of time, Valero decided to move up an FCC turnaround previously scheduled for fall, letting the 85,000 b/d FCC remain down.

The alkylation unit uses a by-product of FCC operation, refinery grade proplyene, to make alkylate. Part of the decision to take down the FCC may have been related to the refinery’s wish not to make excess RGP.

The FCC was likely running at 80-85% of capacity, which suggest the Valero refinery is now producing about 70,000 b/d of VGO, quite a lot. Typically refiners with multiple refineries will try to move excess barrels to other company-owned refineries, and, while this is no doubt the case now, market sources report Valero selling into the spot market.

The offers by the company quickly pushed the market to the $10/bbl over WTI level; Wednesday it recovered to $10.50/bbl.

At the same time, however, gasoline held firm.

The FCC margin is calculated by taking the outright cost of VGO (WTI plus the differential) and comparing it to the value of the products made (70% gasoline and 30% diesel).

So, essentially, the cost of the feedstock has fallen, and the value of the products went up.

Gasoline has increased about 14 cpg since April 2 to 200.50 cpg on Wednesday, while diesel has improved 15 cpg to 208.15.

This column predicted stronger FCC margins in a February blog. The current spike was unexpected, really. Whether or not this level can be sustained is the question.

Valero could cut crude runs at its Texas City refinery, thus producing less VGO and taking some pressure off the market. Or it could cut runs at its other refineries in Texas and Louisiana so those refineries would make less VGO, and be able to run more in FCCs at those plants.

 

FCC profitability pushes higher with strong gasoline

HOUSTON, April 13, 2018 (PCW) -- Fluid Catalytic Cracker margins have pushed higher in recent weeks, spurred by relatively cheap vacuum gasoil and strong gasoline prices.

An FCC takes in VGO and cracks it, producing 70% gasoline and 30% diesel, plus a 10-15% volumetric increase.

As recorded by PetroChemWire's Daily Refinery Focus, the FCC margin on April 11 was $13.26/bbl, up from $10.33/bbl one year ago, and from $7.56/bbl on January 2.

VGO trades as a differential to WTI. On April 11, low sulfur VGO was assessed at May WTI plus $12.75/bbl, compared to $9.25/bbl last year and $7.50/bbl on January 2.

So, despite higher feedstock (VGO) prices, margins have increased.

The strength in gasoline is not so surprising, in that lower volatility makes it more expensive to make as we head to summer. Gasoline as assessed by the Focus increased about 24 cpg from January 2 to April 11; in 2017 it actually fell 2 cpg in the same period.

The strength in VGO is at least partially related to overall gasoline demand. Domestic demand as reported by the US Energy Information Administration has been good but not great, averaging about 9.3 million b/d on a four-week average basis, about flat to last year, as listed in the most recent weekly summary on April 10.

Diesel Demand is stable

Diesel demand has been stable as well, 4.1 million b/d vs 4.0 million one year ago, on a four-week average basis, per the EIA.

The difference now is exports, which continue at very high levels. The EIA reported Wednesday that gasoline exports over the past four weeks averaged 885,000 b/d, compared to 625,000 b/d last year at this time.

Diesel exports were stable; on a four-week average, they were about 1.1 million b/d most recently, compared to 1.0 million b/d a year ago.

It should be noted that typically about 80% or more of US finished product exports originate in the Gulf Coast, with the remaining coming from the West Coast and Atlantic Coast.

Exports have become the lifeblood of Gulf Coast refining. Ten years ago the US was a net importer of gasoline, mostly into the Atlantic Coast, but sometimes even to the Gulf Coast; now imports are principally to the Atlantic Coast, from Europe and Canada.

It may seem odd that the US imports and exports gasoline but, in fact, because of the requirement that only US flagged ships can transport products between domestic ports, it is cheaper to ship gasoline from Europe to Boston, than to bring it there from Houston.

Before gasoline exports took off, gasoline's overall demand would decrease in the winter. Now it is undergirded by export demand, mostly to Latin America.

Brent vs WTI

One indicator of export demand is the spread of Brent to WTI. The cheaper WTI is vs Brent, the more it suggests that the US has a production advantage in gasoline and diesel.

The spread has had a long history, with Brent generally $1-2/bbl under WTI for many years. In the Shale era, however, the situation has reversed itself and now WTI is below Brent, encouraging exports of refined products and crude as well.

Brent averaged $6/bbl above WTI – a huge spread – as recently as September 2017. It started coming off in December and averaged a recent low of $3.09/bbl in February.

On April 11, the spread was back up, to $5.36/bbl.

On the whole, sources have suggested that larger WTI discounts vs Brent are a harbinger of strong gasoline prices, and healthy refinery margins.

Demand should remain good, as the economy hums along and exports are strong.

Mexico, the single largest importer of US gasoline, seems to be inclined to import rather than invest in refineries to make gasoline; a wide Brent-WTI spread is also bullish for product exports.

Good profits for refiners?

No less a light than Barron’s, in its March 30 issue, predicted good refinery profitability, especially for Andeavor (formerly Tesoro), which is making an effort to get into the Mexican market.

 

Refiner Dilemma: How to make low-sulfur bunker fuel

(Tom Sosnowski contributed to this article)

HOUSTON, March 2, 2018 (PCW) -- A major change in marine fuels specifications might affect how refineries run in the Gulf Coast and around the world.

The change is in bunker fuel, set to start in 2020, which would require large ships at sea currently burning high sulfur heavy oil, to use a 0.5% sulfur material, just under two years from the rule’s implementation.

This fuel currently does not exist in anywhere near the volume that will be needed; buyers and sellers alike have really no good idea how to manage the situation.

The change is being implemented by the International Maritime Organization, which has been enlisted in the effort to fight climate change. “I wish we had some clarity, really that is what the market wants,” said one heavy oil broker.

Shipowners will no longer be able to use the current 3.5%S bunker fuel, unless they install scrubbers on their current ships, or else burn the lower sulfur barrel.

The 3.5%S by weight measure is 3,500 ppm sulfur; by contrast low sulfur diesel used in the US is 10 ppm.

Right now in the US and Europe, ships can use 3.5%S on the open sea, but are required to burn 0.1% inside 200 miles from shore (an Emissions Control Area in the graph).

The new regulation is a whole new ballgame, however, as worldwide bunker demand is about 22 million b/d. So 22 million b/d of high sulfur fuel has effectively been banned, and is to be replaced by a fuel that is difficult to make.

Large ships for the most part are driven by huge diesel engines, with cylinders as big as 1500 liters, running at 300 rpm. Typical bunker fuel is an 11.5 API fuel, very heavy compared with diesel, which is 30 API.

Bunker fuel is made from heavy parts of the barrel, parts that cannot be turned into higher margin fuels like gasoline, diesel, jet and lubricating oil.

In the US especially, gasoline has always been the priority, motivating refiners to invest in units to maximize gasoline, employing fluid catalytic crackers, reformers, cokers and the like, all resulting in less heavy residual fuel production.

Sticklers for Quality

Bunker fuel is made by blending some of this residual fuel with dog and cat distillates (such as light cycle oil) to make the required specification. While residual fuel has the reputation of being a “black oil” in that some questionable specification barrels might end up in it, in the modern world the engines are high tech, and most ship owners are sticklers about quality.

The options for the ship owner in 2020 will be: install an exhaust scrubber and burn high sulfur fuel; or burn 10 ppm diesel; or burn the 0.5%S bunker fuel

The scrubber option is viable, but expensive and so far only about 4% of the 20,000-plus ships in the world are likely to go that route, according to published reports. It “scrubs” the exhaust which is stored on a ship and then (in a perfect world) disposed of in dedicated tanks on shore.

The diesel option is in a way the easiest, but also the most expensive. Diesel was assessed by PetroChem Wire Daily Refinery Focus on March 1 at $1.85/gal, or $77.70/bbl. or about $16.70/bbl above WTI.

The current price for bunker fuel is about $52.50/bbl, or $18.50/bbl under WTI.

And diesel, being a lighter fuel, has less BTUs and is thus going to give poorer “gas mileage” to the ship.

One option would be to use 0.5%S vacuum gasoil as a basic blendstock for bunkers. VGO, 20-25 API, is fed into a fluid catalytic cracker and yields 70% gasoline and 30% diesel.

Difficult to Take

VGO is currently trading at $11/bbl over WTI. Refiners cringe at the thought of VGO being used as a basis for bunkers. An FCC is a $1 billion dollar investment for a refiner, so not running it would be hard to stomach.

Also, there are compatibility issues if the VGO is from paraffinic crude, and were blended with blendstocks made from aromatic crudes.

The US Gulf Coast consumes about 6 million barrels per month of bunker fuel; refiners input about 8.5 million barrels per day, so diverting some VGO to bunkers does not seem like an impossibility, especially if the price of bunkers rises to the level of VGO (about $10/bbl in the current market).

VGO at a heavier 20-25 API would get better “mileage” at a lower price than diesel.

It seems clear that the cost of shipping goods around the world is going to go higher.

It is possible that the law could be delayed, or phased in, if a solution is not achieved. “Shipping is not going to grind to a halt,” suggested one bunker seller.

 

VGO is cheap, margins poor, but not for long

HOUSTON, February 16, 2018 (PCW) -- Vacuum gasoil differentials have dropped in recent weeks, pushed down despite good winter gasoline demand and exports. This seems likely to end soon, however.

VGO is a refinery feedstock that makes 70% gasoline and 30% diesel when inputted to a fluid catalytic cracker; it trades as a differential to WTI.

Since January 2, VGO has fallen from $15.25/bbl over WTI to $13/bbl on Thursday.

One might think that if the cost of the feedstocks has fallen, the margins would go higher, but in fact the opposite has taken place.

The margin in running an FCC is calculated by comparing the value of the products produced (70 percent gasoline and 30% diesel and comparing it to the cost of the feedstock (crude plus a differential).

Although the FCC margin started the year out on a low note, it was either side of $9/bbl for much of January; Thursday it was $7.18/bbl. One year ago the margin was $12.07/bbl

What this says is that VGO differentials have fallen harder than crude and products.

Several factors, however, suggest that this weakness will be short lived.

For one thing, domestic gasoline demand has been strong. Demand falls during the winter but on that seasonally adjusted basis, it is up 6.5% versus the same period last year (now about 9 million b/d, per the US Energy Information Administration).

Plus, exports are at all-time highs. Based on the EIA four week average, the US in 2017 exported 696,000 b/d of finished gasoline; so far in 2018, the weekly average is 827,000 b/d.

Gasoline stocks are also lagging. The EiA showed that for the week ended February 9 total gasoline stocks had built 3.6 million barrels to 249.1 million, a number that is 10 million under last year.

The largest factor in play, however, is butane. As the market heads to summer, lower levels of butane will be allowed in gasoline. Currently southern grades of gasoline are 13.5 RVP, which drops to 7.8 RVP in April.

Butane is a cheap octane booster but will have to be replaced with more expensive alternatives like alkylate or mixed xylene in the summe. Butane is cheap. On Thursday it was 91 cpg, while alkylate was 203 cpg and MX 277 cpg.

It should be mentioned that alkylate and all blendstocks do not substitute for each other on a one to one basis in finished gasoline, in that they all have different distillations curves, octane and RVP.

Nonetheless, less butane combined with somewhat lower inventories, robust demand in a strong economy and still strong exports, all suggest stronger finished gasoline prices, and a need for incremental production from FCCs, and therefore stronger VGO.

 

Shell FCC decision signals extra refining needed to boost supplies after Harvey.

HOUSTON, November 7, 2017 (PCW) -- Has the gasoline market changed? This page has long argued that cheap shale crude and light naphtha will keep gasoline well supplied and cheap, but anecdotal and statistical information now suggest otherwise.

The latest and most telling news comes from Shell, which, according to market sources, has canceled the long planned retirement of a Fluid Catalytic Cracker at its 235,000 b/d Convent., La., refinery; the unit was to have come down in January.

An FCC is a major gasoline producing unit in any sophisticated refinery (virtually every Gulf Coast refinery has one) . It takes a feed called Vacuum Gasoil and makes (as a rule of thumb) 70% gasoline and 30% diesel.

Cheap Naphtha

In recent years, the profitability of FCCs has declined because in many cases cheap naphtha produced by refining and splitting lighter crudes has been able to be used to make finished gasoline, in effect, creating extra supply cheaper than can be produced by cracking.

Shell will keep the aging cracker running for 4-5 years, sources said, until its retirement.

What has changed?

Hurricane Harvey for one. During the approximately two weeks’ effects of the storms on refining, about 20-25% of US gasoline-producing units were shut.

The effects of the shutdown seem clear, according to the US Energy Information Administration. On August 3, total US gasoline inventories were per the EIA listed at 231.103 million bbls; on September 15 they had dropped to 216.185 million.

During part of this period exports of finished products lagged; no doubt the impulse was to hang onto inventory until it was clear there was no major damage to a refinery (there wasn’t).

At some point one might expect inventories of gasoline to re-build; that has not happened. As of October 27, the EIA showed yet a lower number, 212.849 million bbls, which is 14.294 million below last year during the same period.

Rebuilding Supplies

This likely played into Shell’s decision; it will not be easy to rebuild inventories. Typically, after all, in the about now refineries in the US start to squirrel away gasoline for consumption in the following summer.

Ann FCC margin is calculated by comparing the value of the finished products (70% gasoline plus 30% diesel) minus the cost of the feedstock (typically WTI plus a differential).

As of Monday, the FCC margin as shown by the Petrochemwire Refinery Focus, was $16.05/bbl, compared to $11.74/bbl for the same period last year.

It is not easy to see why margins are up. Since August 1, gasoline (CBOB) in the US Gulf Cost is up about 25 cpg, to 181.84 cpg.

Diesel Stocks

Another driver of the strong market is diesel fuel/heating oil. Stocks on October 27 per the EIA were 128.921 million bbls, 21.6 million below last year. About 20% of the US diesel market is actually heating oil, and the current stocks suggest a cold winter in the Northeast US may strain household budgets.

Much of the heating oil sent to the US is actually imported from Canada, whose refineries loo to Brent rather than WTI as a indication of crude values.

Brent for much of the year was abort $3/bbl over WTI, but is now at a $6/bbl premium, another indication that the international market is in a bullish mode.

 

Refined product shortages from Harvey? Just export less

HOUSTON, September 1, 2017 (PCW) -- The depth and the breadth of Hurricane Harvey’s effects cannot be overestimated or predicted, no doubt.

Consider that in about five days, the storm hit four major refining areas: Corpus Christi, Houston, Port-Arthur-Beaumont and Lake Charles.

What are the odds of that?

By my informal count of major, complex, gasoline producing refineries in the path of Harvey, about 5 million b/d worth of capacity was directly affected at one time or another--28% of the US total capacity.

Incremental Capacity

More important the USGC is really 100% of the domestic incremental capacity. By this I mean that while, say, Chicago has area refineries that supply it, the region needs extra “incremental” barrels to complete the supply. The same is true of many locations, including New Jersey.

There is one huge difference between Harvey and the last hurricanes to hit the US Gulf Coast, Katrina, Rita, and Ike, however.

It's that the US is now a net exporter of products; it was formerly a net importer. This suggests to me that all the US would have to do to avoid shortages of gasoline is to export less and conduct some creative trading to move those barrels to where they're needed.

According to US Energy Information Administration statistics, in the last week of August 2005 (during Hurricane Katrina), the US was a net importer of 2.245 million b/d of petroleum products.

This statistic is an estimate by the EIA; although it includes all finished products, but is mostly gasoline and diesel. The US at the time was a net importer of gasoline (mostly to the US Atlantic Coast, but also even to the US Gulf Coast), and an importer of diesel/heating oil to the USAC.

Net Importer

During Hurricane Ike in September 2008 the US was still a net importer, to the tune of 1.772 million b/d.

All that started to change in the summer of 2011 however, thanks to the shale revolution.

The most recent EIA numbers, for the week ending August 25, show the US to be a net exporter of products, 2.161 million b/d.

The US exports now gasoline all over Mexico, South and Central America, the Caribbean and even sometimes Africa or Australia. We also export diesel to many areas, including Europe.

The US imports gasoline from Europe to the USAC; the Jones Act makes it too expensive to put gasoline on a ship in Houston and take it to New York. Diesel is imported from Canada to the USAC.

So, in a sense, all the US would have to do is export less to keep supplies healthy. Per the EIA, the US had 23.7 days’ worth of gasoline as of Friday, a typical number for this time of year. That way, if a refiner was down or operating at reduced rates, it could buy products from another refiner that was in better operational shape.

We had 229 million total barrels of gasoline (blendstocks and finished gasoline) which is about flat to last year but is 15.7 million barrels over two years ago.

But while Corpus Christi and Houston refineries appear to be ok, it is too early to tell about Beaumont and Port Arthur, or Louisiana, with significant refinery capacity.

Colonial Pipeline

Also the Colonial Pipeline running at reduced rates or shut altogether would create shortages. Places like the upper Atlantic Coast, South and North Carolina, and Georgia could be supplied by gasoline from Europe or Canada (or even the US if the Jones Act is suspended).

Dallas experienced shortage in that the pipeline from the Gulf Coast was shut during the storm, but a separate pipeline has been reversed to allow supplies to flow from Oklahoma.

On Thursday the price of gasoline in Northwest Europe was about $1.80/gal, while the October NYMEX was $1.7791/gal; the Gulf Coast was assessed at $2.0692/gal.

That suggests to me that if a seller owed gasoline to Mexico or Ecuador, they could supply it out of Europe and keep our barrels home, good economics and better public relations.

My guess is that if there are refineries or pipe lines that will be down or affected for an extended period, places on the USAC will be easily supplied from Europe, but places like Atlanta, with no easy supply source other than the Colonial Pipeline, might struggle.

 

Defying octane value, alkylate differentials stagnant as gasoline prices climb

HOUSTON, August 10, 2017 (PCW) -- Gasoline goes up and down (it has been mostly up lately), but one thing seems to be a constant: US Gulf Coast alkylate differentials to gasoline don’t go significantly higher under any circumstance.

Alkylate is a high octane, low RVP, gasoline blendstock, an octane enhancer that is prized for its clean characteristics.

Alkylate Weakness

The weakness in alkylate defies octane value. On July 3 the Gulf Coast 87-93 octane spread for M-grade (conventional) gasoline was a very low 8.75 cpg; by August 9 it rebounded to 18 cpg.

On July 3, alkylate was assessed by PetrochemWire's Refinery Focus at 19 cpg over finished gasoline; on August 9 it hit a very low 12.5 cpg over gasoline.

So even when the octane value goes higher, when one would expect alkylate to go higher, it falls.

The reason for all this is that market dynamics have changed to turn the Gulf Coast from an exporter of alkylate to an importer as well as an exporter (in the form of finished gasoline).

The incremental imports of alkylate to the US Gulf Coast are coming from India, whose 1.24 million b/d Reliance Industries refinery in Jamnagar is the world’s largest.

For the past few years alkylate from Reliance India has been exported mostly to storage in New York Harbor and the Caribbean. The alkylate is then blended into finished gasoline for the US market, and for South American customers as well.

Things have changed, however, as US government records show imports to the Gulf Coast. In May, the most recent information available, the US Energy Information Administration showed India sent 1.017 million barrels of gasoline blendstocks to the US Gulf Coast, of a total of 2.412 million total to the US.

Sea Change

This may be a sea change, market sources said; in May of 2016 none of the gasoline blendstocks from India went into the Gulf Coast.

US alkylate assessesed by PCW is a 92 octane, 5.5 RVP blendstock, with very clean characteristics. The Indian grade is actually better, 94 octane, 4.7 RVP.

The EIA numbers label the imports as “gasoline blendstocks,” but sources said they are alkylate, which the Reliance refinery was configured to export (it has been doing so for several years).

A cursory look at gasoline suggests that alkylate imports to the USGC may become the new normal.

Finished gasoline trades at a discount to the NYMEX RBOB contract, whose delivery point is New York Harbor. Over the past months the Gulf Coast (Houston) market has traded as low as 17 cpg under the NYMEX, but more typically 6-8 cpg under.

Choice of Market

Right now that spread is only 1.5 cpg, meaning the Gulf Coast and East Coast are essentially flat. This suggests that alkylate sellers have their pick of where to go (assuming the alkylate differentials over finished gasoline are similar in the two markets).

Also, one buyer of alkylate has been PDVSA, a company that sellers are wary of due to its lack of money.

Published reports indicated as many as five ships are sitting off the coast of Venezuela with oil of various types to deliver, which will not be delivered unless the sellers get paid.

The point is that some barrels that used to go to NYH or the Caribbean or Venezuela are now headed to the Gulf Coast.

One source pointed out that if alkylate goes to the NYH market, it is likely stuck there; if it comes to the Gulf Coast it can be re-exported as alkylate or as finished gasoline; the USGC is a major exporter of gasoline.

Another angle is that of a Duty Drawback. If a cargo of fuel is imported to the US, the seller pays a 1.25 cpg duty; if that material is re-exported as finished gasoline, the duty (under a US Customs and Border Protection program) is rebated.

Thus the USGC export would have an advantage over the USAC (where gasoline exports are less prevalent).

 

Steep decline in gasoline exports helps keep US prices low

HOUSTON, June 13, 2017 (PCW) -- This blog has argued for months that gasoline is fundamentally weak, and recent prices again confirm this.

Nowhere is this more evident than in the Gulf Coast, where motor fuel prices are falling harder than crude as the market suffers from a steep decline in exports, which are needed to keep inventories under control.

Consider the beginning of the gasoline season, April 3, when the PetroChem Wire Refinery Focus assessed gasoline price was at 166.37 cpg (M2 grade). As of Friday, June 6, it had fallen 19.2 cpg to 144.17 cpg.

In the same April-to-June period front month WTI fell from $50.24/bbl to $45.83/bbl, off $4.41/bbl or 10.5 cpg. Gasoline has fallen almost 9 cents more than crude.

Since June 1 gasoline has fallen about 10 cpg in the Gulf Coast.

Swelling Inventories

The lower prices, however, have not stopped inventories from increasing. Last week, the US Energy Information Administration showed total gasoline stocks at 240.3 million barrels, about 700,000 barrels over last year, but 22.2 million higher than two years ago.

Domestic demand for gasoline is about what it was last year, either side of 9.6 million b/d. Last year gasoline mostly fell throughout the summer, assessed at 152.28 cpg on June 1, to 131.74 on September 1.

So we are in roughly the same inventory positon we were in last year at this time. But now exports, are dropping off.

The reason for the length in gasoline is apparent by looking at the most recent US and Mexico import/export statistics.

Gasoline exports have fallen dramatically in 2017 compared with the latter third of the year in 2016, when those exports had a bullish impact on the Gulf Coast especially.

Monthly exports of US gasoline in March totaled 18.279 million barrels, down from 20.045 in February, 25.119 in January, and 28.750 in December, according to US Energy Information Administration figures.

The monthly export average in 2016 was 19.25 million; in 2015 it was 14.31 million.

About 50% of US exports of gasoline end up in Mexico, per the EIA (most recent numbers are for March).

Mexico took 8.477 million barrels of finished gasoline from the US in March, not much different than the 8.372 million it took in February; however the number in January was 14.072, and in December it was 15.488.

The most recent statistics from Pemex show the country imported 367.4 thousand barrels per day of gasoline in April of this year, down from 502.1 in March, 533.2 in February and 556.0 in January.

Deteriorating Refineries

The average for 2016 was 505.1 b/d, which showed higher levels in the second half of the year, generally attributed to deteriorating refineries and infrastructure in Mexico. Things now have changed.

It's important to note that the numbers shown by Mexico are for all their imports, barrels that could come in theory from anywhere (likely Europe), not just the US. But the figures confirm Mexico is able to get by with fewer gasoline imports.

US refiners need to export to keep inventories under control. For the week ending June 2, the EIA listed gasoline production in the US at 9.934 million b/d, and gasoline demand at 9.317 million b/d, meaning we need to export 617,000 b/d to stay even.

For the same period in 2016 the production was 9.975 million b/d, with demand of 9.568 million, or a 407,000 b/d deficit; in 2015 the numbers were 9.908 million b/d, and 9.600 million b/d, or 308,000 b/d.

The “incremental” demand for US refiners comes from exports. Without them, the US--the Gulf Coast especially--would need to cut refinery runs.

Absent some kind of international calamity, given the flat US demand and the failing exports, it's hard to see how gasoline can go higher. “It is hard to come up with a scenario that would in fact push prices up,” commented one source.

 

Pre-buying alkylate for summer blending an unworkable strategy amid weak octane, gasoline prices

HOUSTON, March 17, 2017 (PCW) -- Alkylate differentials flirted briefly with strength in March, but have headed lower again as gasoline looks weak and octane values have not gone higher.

Alkylate is a 5.5 RVP, 92-93 octane blendstock, prized for its value in blending up octane and lowering volatility (measured in RVP) in summer grades of gasoline; it trades in the US Gulf Coast as a differential to finished 87 octane conventional gasoline (commonly referred to by its Colonial Pipeline moniker, “M grade.”)

Failed Strategy

Historically, gasoline blenders will store alkylate in the winter months, buying it at low differentials versus gasoline, storing it for three to five months and hoping that the differential will rise in late March when alkylate is needed to make lower RVP (historically more expensive) summer grades of gasoline.

This is a strategy that no longer works.

Right now the Gulf Coast benchmark for M grade gasoline is 9 RVP, the summer grade, which will remain the benchmark until fall; winter grades in the South are 13.50 RVP.

In short, the 5.5 RVP alkylate should be near its most valuable annual levels right now. On Thursday, it was assessed by PetroChem Wire at gasoline plus 22 cpg, down from 29 cpg on March 13, which had been its highest of the year; on March 1 the differential was 27 cpg.

To put this in perspective, alkylate in 2015 routinely traded between 35 cpg and 55 cpg over gasoline, even up to 59 cpg. In 2016, however, it seemed stalled at lower differentials, from which it has never really recovered for any extended period.

Also, the underlying price of gasoline has fallen. On February 1, the assessed price of M grade gasoline was 159.10 cpg, by March 1, it was 152.30 cpg, and on Thursday, it fell to 149.67 cpg.

Weak Octane Value

Another factor in alkylate prices is the value of octane, which has also been weak for most of the year. On March 1, the 87-93 spread for conventional gasoline was 14.50 cpg. On Thursday, it was 11 cpg.

In the current refining environment, it is perhaps a question why a refiner would want to make spot alkylate at all. Alkylate is a by-product of fluid catalytic cracking using refinery grade propylene (RGP) as a feedstock, but the value of RGP is higher than alkylate by a long shot, and has been so for months.

These atypical price dynamics have also interestingly occurred during maintenance season, when crude runs are low and FCC maintenance has been high, which should have decreased alkylate production and provided some price support.

Naphtha differential narrows on tight benzene markets

HOUSTON,  February 17, 2017 (PCW) -- US Gulf Coast naphtha differentials, especially heavy naphtha differentials, have narrowed in recent weeks as the market reacted to stronger benzene prices.

On January 3, PetroChem Wire assessed naphtha at 34 cpg under finished gasoline; by February 1 it had strengthened to 15 cpg under gasoline, although it fell to 19 cpg under gasoline as of Thursday.

Naphtha as assessed by PetroChem Wire is a 62 API “full range” barrel, with an Initial Boiling Point of 110F. Although heavy naphtha is not assessed, it is mentioned in the commentary, as a 58 API barrel with a 130F IBP.

Typically, heavier naphtha will produce more benzene when inputted into a catalytic reformer and then run through an aromatics extraction unit.

Widening Spread

The spread between the two grades is typically 3 cpg in favor of the heavy naphtha, which has a better yield on a per gallon basis. The spread has now widened to 7 cents, or perhaps more.

Naphtha is inputted into a catalytic reformer, which yields reformate, a 100 octane, 1 RVP blendstock (assessed by PetroChem Wire as well); reformate can be blended into finished gasoline (if it has a low benzene content), but typically it is inputted into an aromatics extraction unit, which yields benzene, toluene and mixed xylenes, commonly referred to as “BTX.”

In the current market, it is the benzene that garners the most attention. Benzene began its rise in late November. A perfect storm of higher Asian and European prices have curtailed imports to the US, and lower crude inputs to Gulf Coast refiners have likely resulted in less naphtha production as well. Refiners have begun buying naphtha in the spot market rather than making their own from crude).

On November 1, benzene was assessed at $2.17/gal, but by December 1 it had risen to $2.45/gal; at the start of the New Year it was $2.70/gal and by January 24 it was $3.45/gal, its recent high.

It has fallen slightly since, to $3.34/gal on Thursday. Consider that on November 1 front-month WTI settled at $46.67/bbl, and on February 16 it settled at $53.20/bbl, an increase of $6.53/bbl.

In the same time period, benzene went from $2.17/gal to $3.34/gal, up $1.17/gal ($49.14/bbl).

The increased yield of benzene from a reformer would seem to justify the higher price of naphtha, especially heavier grades. In fact heavy naphtha has been sold for input directly into steam cracking as well, not reforming.

“Steam crackers want all the heavy they can get which is quite out of ordinary,” said one seller. -- Robert Sharp

 

Spot normal butane shows strength due to tight supply; could normalize in 2Q

Guest column by Samantha Hartke

HOUSTON, February 9, 2017 (PCW) -- Normal butane has seen tremendous strength in the last few months, rising 29 cpg or nearly 31%, since the beginning of the year to $1.23/gal. It's gained a whopping 58 cpg, or 89%, since mid-September, which is the start of the peak gasoline blending season.

This tremendous strength has resulted in outright spot butane hitting highs last seen in October 2014, according to PetroChem Wire prices, and exhibiting relative strength to crude not seen since 2009.

The reasons for this strength are manifold, but they ultimately paint an extremely tight supply-demand situation.

From a supply standpoint, butane production has been slowing slightly. The most recent EIA production (for November) shows butane production for the 2016 year-to-date at 108.378 million barrels, down from the record high set in 2015 of 111.838 million barrels.

This, however, could be a short-term phenomenon given the recent uptick in crude and spot butane prices, which should incentivize greater NGL recovery levels. Most analysts expect butane production to increase 5-13% through the end of the year and into 2018.

Butane inventory levels are what several market players are eyeing with great interest. November inventory data from the EIA showed stockpiles at 1.275 million barrels, a level not seen since Apr (1.165 million barrels). In contrast, year-ago levels were at 1.696 million barrels and the five-year average stands at 1.339 million barrels. Several analysts have forecasted inventories to hit lows last seen in 2011 by the end of the winter-grade gasoline blending season in May.

Blending Demand

The reasons behind the low stockpile levels are largely due to intense gasoline blending demand and record exports.

Gasoline production last year hit all-time highs with a zenith of 10.537 million b/d in late December, according to EIA data. Average gasoline production in 2016 was 9.816 million b/d, up 2.5% from 2015 (which held the previous record). Butane demand for gasoline blending can soar from a low of around 60,000 b/d in the low RVP summer blend months to highs of more than 800,000 b/d during the winter blend months.

Butane exports hit a high water mark themselves last year, coming in at 36.073 million barrels (98,830 b/d), up 9.5% from the prior year. November exports came in at 4.566 million barrels (152,200 b/d), a level last seen in May and more than double the five-year average. The uptick in exports was largely seen as coming from Europe and the Mediterranean for petrochemical cracking because of a scarcity of the product in the Middle East and Europe.

 Shipping sources noted petrochemical companies have been the dominant players of late in the export market, bidding quite aggressively for cargoes. Again, this is likely a short-term phenomenon. The price differential between USGC and Northwest Europe naphtha looks to be rapidly closing and should send European olefins producers back to cracking naphtha.

Butane Values

Some petrochemical players noted that is incremental cracking demand for butane domestically, even though natural gasoline and ethane are the most advantaged feedstocks. The reason: record-high prices for butadiene in the US and Asia, which is a co-product in the steam cracking process.

Asian Turnarounds

PetroChem Wire last assessed US spot butadiene at 111 cpp ($2247/mt). Asian prices, meanwhile, are around 141 cpp ($3100/mt) due to turnarounds in the region and Europe. With the arb wide open, crackers that can use butane as a feedstock are likely trying to maximize their butadiene yields. Currently, there are only a handful of crackers that maintain that kind of feedstock flexibility.

These include: BASF/Total Port Arthur; Chevron Phillips Cedar Bayou and Sweeny 33; Equistar Channelview; Flint Hills Port Arthur; Shell Norco OP-5, ExxonMobil Baton Rouge, among others.

PetroChem Wire’s forward curve assessments have consistently shown a steep backwardation between the front and next months, indicating again that butane strength should be short-lived. Currently, there is a 27 cpg discount between February and March, a relationship that has been narrowing since last week, as players deal with the short-term squeeze on the front month. The curve remains in backwardation through May as gasoline blending demand drops off and the summer blend takes hold.

 

US styrene hits high amid extreme domestic, global supply tightness

Guest column by Samantha Hartke

HOUSTON, February 2, 2017 (PCW) --- US spot styrene was assessed at $1480/mt (67.1 cpp) FOB USG on Wednesday, marking a high since PetroChem Wire began publishing styrene assessments in 2015.

This high-water mark is only overshadowed by the rapidity of its increase. Since the beginning of the year, spot styrene has gained $340/mt (15.4 cpp), or 29.8%, PetroChem Wire prices show.

The reason for the sharp uptick is supply tightness, both domestically and globally.

Americas Styrenics took down its 2.09 billion lbs/yr (950,000 mt/yr) styrene plant in St James, Louisiana, this month for what was initially planned as a month-long turnaround. Recently, the joint-venture 2.42 billion lbs/yr (1.1 million mt/yr) Cosmar plant in Carville, Louisiana, (joint venture by Total and SABIC) also went down for its planned turnaround. Last week, LyondellBasell’s 2.86 billion lbs/yr (1.3 million mt/yr) propylene oxide/styrene unit at Channelview went offline due to a power outage at the facility. All told, last week 7.34 billion lbs/yr (3.3 million mt/yr) --- or 61% --- of total North American styrene production capacity was offline for a brief time.

The LyondellBasell unit was reportedly restarted quickly.

This week, however, AmSty reported it would be extending its turnaround through mid-March because of equipment failure, and on Wednesday SABIC declared force majeure on styrene. In a customer notice, it stated that due to equipment failure it was now only expecting styrene production to resume in the middle of the year.

Additionally, this month, INEOS Styrolution’s 990 million lbs/yr (450,000 mt/yr) Texas City styrene plant is set to go down for planned maintenance for about six weeks, bringing nearly 46% of North American production capacity offline through the end of the first quarter.

As of Wednesday, March styrene was seen to be in backwardation, assessed at $1465/mt (66.5 cpp) FOB USG. But both February and March bids were seen at $1500/mt (68 cpp) on Thursday morning, suggesting the months are now at least in parity, although market players believe a contango structure will soon take hold.

Europe and Asia

Exacerbating the US supply situation are tight markets in both Europe and Asia.

According to customs data, Europe received absolutely no styrene imports from the US in December, a situation that could well repeat itself in January. Between low Rhine levels impeding vessel traffic, a recently remedied production issue at Shell’s Botlek aromatics complex in the Netherlands and an impending turnaround at Trinseo’s 1.1 billion lbs/yr (500,000 mt/yr) plant in the Netherlands, European styrene prices have also skyrocketd.

 Meanwhile, Asia is staring at an extremely heavy turnaround period in 1Q with at least 3.19 billion lbs/yr (1.45 million mt/yr) offline, especially in Taiwan and Korea, which should result in low inventory levels carrying over into 2Q and possibly, 3Q.

PetroChem Wire assesses daily styrene spot prices and monitors global aromatics outages in its Daily Refinery Focus report. For a free trial, click here.

 

Spot PGP price spike creates uncertainty upstream and downstream

Guest column by Kathy Hall, David Barry and Samantha Hartke

HOUSTON, January 20, 2017 (PCW) -- Propylene has seen immense volatility since the beginning of the New Year with PGP gaining 12.25 cpp, or 36% of its value, while RGP picked up 9.5 cpp (46.3%).

Spot PGP has traded up to 46 cpp for January, and February has traded up to 48.75 cpp -- a level last seen in Feb 2015. Jan RGP activity has been thin but since trading at 23.75 cpp on Jan 10, it has been bid up to 30 cpp, while Feb RGP traded up to 36.5 cpp. The rapidity at which these spot prices have climbed is noteworthy with PGP seeing day-to-day jumps of as much as 5 cpp (Jan 5) and RGP at 6 cpp (Jan 13), something the market hasn’t seen since the rollercoaster crude days of 2011.

There are several reasons for this volatility.

Propylene, overall, moved into a tight supply situation. While prices in Dec did not necessarily reflect a tight market, end-year destocking has often masked supply situations. When demand resurfaced in Jan, buyers this year found that they had to pay dramatically higher prices.

Enterprise Product Partners, the US’ largest propylene merchant, has been having splitter issues since 3Q 2016, conducting sporadic maintenance during July, August, September and again in December. Enterprise has six splitters at Mont Belvieu with a combined capacity of 96,000 b/d. Dow Chemical's PDH unit at Freeport also experienced intermittant issues during 3Q, finally finding stable production in September.

While PDH and splitter production outages were in the spotlight, steam cracker outages quietly exacerbated the PGP supply situation. At some of the larger crackers with some heavy feedstock furnaces, which produce more propylene as a co-product than light crackers, the supply loss was palpable.

These outages included an extension of the expansion work at Equistar's Corpus Christi cracker, which lasted until mid-December, an unplanned production upset at Equistar's La Porte cracker for two weeks in December, an unplanned upset at Dow's LA-3 Plaquemine unit for two weeks in December, and planned outages starting in January 2017 at Formosa's Point Comfort Olefins 2 unit and Chevron Phillips' Sweeny 33 unit.

US propylene stocks, according to EIA data, were at 4.222 million bbls for the week ended Jan 13, marking the third consecutive inventory draw.

Polymer Orders Pull Back

Downstream, polypropylene suppliers had expected to ramp up production to meet strong domestic demand this month, but the run-up in propylene costs has caught PP buyers off guard and caused some to lower their order volumes.

Buyers appear unconvinced that the propylene increases will be sustained for more than a couple of months. Spot HoPP on an FOB Houston basis has moved from 40-41 cpp early this month to the upper 40s cpp or low 50s cpp as of today, effectively shutting the door for deep sea exports.

However, PP suppliers have backed out of the spot market amid uncertainty over how to price their product. There has also been more discussion of PP resin imports, as prices from offshore are becoming competitive in light of a potential double-digit PGP and PP contract increase.

Splitter Upsets Mute RGP Demand

Not only have such splitter outages tightened up PGP availability, they have muted demand for RGP. While the start-up of Enterprise's new 1.65 billion lbs/yr PDH unit at Mont Belvieu later this year will give PGP supply relief, RGP demand won't change as the unit's feedstock is propane.

However, a heavy refinery turnaround period in 1Q is expected to tighten RGP supply, making Feb RGP a hot commodity. As much as almost 600,000 b/d of production from fluid catalytic crackers and 200,000 b/d from cokers are estimated to be out during these turnarounds, according to IIR Energy estimates. Propylene from refineries is produced by FCCs and cokers.

Cash costs have also contributed to the increasing tightness in propylene supplies. While many steam crackers have replaced older, heavy-feedstock furnaces in the past 10 years, and expansions have been to add light-feedstock furnaces, many have kept the option to crack propane or E/P mix, phasing out gasoil and natural gasoline. This had a limiting effect on co-product production and reduced propylene production in general, but the use of metathesis units and the start-up and expansion of PDH units has made up for some of the co-product loss.

That said, ethane has enjoyed a sustained run as the cheapest ethylene feedstock in terms of its cash cost since mid-October, which has incentivized producers to favor ethane. Ethane, of all the feedstocks, results in the least amount of propylene as a co-product, again exacerbating an already snug supply situation for PGP.

Contract Price Speculation

The spot market volatility has intensified the speculation around monthly contract prices. While the spot prices are certainly an important market component, most PGP sales volume (and margin) is into the monthly contract market.

Despite a move by some in the contract market to move away from a negotiated price to a spot market average price, the monthly PGP contract price has a major effect on downstream PP markets and resin products. PGP contract prices in 2016 ranged from a low of 30 cpp in Feb to a high of 43 cpp in Sep, with the average for the year at 34.417 cpp.

PGP spot prices in 2016 ranged from a low of 26.875 cpp in Feb to a high of 42.75 cpp in Sep, with the average for the year at 32.469 cpp. When spot PGP was last in the upper 40s cpp range (Feb 2015), the monthly contract price was 50.5 cpp, and was continuing a slide down from mid-70s cpp reached the previous Oct. With the Dec 2016 PGP contract price at 31.5 cpp, the market is bracing for a dramatic increase, and then waiting to see how sustainable it is throughout the rest of the quarter.

 

Record exports push US gasoline prices atypically higher at end of year

HOUSTON, January 13, 2017 (PCW) -- Gasoline in the Gulf Coast has gone higher in recent weeks, assessed by PetroChem Wire at 148.45 cpg on December 1, and at 163.92 cpg on Thursday, an increase of about 15.5 cpg.

This flies in the face of common wisdom, which held that higher RVP used in winter grades would allow for increased use of lower cost butane, which would in turn keep gasoline cheap.

In the same period in 2015, gasoline in the Gulf Coast fell from 126 cpg, to about 101 cpg.

Also, demand in the winter months was expected to be lower, which should be a bearish influence. In fact, per the US Energy Information Administration, domestic demand fell from about 8.8 million b/d for the first week in December to about 8.5 million at the end of the month. In the summer, demand hit well over 9.8 million b/d.

Butane did shoot higher at the very end of the year, going from 84 cpg on December 1, to 99.25 cpg on Thursday. It touched 126.5 cpg on December 28, during a feverish end-of-year bout of short covering.

Market sources, attributed the strength in butane to short positions unable to find physical barrels in the wake of exports, which tightened the market. The paper market for butane figured in as well, motivating some to buy to support forward positions.

The overall strength in gasoline was not attributable to strong butane (which is about 5% of a gasoline blend), but rather at least partly to exports, data suggests. The EIA gasoline figures show for the week ended January 6, finished gasoline exports were 981,000 b/d, compared with 472,000 in the first week of 2016.

For the week ended December 29, the EIA reported a record for gasoline exports, 1.149 million b/d.

Sea Change

It is difficult to overstate the sea change that exports represent in the market. As recently as the last week of December 2015, gasoline exports averaged about 350,000 b/d. The great majority of exports come from the Gulf Coast, as the East Coast is a net importer. The West Coast, while it has exported some gasoline in the past to Mexico and Canada, is a minor factor.

Mexico is the key destination for US gasoline. The EIA monthly data for individual countries shows that Mexico took in a record volume of gasoline in October 2016, 12.077 million barrels. In 2015, Mexico imported an average of 7.2 million bbl/month.

Of the total of 20.5 million barrels of gasoline exported in October, 12.077 million barrels went to Mexico. The infrastructure of Mexico’s refineries and pipelines has not been maintained, market sources said, so the current level of exports is likely to be sustained.

But is the price strength sustainable?

The EIA shows that while gasoline was strong at the end of the year, so were inventory increases. The first week of December, total gasoline stocks started out at 229.5 million barrels, but climbed to 235.4 million barrels at the end of the year, and hit 240.5 million barrels for the first week of 2017.

The 240.5 million barrel level is about even with the first week of January 2016, so we are starting the year about where we were last year.

High Operating Rates

We are entering 2017 with refineries running at a very high rate. In the Gulf Coast, refineries are at 96.4% of capacity, compared with 95.7% a year ago.

Margins are also up. A 3-2-1 calculation for the Gulf Coast by PetroChem Wire shows $10.50/bbl on December 1 and $12/bbl on Thursday; on January 11, 2015, the figure was $9.83/bbl.

So we are entering 2017 with high inventories, but with good export demand and high refinery runs (and therefore gasoline production). It is clear that exports are crucial.

One source felt prices were sustainable at this level, but pointed out how quickly the US built inventories up over only a few weeks. “Things change fast,” he said.

 

Refinery margins rebound in the Gulf Coast as gasoline prices climb

HOUSTON, December 16, 2016 (PCW) -- Gulf Coast refinery margins have shot surprsingly higher in recent weeks, despite tepid domestic gasoline demand, PetroChem Wire data show.

Also, cheap naphtha and blendstocks like butane were expected to allow gasoline blenders to make less expensive winter gasoline, a situation that tends to undermine refinery margins. On November 1, the NYMEX RBOB settle was backwardated by 3 cpg from December to January, but on Decemeber 15 it was at a 1 cpg contango.

Higher Gasoline

In short gasoline has gone up when it was expected by some to remain low.

Domestic demand for gasoline fell from November 1 to December 15, according to US Energy Information Administration figures, going from about 9.1 milliion b/d to 8.9 million. Diesel demand was steady at about 4 million b/d.

Crude oil has been stronger. Front month WTI from November 1 to December 15 in this period went up about $4.23/bbl ($46.67/bbl to $50.90/bbl), or 10 cpg; gasoline in the Gulf Coast, however is up about 14 cpg ($1.3266/gal to $1.4673/gal).

Refinery margins in the Gulf Coast based on a 3:2:1 crack spread (3 barrels of crude yielding 2 barrels of gasoline and one barrel of diesel) have gone from $8.78/bbl on November 1 to $11.20/bbl on December 15, PetroChem Wire data show (it hit $5.70/bbl in mid-November).

During the same period the NYMEX 3:2:1 crack actually fell 85 cents, from $16.12/bb; to $15.27/bbl.

In addition, fluid catalytic cracking margins were up. The PetroChem Wire calculates a margin based on front month WTI and 70% spot gasoline and 30% diesel.

On November 1 the FCC margin was $12.18/bbl, but by December 15 it had risen $1.42/bbl to $13.60/bbl.

Higher VGO

VGO trades as a differential to WTI. On November 1, sweet VGO was assessed at plus $5/bbl; on December 15 it had risen to $7/bbl.

In other words, while the cost of VGO went higher, the margins of putting it into an FCC and making gasoline and diesel went higher anyway.

So gasoline demand is not all that great, crude is up but gasoline is up even more, and refinery units like FCCs are showing better economics, at least in the Gulf Coast.

Export Strength

The reason for this relative strength appears to be increased exports, especially of finished gasoline, For the week ending December 9, the EIA showed the US exported 1.131 million b/d of gasoline, which, is an all-time record. Last year at this time the export number was 616,000 b/d.

The US only a few years ago was a net importer of gasoline, but it now exports to Latin America, especially Mexico. In September, Mexico took about 10.2 million barrels of gasoline from the US, about double what it did in September 2015, according to the EIA.

Mexico has not put sufficient effort into maintaining refineries and infrastructure, sources said, so the imports there are likely to be a more or less permanent feature of the market.

 

US blendstocks trade against virtually non-existent, minor grade of gasoline; change is unlikely      

HOUSTON, December 9, 2016 (PCW) -- US gasoline blendstocks will continue to be priced against a grade of gasoline that virtually does not exist in the domestic market because a change would be “an accounting nightmare.”

Gulf Coast gasoline blendstocks, such as alkylate, raffinate and reformate, as well as heavier naphtha, have for decades traded as a differential to conventional gasoline, known as “M” grade (a reference to nomenclature used by the Colonial Pipeline for conventional gasoline).

Alkylate, for example, is currently trading at 22 cpg over pipeline M4 gasoline, raffinate is at 16 cpg under M4, and reformate is 37 cpg over M4. Naphtha was assessed at 19 cpg under M4 (The ‘4’ refers to the gasoline RVP, which changes throughout the year).

Conventional gasoline is just exactly what it sounds like, 87 octane gasoline that has been used in domestic cars forever.

Beginning around 2006, however, the US began a federally mandated program putting increasing volumes of ethanol into finished gasoline. Today, those volumes, in effect, require virtually every gasoline of retail gasoline in the US to contain 10% ethanol.

The grades of gasoline are called “CBOB” and “RBOB,” for Conventional Blendstock for Oxygenated Blending,” and "Reformulated Blendstock for Oxygenated Blending." Both grades are 83.7 octane and, when blended at 90% with 10% 115 octane ethanol, make 87 octane finished gasoline.

RBOB is used in higher pollution areas, like Houston, Dallas, Chicago, Milwaukee, and the Eastern Seaboard from Boston to Washington DC. A form of RBOB called CARBOB is exclusive to California. CBOB is used everywhere else.

CBOB Two-Thirds of Demand

Effectively, RBOB is one third of US demand and CBOB is two-thirds.

There are some places one can still fill up one’s car with conventional gasoline, notably Oklahoma, where a few retailers protest the ethanol mandate. Also some locations use conventional in marine applications where gasoline with ethanol has never been embraced.

But it is a very rare grade. The Colonial Pipeline tried to stop shipping conventional gasoline some years ago, but relented after market objections. It currently does not list the lowest RVP grade of conventional, M1 – what used to be the benchmark ‘Southern Grade’ gasoline – at all for shipping.

Mostly for Export

However, plenty of conventional grade gasoline is still produced in the Gulf Coast, but it is for export, mostly to destinations throughout Latin America.

It would make more sense to have all blendstocks trade against CBOB, the new “conventional” gasoline. But it is not likely to happen.

“There are swaps and other contracts for blendstocks that are priced against conventional gasoline,” commented one broker. “Hundreds for sure, I don’t know how many ... how would you unwind them?”

The swaps are long-term sales, tied to publications’ assessments, internal transfer prices, all tied to a grade of gasoline that, although it still is traded, is hardly a presence in the US.

It was hoped by some that the ethanol mandate would be lifted, in that one of its intended reasons to exist, to lessen US dependence on foreign oil, seems to have been solved by the shale crude revolution.

But that did not happen, and it appears that the new US administration does not have any intention of changing the status quo.

More Ethanol for 2017

In fact, the most recent renewable fuels requirement announced in late November by the US Environmental Protection Agency (which administers the program)  has upped volume of ethanol for 2017.

To some, it may not be a big deal that the blendstocks are priced off an almost non-existent grade of gasoline. As assessed by PetroChem Wire, CBOB was trading at 9 cpg under the NYMEX RBOB settle, while M grade was 5 cpg higher at minus 4 cpg.

Others might feel uncomfortable with this situation and push to change to CBOB. If the Colonial Pipeline has in fact decided to not ship M grade, the industry might be forced to change.

VGO differentials, FCC margins softer on weak gasoline fundamentals; little incentive to up FCC runs

HOUSTON, November 18, 2016 (PCW) -- Vacuum gasoil differentials on Thursday hit their lowest levels since March, driven down again by the fundamentally weak gasoline market.

     VGO is a major refinery feedstock, which is inputted into a fluid catalytic cracker (FCC) to make gasoline and diesel.

     Typically VGO trades as a differential to WTI and usually holds a premium.

     On Thursday, sweet VGO was assessed by PetroChem Wire at December WTI plus $4.25/bbl. As recently as November 1, the differential was $5.50/bbl, and on October 4 it was $7/bbl. The last time it was as low as $4/bbl was March 7, according to PCW assessments.

     When VGO is inputted into an FCC, the rule of thumb is that it produces 70% gasoline and 30% diesel (as well as other by-products). When one takes the cost of VGO  (in this case the price of  WTI and the differential) and compares the Gulf Coast value of the products (using 70% gasoline and 30% diesel), a margin  (“the FCC margin”) can be calculated.

     So as the differential over WTI goes down, one might think the FCC margin would go up, but in fact the opposite has happened. On Thursday, the FCC margin based on PCW prices was $10.66/bbl, down from $12.18/bbl on November 1; on October 4 it was $14.92/bbl.

     To be fair, this weakness occurred during a period when a Colonial Pipeline leak was being repaired, which meant significant gasoline volumes that would have gone to the East Coast were temporarily kept in the Gulf Coast (things are back to normal now). But at the same time, refiners such as Total and ExxonMobil reacted by cutting cut crude runs, therefore producing less gasoline.

     In fact, measured by the US Energy Information Administration, as a percentage of capacity, Gulf Coast crude runs were low in this period. For the week ending Oct 7, Gulf refineries ran at 86% of capacity, down from 90.4% the previous week. They stayed at roughly that level until the most recent numbers for the week ending Nov 11, when they hit 91.1%.

     And during this period exports of gasoline were very strong, averaging about 850,000 b/d, about 450,000 b/d over the same period in 2015.

    So, despite lower VGO differential prices (an incentive to run VGO), lower crude inputs (which would make gasoline) and strong exports of gasoline, FCC margins were lower anyway.

Refinery Grace Propylene

    One by-product of an FCC is refinery-grade propylene, a feedstock that can be used to make alkylate or to produce polymer-grade propylene.

    RGP prices have fallen in this period, dropping from 32 cpp on Oct 3 to 16.5 cpp Thursday. This is perhaps reflective of the price of alkylate, which has been up and down.

    Alkylate is a 92 octane, low-RVP gasoline blendstock that is more valuable in the summer. In the winter it is often stored for use in the spring. It trades as a differential to gasoline.

    On Oct 3, alkylate was assessed to a low of 15 cpg over gasoline, but recovered to 25 cpg by Thursday. Those numbers, however, are still at historic lows.

    With VGO margins low and RGP down as well, there is no incentive to run an FCC harder than at minimum rates. One would think that would tighten RGP, but so far that does not appear to be the case.

US styrene hits 15-month high as global prices skyrocket amid tight supplies

By guest blogger Samantha Hartke

HOUSTON, November 10, 2016 (PCW) – The front-month US spot styrene price was assessed today at $1085/mt (49.2 cpp) FOB USG, marking a 15-month high, as global prices similarly saw multi-year highs amid an extremely tight global supply situation.

The last time US spot styrene was at this level was late August 2015, when it was assessed by PetroChem Wire at $1090/mt (49.4 cpp) FOB USG.

The recent spike comes as part of a wave of global styrene strength. On Wednesday, Asian front-month styrene shot up $30/mt to $1150/mt CFR China and Europe gained $25/mt to $1048/mt CIF ARA, marking year-to-date highs for these markets.

The reason for these increases is global supply tightness.

In the US, Westlake’s 260,000 mt/yr Lake Charles styrene unit shut down in mid-October after a fire at the unit. A force majeure on styrene was declared shortly thereafter. The unit is expected to restart at some point this week.

Ineos Styrolution’s 450,000 mt/yr Texas City plant went down almost two weeks ago and a restart timeframe is unknown. Meanwhile, Shell’s 365,000 mt/yr Scotford plant is in restart mode after a month-long turnaround.

Currently, 26% of North American styrene capacity is down with Scotford’s 9% expected to fully to return to service soon.

Low Production

US production levels are at their lowest ebb since 2Q 2015, according to AFPM data, coming in around 2.6 billion lbs in 3Q, compared to nearly 2.9 billion lbs in 2Q and 2.7 billion lbs in 3Q 2015.

The situation is just as tight around the world. Among the units down: Unigel’s Cubatao unit in Brazil; SK Global’s Ulsan plant and Saudi Polymers’ Shuaiba plant, totaling 930,000 mt/yr of lost production. In Europe, BASF’s styrene unit at Ludwigshafen – the site of a deadly blast – is slowly ramping up to full rates.

Asia is also just exiting a heavy turnaround season in 3Q with China having reduced the capacity of a slew of aromatics units to lower pollution levels during the G20 meeting in Hangzhou in September. As a result, eastern China’s inventory levels are quite low, coming in at 55,000 mt this week, compared to the historical average of about 100,000-120,000 mt.

Market sources said the situation is likely to remain tight through year’s end with late Dec deals being reported at the current assessed levels, indicating domestic tightness amid continued hot demand for exports. The tightness could well extend into the new year as global forward styrene markets for Jan are barely in backwardation, according to Thursday’s bid and offer ranges.

 

Changes in China markets to cast bearish shadow over US reformate, despite strong gasoline demand, exports

Reformate differentials in the US Gulf Coast have fallen consistently over the last year, despite the ups and downs of the overall market.

When naphtha is inputted into a catalytic reformer, reformate is produced, typically a low, 1 RVP 100 octane gasoline blendstock.

Reformate can either be used directly in gasoline blending or petrochemicals, or be further inputted into an aromatics extraction unit, where it makes benzene, toluene and xylene.

Benzene Limits

Toluene and xylene can be gasoline blendstocks and petrochemical feedstocks. Benzene, however, has very limited use as a blendstock, especially in the US where it is federally mandated to make up less than 1% of overall gasoline content.

Because of its low RVP, reformate is valuable as a blendstock when used with higher RVP light naphtha and natural gasoline to make gasoline.

One would think that with excess naphtha and natural gasoline in the market (the result of lighter crude production since the advent of shale), there might be bullish pressure on reformate to blend gasoline.

But that has not been the case. Reformate trades at a differential to gasoline. On November 2, 2015, reformate was assessed by PetroChem Wire at gasoline plus 71 cpg. But the market has trended lower since then, and on Wednesday, reformate was assessed at gasoline plus 37 cpg, a nearly 48% decline.

Much of this weakness occurred during a period of strong domestic gasoline demand and higher gasoline exports.

Record Exports

In fact, while domestic demand for gasoline was 9.1 million b/d for the last week in October, marginally lower than last year, exports were an all-time record of 7.94 million barrels in August, up from 4.39 million a year ago, according to EIA data.

So why would reformate be weak? Market sources said it is at least partly attributable to changes in China.

While the EIA does not specifically track exports of blendstocks, it does report non-crude exports to China. This data set has seen a dramatic drop. In August 2015, the US exported 7.27 million barrels of products to China; this August, that figure was 1.823 million, a nearly 75% fall-off.

China Tariffs

Earlier this year, China increased tariffs on reformate imports, putting it at parity with finished gasoline (formerly it was at a discount). At the same time, China has increased its domestic crude runs to the point it is now a net exporter of many products, such as gasoline and diesel.

China is now competing for export outlets with India and Singapore, market sources said, which will make it a limited outlet for US exports of gasoline.

This seems to be a trend that will not reverse itself anytime soon and should remain a bearish for US reformate in the longer term.

 

Crude, gasoline bullish run likely short-lived by high 2017 inventories

HOUSTON, October 28, 2016 (PCW) -- Crude oil and gasoline prices have increased in recent weeks and crude inventories are down, but has the market turned bullish? Inventories of gasoline suggest the answer is no -- not by a long shot.

Since September 1, front month WTI has pushed up $6.56/bbl, from $43.16/bbl to $49.72/bbl on Thursday.

In the same period, Gulf Coast CBOB gasoline was assessed by PetroChem Wire at $1.2774/gal to $1.3985/gal, an increase of 12.11 cpg or about $5.86/bbl.

Gasoline production has dropped in this period, according to US Energy Information Administration figures, from 1.0173 million b/d for the week ending September 2, to 9.837 million b/d for the most recent figures, the week ending October 21.

So crude and gasoline prices are up and gasoline production is down. And gasoline stocks did fall about 1.7 million barrels from September 2 to October 21 to 226 million barrels.

But those gasoline inventories are still extraordinarily high. For the week ending October 21, total US gasoline stocks were at 226 million barrels per the EIA -- an all-time record for the third week in October.

That current gasoline figure is about 7.4 million barrels over last year (for the third week in October), 23 million barrels over 2014, 13 million barrels over 2013, and 26 million barrels over 2012.

In short, we are going to enter 2017 with very high inventories.

Gasoline demand has been good. For the most recent week it was 9.1 million b/d, essentially flat to October 2015.

At the same time refinery inputs were lower. On September 2, total US inputs to refineries were at 93.7% of capacity. On September 21, the figure was 85.6%. In 2015, the comparable figures were 90.9% on September 2 and 87.6% in October.

So even with markedly lower inputs to refineries and essentially flat demand, gasoline inventories are at record levels for this time of year.

Low Octane Components

The EIA figure for stocks is “total” gasoline stocks, meaning it includes gasoline blendstocks, which is unfinished gasoline like light naphtha and natural gasoline. Those are low octane components that can be turned into finished gasoline when blended with mixed xylenes, toluene or alkylate, among others.

Some of those components are made from lighter grades of crude that have been produced by fracking.

Sophisticated refiners in the US turn about 50% of the crude they run into gasoline. It is hard to see how the market could head significantly higher when gasoline is so long.

We are heading, after all, into the winter season when domestic demand typically falls off.

One thing that could turn this around is exports, and those are indeed up. Given our current inventory situation, they will need to increase.

VGO differentials to WTI touch lowest level since August, could tighten RGP markets

HOUSTON, October 21, 2016 (PCW) -- Vacuum gasoil differentials have equaled their lowest levels since August as the PetroChem Wire low sulfur barge assessment fell 50 cents to November WTI plus $5.25/bbl.

Before touching $5.25 in August, the market had not been this low since March.

VGO is a refinery feedstock that is inputted into a fluid catalytic cracker, a major gasoline producing unit at a refinery. The rule of thumb is that an FCC produces 70% gasoline and 30% diesel (as well as other by products like refinery grade propylene).

Typically, VGO trades at a differential to WTI and usually at a premium. A refinery can make its own VGO and input into an FCC, or (as is typical in the US Gulf Coast), have a large FCC that is configured to allow it to be supplied with VGO purchased from the spot market.

In the Gulf Coast, refineries were historically designed with large FCCs that were supplied by European-sourced material.

An FCC is a gasoline-driven unit. They were installed to make extra gasoline when gasoline was needed; in Europe, gasoline is as dominant a fuel as it is in the US.

Gasoline, especially in the shale era, can be made in different ways. In the current market, light naphtha, natural gasoline (that in some cases is gathered by truck from a crude oil field), and heavier naphtha can all be blended, resulting in finished gasoline that, in a sense, does not come directly out of a refinery.

FCC Not Idle

So you don’t need an FCC (cost: $1 billion) to make gasoline. But once you have one, a refiner is not going to let it sit idle.

The highest that VGO differentials were this year was on April 15 when they hit WTI plus $10.25/bbl -- which was still historically low. Back in 2008-12, they were routinely as high as WTI plus $25/bbl.

But consider that on April 15, NYMEX RBOB settled at 146.12 cpg. On Thursday it settled at 149.37 cpg, so gasoline is up 3 cpg. Meanwhile, NYMEX WTI on April 15 was $40.36/bbl (96 cpg). On Thursday, it was $50.43/bbl (120 cpg), up $10/bbl or about 24 cpg.

So crude is up, while gasoline is gaining at the same magnitude.

VGO differentials, however, were marginally up over the summer, generally between $6-7/bbl over WTI, but overall trended lower, hitting $5.24/bbl on Thursday.

Lower VGO differentials suggest that refiners will run FCCs at low rates and this suggests that RGP, which is a by-product of FCC runs, will trend lower. Refiners run VGO to make gasoline, not RGP, but if inputs to FCCs are deemed uneconomic then RGP production will inevitably fall.

Tighter RGP

Combine this with the newly emerging PGP export market, and you could have an RGP market that could be tighter.

What could change this? Lower light crude oil production might mean less light blendstocks, which would tighten naphtha and make blending less attractive.

Also increased gasoline exports, especially to Mexico -- where there are a host of refinery issues and declining infrastructure (see last week’s blog) -- could boost refinery margins.

US gasoline exports hit record high, helped by growing demand from Mexico

HOUSTON, October 14, 2016 (PCW) -- Exports of gasoline from the US hit an all-time high last week with Mexico taking record amounts.

The US Energy Information Administration statistics released Thursday for the week ending October 7 showed exports of 805,000 b/d from the US. As recently as June, the weekly export figure averaged 380,000 barrels over four weeks.

Aggressive Exporter

The US has been an aggressive exporter of gasoline since the beginning of the shale crude era. In June 2010, the US exported only about 8.5 million bbl/month, per the EIA. In June 2012, that figure shot to 10.2 million bbl/month and by June 2015, to 11.9 million bbl/month.

The US exports gasoline all over Latin America (as well as Africa and even Asia). But Mexico is by far the largest destination.

In 2015 Mexico averaged imports of 237,000 b/d, about half of the total US exports of gasoline and about seven times the volume of other large importers, such as Ecuador or Colombia.

 In July, the 275,000 b/d Cadereyta refinery in northern Mexico was shut because of insufficient water supply for boilers. By the last week in July, total US gasoline exports had increased to 454,000 b/d, hitting 655,000 b/d in early September and 805,000 b/d last week.

The weekly EIA statistics don’t break out destinations by individual country, but the monthly numbers do. However, they are delayed by a few months.

It is not clear if the Cadereyta refinery is still down or perhaps running partial rates. One trader with Latin American connections said it remained out of operation.

Another source estimated that lack of maintenance in the entire Mexican refinery system now means that it is able to supply “50 percent” of what it could a few years ago. Total Mexico refinery crude capacity is about 1.25 million b/d.

'New Venezuela'

“Mexico is the new Venezuela,” said another source.

Imports to Mexico are likely to come from the Gulf Coast and not the West Coast, as the latter market has had refinery issues for much of this year and has significantly less ability to make extra gasoline even when plants are running at full capacity.

The effect on the Gulf Coast is demonstrated by gasoline differentials. On June 1, NYMEX gasoline closed at 161.53 cpg. The CBOB market traded at 11.5 cpg under the NYMEX, putting the outright price at 150.03 cpg. On Thursday, the NYMEX closed at 148.16 cpg, but the CBOB spread was 1.75 cpg under, or 146.43 cpg.

The Gulf Coast NYMEX gasoline spread has tightened by almost 10 cpg; the NYMEX fall had almost been made up by the tightened spread.

Higher inventories douse alkylate differentials, despite record gasoline demand

HOUSTON, October 7, 2016 (PCW) -- Alkylate differentials have remained low this summer, pushed by oversupply and the start of the higher RVP driving season.

Alkylate is a lower volatility (5.5 RVP), high-octane (92) gasoline blendstock that is prized for its lack of aromatics, its essentially clean specifications, as well as its low RVP for summer gasoline blends.

It trades in the Gulf Coast at a differential to conventional gasoline.

Last October at this time, alkylate was assessed by PetroChem Wire at gasoline plus 31 cpg. On Thursday, alkylate came in at 14 cpg. Reformate, another important blendstock component, was 58 cpg over gasoline last year and is now 36 cpg over gasoline.

At least part of the explanation lies in the relentless build in gasoline blendstock inventories.

The US Energy Information Administration lists “Gasoline Blending Components” in its weekly report, but those figures don’t break out specific components, although they include alkylate.

The EIA shows that in PADD III (the Gulf Coast), blending component inventories fell marginally from about 75.3 million barrels in January to 74.4 million barrels in September, which is the most recent data that EIA has available.

 

This is in marked contrast to 2015 where inventories started in January at 70.1 million barrels and dropped to 64.3 million in October.

Essentially, inventories this year have built when they typically should have dropped. Other years follow a similar pattern to 2015: blending components are stored in the winter in anticipation of the driving season and are worked down over the summer.

This year, inventories built despite gasoline demand that is near an all-time record. The EIA listed gasoline demand as 9.3 million b/d for the week ending September 30, up 3.9%. For much of the summer it was 9.7 million b/d.

Store now, sell later

Typically alkylate should be weaker as the market heads into winter, when gasoline RVPs increase to 13.5 RVP in the south and 15 RVP in the north, and alkylate (at 5.5 RVP) is less in demand than in the summer (7.8 RV and 9.0 RVP).

Right now the best option for those long alkylate may be to store it for spring. The absolute price of alkylate Thursday was about 165 cpg. It costs about 2 cpg per month to store it, so if you held in until April –seven months—it would cost 179 cpg.

The April NYMEX right now is about 170 cpg. Assuming the Gulf Coast is trading at a 5 cpg discount – 165 cpg -- and alkylate is 14 cpg over that (179 cpg), players are breaking even right now.

However, the spread is likely to increase going forward. If it goes from 14 cpg to 25 cpg, that 11-cpg spread can be an attractive alternative to trying to sell today.

Venezuela's oil supplies to the US are at risk, as are low US pump prices

HOUSTON, September 30, 2016 (PCW) -- US commercial crude oil inventories showed a 1.9 million barrel decline, to 502.7 million barrels, for the week ended September 23, the fourth straight weekly drop. Just a month ago, for the week ended August 26, the stocks were 525.8 million barrels.

At the same time US production was more or less steady at about 8.4-8.5 million b/d.

Throw in an informal OPEC meeting where it is announced that crude production may be cut, and you have a fairly impressive crude increase of $2/bbl, to $45.83/bbl from Monday to Thursday.

So has the trend of the market changed?

International supply being what it is, there is no certainty that the production cuts would be honored by OPEC members like Iran, or by Russia.

Venezuelan meltdown

However there is one event that could cause an immediate spike in crude prices: a meltdown in Venezuela. PDVSA, the Venezuelan state-run oil company, is under extreme pressure, according to a report by the Columbia SIPA Center on Energy Policy.

The August report, entitled Venezuela’s Growing Risk to the Oil Market, said that lower oil prices have pushed Venezuela to the breaking point. “The cash-flow situation of PDVSA is so critical that even a steep cut in its dollar transfers to the government could not keep it from falling into arrears with key oil service providers.”

The report states that Venezuelan total production that had been steady at about 2.6-2.7 million b/d has dropped to 220,000 b/d in the first six months of 2016.

“Political conflict in Venezuela has significantly intensified," the report states. "This started to happen with the electoral loss the government faced during the December 2015 legislative elections, which resulted in the opposition winning two thirds of the National Assembly. But the government has failed to recognize the electoral results and has de facto thwarted the capacity of the National Assembly to legislate, using its control of the Supreme Court to declare the laws issued by the elected assembly as unconstitutional.”

Jaw-dropping decline

The decline of Venezuelan oil industry is truly jaw-dropping. When Hugo Chavez took control of Venezuela in 1999, the country averaged 45.4 million barrels a month of crude exports to the US, per the EIA; in 2015 that figure was 25.2 million.

The reason for this, market sources have said, was the lack of maintenance of vital crude oil infrastructure by the Chavez and Nicholas Maduro governments.

The refining sector is equally bleak. Venezuela is a country with a population of 31.4 million, and a refining capacity of about 1.2 million b/d. The system is configured to allow exports, which makes sense in that the country has cheap crude and good access to northern and southern hemisphere products markets.

In 1999 Venezuela exported about two million barrels a month of gasoline to the US, maybe eight cargoes per month. As of 2015 that number is effectively zero at about 2,000 barrels a month, or one cargo for the entire year.

Diesel exports to the US in 1999 were 1.6 million barrels a month; in 2015 that figured has dropped to literally zero.

Gasoline importer

In fact Venezuela now actually imports gasoline components from the US (akin to taking coal to Newcastle), so they can keep prices low at retail for an increasingly rattled middle class. Gasoline has always been a cheap, subsidized perk for citizens; the current price is about 20 cents per gallon.

Citizens of Venezuela now buy cheap gasoline by the can and take it across the border to Ecuador, where it can be sold or exchanged for food and other necessities.

The US imported 20.1 million barrels of crude from Venezuela in June, according to the EIA, or about 670,000 b/d. US refineries consumed 16.1 million b/d of crude last week, so 4% of our crude runs are with Venezuelan oil. That’s a lot, and if that supply were cut off, the result could be sharply higher prices.

The market shot up this week on the crude draw in the US, among other factors. Still the EIA described crude inventories as “at historically high levels for this time of year.”

A political upheaval that would cut off or curtail crude supply to the US is not unthinkable. In fact that would allow other OPEC members to produce crude to make up for any shortfall.

Bullish EIA crude, gasoline inventory figures a head scratcher, is correction in the works?

HOUSTON, September 23, 2016 (PCW) -- Inventory figures issued by the US Energy Information Administration threw the market a curve ball Wednesday, showing huge draws in crude and gasoline.

The market had expected the opposite. One bank issued its weekly inventory view that looked for a 3.6 million barrel build in crude stocks.

The EIA, however, showed a 6.2 million barrel decfrease. Gasoline was expected to decline 1.3 million, but showed a bigger drop of 3.2 million barrels.

November NYMEX WTI settled Wednesday at $45.34/bbl, up $1.29/bbl. October NYMEX RBOB finished up 3.44 cpg at $1.3960/gal.

Weak Market

This blog has argued over the summer that the market is fundamentally weak in crude and products and that spikes in the market were going to be temporary, effectively creating opportunities to sell short.

So, the question becomes: Have things changed? Has the market tightened?

In the past month, the market pushed higher after floods in Louisiana and bad weather in the East Coast caused refineries to lower runs as ships bringing crude to them were held out at sea.

By now the market had expected things would have come back to normal with crude delivered and stocks replenished. That does not appear to have happened.

One suggestion is that the crude may have been diverted elsewhere, to storage in the Caribbean, for example. That crude will eventually get here.

Another theory is that the numbers are simply wrong, that some company did not report correctly. Revisions to EIA numbers are not unheard of.

A mistake could have been made also in US production levels, which are lower than last year, but were only down by 19,000 b/d on the week. One source said production data is less reliable than other EIA data.

None of these explanations seem very satisfying.

'No Way'

“There is no way we drew that much crude in one week,” one source said.

The gasoline decline is also hard to explain. Demand over the past four weeks was essentially flat at 9.6 million b/d.

Average daily exports of gasoline over four weeks (as shown by the EIA) were up about 53,000 b/d, a total of 371,000 barrels for a seven-day week. Gasoline imports were down about 81,000 b/d, a total of 406,000 barrels for a seven-day period.

So flat demand and 777,000 barrels less supply – a deficit of 777,000 barrels. A long way from a weekly drawdown of 3.2 million barrels.

If you use all the week-to week figures, the implied drawdown comes to 2.642 million barrels, 550,000 barrels off the gasoline stock figure. Gasoline demand for that one week (ending September 16), was up 244,000 b/d -- another data point that is difficult to accept.

Refinery crude inputs have not changed significantly and there have been some turnarounds in gasoline producing units like fluid catalytic crackers and reformers last week.

Again none of this is really a satisfactory explanation. The feeling here is that there will be a correction next week, and a return to fundamental weakness.

Colonial Pipeline outage does little to change bearish gasoline situation despite short-term price upticks

HOUSTON, September 16, 2016 (PCW) -- This blog has argued for weeks now that gasoline is fundamentally weak, and as we head into winter, when more low-priced butane can be blended into gasoline, it should remain cheap.

While the fundamentals have not changed, the prompt market shot higher this week on news that repairs to the Colonial Pipeline’s gasoline line in Alabama will take longer than expected.

A leak was discovered last Friday, which necessitated the shutting down of one of the two Colonial lines. The leak directly affected the line that carries about 1.4 million b/d of gasoline from the Gulf Coast to the East Coast, terminating in New York Harbor. A second line, which was also shut down in the area, carries about 1.2 million b/d of distillates – diesel and jet fuel.

The market reacted -- October NYMEX RBOB shot up just over 8 cpg since last Friday.

The lack of the ability to ship has “just created a glut of products in the Gulf,” commented one trader. Gulf Coast gasoline has seen only a milder gain of about 3 cpg since Friday.

If the repairs take another few days and the line is down for, say, 10 days, that could lead to a cumulative gasoline shortfall of about 14 million barrels on the East Coast.

The US uses about 9.4 million b/d of gasoline, (based on US Energy Information figures), so that 1.4 million b/d constitutes about 15% of total domestic demand and 40% of the East Coast demand -- not a small amount. Mid-morning Friday, Colonial stated that repairs were progressing on its gasoline line, and that it had shifted some of its gasoline to the second distillate line.

Still it will be at least a few days before things return to normal. And consider that the pipeline runs at 100% capacity, so lost supply cannot be “made up” by running the line harder.

Supplying extra gasoline to the East Coast would not be too difficult over time. Canada and Europe are routine suppliers of gasoline already and Caribbean blenders could deliver as well.

Caribbean Swap

If the problem persisted, the federal government could suspend the Jones Act and allow ships to move from the Gulf Coast to the East Coast. If not, traders can take gasoline to the Caribbean, replacing those that left for the East Coast.

Delivery from Canada or the Caribbean would take 5-7 days; Europe would be more like two weeks.

Early Friday morning, the October NYMEX RBOB was up 1.56 cpg to 144.58 cpg, while November was down 0.73 cpg to 137.12 cpg. October NYMEX WTI was down $1.00 to $42.91/bbl.

The market is long gasoline, but as was seen when the storms hit Baton Rouge, it can easily shoot higher.

Crude's price jump unlikely a bellwether for the future

HOUSTON, September 9, 2016 (PCW) -- The market reacted viscerally to the bullish inventories Thursday, which put crude supplies and production lower.

Crude stocks were the lowest in months and production took a hit as well. Imports were off significantly too, and overall demand seems to have locked in at higher levels.

The upshot was a WTI market that pushed up $2.12/bbl on Thursday, to $47.62/bbl.

Has the market turned? Seems unlikely.

The inventories simply reflect the effects of bad weather in the Gulf Coast, and the East Coast, market sources suggested Friday. “They’re all lined up in the Gulf (of Mexico) waiting to come in,” commented on trader, referring to crude ships.

Storm Impact

And the US East Coast has also been affected by Hermine, delaying delivery of crude into refineries here.

There is “no way we drew 14 million barrels in one week on crude,” commented one broker.

Crude production is indeed lower. As recently as July 2015 it was 9.6 million b/d. Last week it was 8.6 million b/d.

Imports are the difference. In fact the week before last crude imports were 8.9 million b/d, the highest since August of 2012. Most of that increase is of course, Canada, largely immune to the weather.

But the US gets significant crude from the obvious sources like Saudi Arabia and Kuwait, but also Mexico, Colombia, Brazil, Venezuela, Nigeria, Russia, Norway and many others.

This blog suggested a few weeks ago that gasoline would remain weak as we headed into the winter, when gasoline is allowed to be blended with more (cheap) butane.

“The fundamentals of supply and demand have not changed,” commented one market participant.

RGP price strength, supply tightness due to lower FCC margins, weak gasoline

HOUSTON, September 2, 2016 (PCW) -- Refinery grade propylene prices have shot higher in the past month, driven by tighter supply, and perhaps, other factors.

On August 1 RGP was assessed by PetroChem Wire at 21.5 cpp. By Thursday, it was 33 cpp, an increase of almost 50%. In that time, polymer grade propylene went from 33.5 cpp to 42.5 cpp, a 21% increase.

In the same period, November Brent went from $42.60/bbl to $45.45/bbl, an increase of about 6.6%.

PetroChem Wire also tracks the price of alkylate on a cpp basis (it trades on a cpg basis) and this data appears below and as a graph in the Daily Refinery Focus. The graph shows that RGP, which was assessed lower than alkylate throughout the summer, is now trading at a significant premium.

Perhaps fluid catalytic cracking margins are part of the reason. An FCC takes vacuum gasoil and cracks it into 70% gasoline and 30% diesel; RGP is a by-product. The harder an FCC runs, the more RGP is produced.

But FCC margins have been hit by lower gasoline prices. On August 1, the margin was $11.88/bbl; on August 15 it was $13.07/bbl. It hit its high on August 24 at $18.89/bbl; by September 1 it fell all the way back down to $12.29/bbl.

Clearly this is tied to gasoline. After a brief flirtation with higher numbers, gasoline this month went dramatically lower as we headed to winter.

(In fact, a few weeks ago, this blog suggested any gasoline strength was going to be ephemeral, and that has largely proved to be the case).

On August 1, M2 grade gasoline was assessed at 130.36 cpg by PCW. It hit its high on August 24 at 156.46 cpg, up 26 cpg, before heading lower. Since then it has dropped 24 cpg to 132.3 cpg on September 1.

Those are remarkable numbers, not just in terms of the weakness but also the strength, and the overall volatility.

The immediate reason for higher levels was no doubt the flood-related issues that affected refineries, which included plants in Baton Rouge and on the lower Mississippi River.

Also, there were a few problems at larger fluid catalytic crackers in Houston, but they have since largely been resolved. With the subsiding of the water, the market fell.

Perhaps this is a lesson in volatility -- in the short-term, refinery issues can push the spot market up, but reality eventually asserts itself.

Barring a physical calamity like a hurricane, it is hard to theorize stronger gasoline prices. Naphtha of various grades are 32-38 cpg under finished gasoline in the Gulf Coast, a level that given the already relatively cheap octane boosters (save for toluene and mixed xylenes, which are indirectly tied to strong benzene), ensures that blending gasoline will remain cheap and FCC margins remain under pressure.

That will tend to keep inputs to FCCs lower and RGP production less than it might be otherwise. One might think that refiners might try to run FCCs harder to make RGP, but one source dismissed that, saying “refiners don’t run cat crackers to make RGP, but to make gasoline.”

Potential Lyondell plant sale shows struggle of merchant refiners

HOUSTON, August 26, 2016 (PCW) -- It seems like only a few years ago the US was decrying the lack of new refineries built here and calling for new plants. The most recent ‘new’ refinery built in the US was commissioned in 1976 -- the 200,000 b/d Marathon plant in Garyville, La.

Things have changed. Only Thursday, LyondellBasell indicated it had contracted with bank to explore selling its 263,000 b/d refinery in Houston. It is a highly sophisticated plant that can run light and heavy crudes.

While no ground has been broken to build a new plant, US refinery capacity has increased fairly dramatically in this decade. In 2010, the total crude capacity was listed at 17.597 million b/d; today it is 18.320 million b/d. Effectively, we have added a new 723,000 b/d refinery in six years.

But in 2016, one look at margins makes it clear why there is motivation to get out of refining. The NYMEX 321 crack gives a sense of what has happened to refinery margins.

Using history as a guide, note that the graph shows that summer margins are about as good they can get. They decrease as the market heads to winter, when higher RVP gasoline blends allow for blending increased percentages of cheap butane into finished product.

The NYMEX RBOB crack (RBOB vs. WTI) shows this. The August crack on Thursday was $14.89/bbl, dropping to $12.20/bbl in September and $8.92/bbl in December.

One issue with Lyondell is that it does not own its own crude oil. For many years and until a few years ago, it partnered with Citgo to receive cheap crude from Venezuela. Since that deal ended, the company has made itself more flexible, allowing it to run lighter and heavier crudes. And it did the right thing.

But merchant refiners – those without crude oil, retail or special niches – are struggling. Consider that recent refinery purchases are by PBF (ExxonMobil's Chalmette and Torrance, Cal. facilities), a company that has deep roots in trading oil and so is light on its feet. This is unlike Lyondell, which operates more like a major oil company.

Lyondell suitors listed as interested in the refinery include companies which have crude oil (Saudi Aramco, Cenovus and Suncor), which essentially means the plant would again get cheaper crude than what it currently pays on the spot market.

Spot Market Dependence

And Lyondell does not have a retail system, which means it is dependent on spot market sales. Valero, another interested party, does have extensive retail (although the company does not own the Valero retail outlets).

Also, the Lyondell refinery was intended also to supply its petrochemical plants with feedstocks, something that, in the age of cheap shale crude and cheaper NGLs, may be more economically done on the spot market.

Much of that light shale crude ends up split into naphtha, some of which is blended into gasoline, another reason refiners will struggle.

US benzene in extreme backwardation on lack of imports, disconnects with Brent, sends hedges into disarray

HOUSTON, August 19, 2016 (PCW) -- Benzene has pushed higher worldwide during the past six weeks and has put the typically contango US market into extreme backwardation.

Since July 1, US front-month benzene has shot from $2.18/gal to $2.60/gal on Thursday, up $0.42/gal or $17.64/bbl. In the same period, September Brent has gone from $50.35/bbl to $50.89/bbl, up a mere $0.59/bbl.

The ratio of benzene to Brent in this time frame has gone from 1.8 to 2.14.

Meanwhile, gasoline in the Gulf Coast has gone from $1.4410/gal to $1.4807/gal in the same period. The NYMEX RBOB September settle has gone from $1.52/gal to $1.4897/gal, a drop of $3.03/gal.

Dearth of Imports

Clearly the US, a net importer of benzene, has been affected by a sudden dearth of imports. According to US Census Bureau statistics, in the first six months of 2016, the US imported an average of just under 1.2 million bbl/month of benzene.

In May, the imports were just over 1.0 million bbl/month and in June (the last month for which statistics are available), the figure was 740,000 bbl/month.

The drop in imports coincides with the change from contango to backwardation. On July 1, PetroChem Wire benzene assessments were July at $2.18/gal, Aug at $2.20/gal and September at $2.23/gal.

On July 16, July was assessed at $2.25/gal, August at $2.27/gal and September at $2.27/gal.

In contrast on Thursday, August benzene was pegged at $2.60/gal, September also at $2.60/gal, October at $2.80/gal and November at $2.45.

Clearly the market does not see a quick fix to this supply tightness.

But the higher US prices have opened up international arbs somewhat.

On July 1, spot assessments in Korea were about $2.11/gal, with Europe at about $2.20/gal and the US at $2.18/ gal. But on Thursday, Korea was $2.24/gal, Europe at $2.44/gal and the US at $2.60/gal through September, so it would appear benzene will head to the US.

Difficult to Hedge

One problem is that benzene is extremely difficult to hedge, as it has a dodgy relationship with crude, naphtha and gasoline. Benzene can be produced when heavier naphthas are put in a reformer, but prices don’t seem to indicate that is happening.

On July 1, naphtha was assessed by the PetroChem Wire at about $1.17/gal, $0.27/gal off gasoline. On Thursday, naphtha was $1.19/gal, $0.30 off gasoline.

One problem is that the lighter shale crudes produce lighter naphtha, which in turn, do not produce as much reformer-friendly naphtha.

Current trade in Europe is above the August contract price of $723/mt (about $2.42/gal); the same is true of the US, where the August contract price came in at 228-229 cpg ($682-685/mt).

Record gasoline imports another bearish factor for prices

HOUSTON, August 12, 2016 (PCW)  -- In last week’s blog I made a case for continued weakness in gasoline. That looked good until Wednesday when the US Energy Information figures showed a big draw -- 2.8 million barrels – in gasoline inventories. The previous week had featured a 3.3 million barrel draw.

Still on Wednesday the market fell anyway: September NYMEX RBOB was down 4.48 cpg to 130.14 cpg.

On Thursday, the International Energy Agency published its report, predicting a year-on-year growth in oil demand of 1.4 million b/d. And then a massive explosion at the Motiva refinery in Convent, La., caused the NYMEX to push up 6.03 cpg, to 136.17 cpg.

On the week the NYMEX finished at 137.09 cpg, up a mere 0.89 cpg

Still gasoline inventories are long, 19 million barrels over last year at this time. Inventories were 23 million over the year-ago period in the prior week.

Using the EIA demand figure of 9.8 million b/d, the US currently has 24 days’ supply of gasoline. In contrast, in the first week of August 2015, we had 22 days.

So in theory we are going to work down our inventories. Maybe.

But there is yet another reason – aside from the upcoming lower demand season -- why that is unlikely to happen: gasoline imports are at near all-time highs.

For the week ending August 5, the EIA showed the US imported 930,000 b/d of gasoline, compared to 683,000 b/d in the first week of August 2015, and 435,000 b/d in 2014.

The US exports gasoline mostly out of the Gulf Coast, but the pipelines that take it to the East Coast are at capacity, and because of the Jones Act, shipping is too expensive. The Jones Act requires shipping between US ports to be done by US-flag ships, not cheaper foreign flag vessels.

So the US East Coast typically gets incremental gasoline from Canada and Europe at a lower cost than it can be supplied from the Gulf Coast. European gasoline often goes to Africa, but apparently now the better netback is to bring those barrels to the US East Coast.

According to one source, European refinery netbacks are very good, so they are producing gasoline that is ending up in the US. US exports of gasoline have been steady to slightly weak, according to EIA data.

One blendstock trader added that toluene – a 106 octane gasoline blendstock – is also headed from Europe to the Gulf Coast. Those barrels originated in north Africa and were shipped to Rotterdam, where, apparently, they are not needed. The trader added: “There is more toluene headed here than you can say grace over.”

Recent gasoline strength a red herring; supply-demand situation remains loose

HOUSTON, August 5, 2016 (PCW) -- Timing is everything and mine was apparently perfect last week as I suggested gasoline would remain weak.

Of course coinciding with that blog was the news that PBF Energy was going to cut crude runs at its refineries by 6%. The company owns five refineries with a combined boilerplate capacity of 884,000 b/d.

So in the past week CBOB as assessed by the PetroChemWire is up about 8 cpg in the Gulf Coast, and NYMEX RBOB up almost 5 cpg.

Now this week comes the news that BP will take a crude unit and a fluid catalytic cracker at its giant (413,000 b/d) Whiting, Indiana, plant down for maintenance in the last half of September.

Gasoline stocks remain very high, however, at 238.2 million barrels, per the US Energy Information Administration statistics for the week ending July 29, which is 21.5 million barrels over last year.

Week on week, however, gasoline stocks drew significantly, down about 3 million barrels.

While some refiners may cut runs, others may not. One source mentioned Holly Frontier and Tesoro as being unlikely to cut runs, and Valero has indicated they will resist this as well.

The EIA tracks gasoline margins (using Brent and New York Harbor prices) and showed that last year, gasoline margins were about 52 cpg in June. This June, margins were about 35 cpg.

However 35 cpg isn't so bad. In June 2014, margins were about 23 cpg, June 2013 was 28 cpg, June 2012 was 32 cpg and June 2011 was 12 cpg.

If there are significant run cuts, crude prices will tend to fall and that should put some bearish pressure on gasoline. So such reductions by some may not be enough to boost prices.

Gasoline demand typically falls as the market heads into winter. In 2014, per the EIA, gasoline demand (on a four-week average basis) went from 9.615 million b/d to 9.169 million b/d between the first week of August and the first week of December.

Looking forward at the NYMEX RBOB spreads between September and October, the latter month marking the switch from more expensive, lower RVP summer gasoline toward less expensive winter gasoline, it seems as if the market has shrugged off gasoline strength.

RBOB Spread

On July 15, October RBOB was about 8 cpg under September; on Thursday, the spread was 9 cpg. This suggests the relative strength in the market was at the front month, but also that the fundamental relationships have not changed.

So while gasoline refinery margins are not as good as they have been in the recent past, they are not completely dire from a historical price perspective. Demand will fall as we head into winter, and although there may be run cuts, they will not be sufficient to significantly tighten the market.

Butane will be cheap and more and more of it will be allowed to be blended into finished gasoline as we head into winter.

Gasoline will remain cheap.

Around the corner from my house in southeast Houston, I can buy major-brand gasoline for $1.88/gal, up from $1.85/gal a week or so ago.

To the rest of the country, I say: read it and weep.

A hazy shade of winter (grade gasoline): Kicking the supply overhang can down the road?

HOUSTON, July 29, 2016 -- Last week’s blog (see below) pointed to the underlying weakness of gasoline: despite summer demand being high, supplies have not drawn down significantly and as the season heads to fall, gasoline is allowed to contain more cheap butane – a formula for continued weakness.

So far that prognostication -- hardly an original one -- looks pretty good. Gasoline demand, as per the US Energy Information Administration for the week ending July 22, was up 100,000 b/d to 9.8 million b/d, but gasoline inventories rose anyway by 500,000 bbls to 241.50 million bbls. Gasoline inventories stood at 241.5 million bbls, an astonishing 25.5 million over last year (215.9 million bbls), and 23.3 million over the previous year (218.2 million).

Gasoline demand is up significantly: in July 2015, it was 9.3 million bbls and in late July 2014, it was 9 million bbls. But even with higher demand, prices have fallen.

Since the previous week’s inventory reporting day, July 15, the NYMEX RBOB (September) contract has dropped 12.09 cpg to 130.11 cpg and the CBOB cash price in the Gulf Coast fell 8.84 cpg to 124.36 cpg (cash prices assessed by the PetroChem Wire).

Winter Grade Gasoline

This week, two refiners – Valero and Marathon Petroleum – acknowledged the situation and indicated some ‘other’ refiners have already switched to making winter-grade gasoline, which one cannot put on the market until late September.

In the summer, refiners make lower volatility (lower RVP) gasoline and as the market heads toward winter, they make higher volatility (higher RVP) gasoline so cars can start up more easily in the cold months.

So is the market going to ameliorate the current oversupply by creating more of an oversupply as we head to a lower demand season? Are we kicking the can down the road?

On paper, making winter-grade gasoline may make sense, even though the October NYMEX (against which the higher RVP grades will trade) is trading 8 cents below September.

Cheaper Butane

The refiner can now make the higher RVP grades, using cheap butane – assessed Thursday at the bargain-basement price of 55 cpg (!) in the Gulf Coast – and back out higher-priced octane boosters like reformate (assessed at 154 cpg by PetroChem Wire on Thursday) and alkylate (144 cpg on Thursday).

By September, it will be turnaround season, so in theory, less gasoline will be produced, perhaps allowing a modest increase in prices: the cheaper gasoline may get sold into a tighter market.

Looking at the NYMEX RBOB curve, gasoline is slightly backwardated from October to December, and then only modestly in contango through February. NYMEX WTI, however, is in contango from now and well into next year, perhaps a signal that the market thinks these low crude prices will finally result in lower production levels.

Margin Pressure

Could higher crude and flat gasoline, which in theory puts pressure on refinery profit margins, set the stage for lower refinery runs and stronger gasoline?

But another bearish factor is exports. The EIA numbers show total gasoline production last week at 10.068 million b/d; demand is 9.8 million b/d. So we would need to export about 268,000 b/d to just maintain inventories at their current high levels.

Over the past year, the net exports of products (which includes distillates) have trended lower, likely a result of the narrowing Brent/WTI spread.

What the specific gasoline data suggests is that while exports of gasoline from the Gulf Coast (typically to Mexico and South America) are stable, imports (mostly to the East Coast from Canada and Europe) have trended higher.

Long gasoline inventories are likely to be with us for some time and it is difficult to see how this can fundamentally change as we head into winter.

As gasoline demand hovers near record, prices may soften

HOUSTON, July 21, 2016 -- Gasoline demand is up and is as high as it has ever been, now coming in at 9.7 million b/d, according to last week’s US Energy Information Administration numbers.

Only a few years ago, gasoline demand was 8.6 million b/d or so, and in the good economic years before the recession of 2009, it was only about 9.5 million b/d.

Domestic crude oil production, meanwhile, is off about 1.054 million b/d versus last year, per the EIA.

So good demand and tighter crude should lead to stronger gasoline prices, one would think. The market consensus, however, is that gasoline season is over. Barring a hurricane or some other calamity, gasoline prices can’t go significantly higher and are likely to go lower.

Excessive Volumes

A combination of excessive volumes of gasoline and various naphthas, as well as other factors, will keep downward pressure on gasoline prices.

Total gasoline inventories for last week were 241 million barrels, up 16.7 million barrels over last year. In early May, total inventories were roughly 240 million barrels. This suggests while summer demand is good, inventories have still not been drawn down significantly.

Since May 2, NYMEX RBOB has dropped from 156.28 cpg to 136.37 cpg, a decrease of 19.91 cents. In the same period, Gulf Coast CBOB has gone from 141.03 cpg to 130.31 cpg, a drop of 10.66 cpg, according to PetroChem Wire data.

Again, all this took place in the summer driving season when gasoline demand was at near record levels.

Alkylate Predictor

One of the principal gasoline blending components is alkylate. It is a 92 octane, 5.5 RVP blendstock that is important for lower RVP summer grades of gasoline. Alkylate is seen by some as predictor of gasoline supply demand balances: the stronger alkylate is the more likely gasoline prices will go higher.

Since May 2, alkylate has fallen from 169.78 cpg to 154.37 cpg, along with the value of octane. The 87-93 spread has dropped from 19.75 cpg to 14.25 cpg.

As summer ends and fall begins, RVPs will rise, which means that more butane – a very high RVP blendstock – will be allowed in gasoline. Butane was assessed Wednesday by PetroChem Wire at 62 cpg.

One can think of it this way: expensive alkylate can be replaced, at least in part, by cheaper butane.

The change in RVP is reflected by the NYMEX RBOB market, where October is currently trading at 129.91 cpg, about 7 cpg below September.

So as summer gasoline demand winds down, gasoline will get less expensive to make, which should result in lower prices.