July 3, 2014
EIA Monthly Numbers Show Surprisingly Robust Gasoline Demand

The conventional wisdom in the downstream petroleum business holds that the Energy Information Administration (EIA) has been overstating gasoline demand for much of 2014. But data that was quietly released by EIA on July 1 suggest that government data gatherers may have actually been underestimating actual demand.

This week saw final monthly data for April 2014, and EIA measured demand that spring month at 8.979 million b/d, reflecting a stunning 295,000-b/d leap from March and a 233,000-b/d increase from April 2013. But even more striking was the difference between gasoline demand levels implied by the five weekly reports that overlapped various April dates. Those weekly numbers suggested demand of only about 8.658 million b/d, or 321,000 b/d less than what now goes into the record books in the higher resolution monthly assessment.

The numbers may offer comfort to analysts who believe that multi-month assessments of gasoline demand often auger well for the U.S. economy. But others have become increasingly uncomfortable with the weekly bulletins that are issued each Wednesday morning. One veteran market watcher cited the tendency for "more noise from the weeklies" that may lower the value or the impact of the Wednesday reports.

The final April numbers represent the highest level for that month's demand since 2010 when gasoline deliveries were estimated at 9.108 million b/d. Since there is normally demand "lift" from April to May and June, the data points to numbers that may consistently be well above 9 million b/d through the driving season.  

When the April numbers are added to the first three months, one can calculate that the first third of 2014 saw gasoline demand of 8.638 million b/d, compared with 8.503 million b/d last year. Projected over an entire year, that 1.59% increase could push 2014 demand up by about 135,000 b/d. The final demand estimate for all of 2013 was 8.774 million b/d.

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July 1, 2014
WTI Slumps in Some Source Markets

WTI futures have withstood some selling pressure in recent sessions, but prices for the benchmark grade near the fields where it is produced in West Texas have slumped.

Sources credit production gains in the Permian Basin that they believe are outpacing predictions, but they also note that refinery issues in the region can strand additional supply. In the last week, OPIS confirmed that Valero had a brief power outage at its McKee, Texas refinery and Phillips 66 has had a coker down at its Borger, Texas, facility.

Yesterday, WTI near Midland, Texas, for August shipment moved several times at an $8/bbl discount to NYMEX futures, putting the value at about $97.75/bbl based on this morning's August futures quote of $105.75/bbl. There was also some September business conducted at a more modest $5.75/bbl off September futures, which based on the September print of $105.10/bbl, works out to $99.35/bbl.

This leads to the rare situation where a company with vacant storage in the area actually could make money by "carrying" the August barrels and shipping them in September, although observers doubt whether any bulk storage is available.

The lower September numbers reflect the view that a couple of additional pipelines that move crude from the Midland area to Houston destinations will come online this summer.

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June 23, 2014
Volatile RIN Values Put Importers of European Gasoline on Defensive

The volatile RIN values in the past week have kept European gasoline arbitrage players on their toes, contributing to the already weak economics for imported cargoes into the U.S. East Coast, traders told OPIS on Monday.

Ethanol RINs jumped to a high of 64-65cts last week, possibly due to confusion over the timing of EPA's release of the final 2014 Renewable Fuel Standard rule. However, RIN retreated early on Monday to about 54cts. RIN was stable at around 30cts earlier this year.

Gasoline importers are required to buy RINs for their imported cargoes from Europe. Based on the current RIN price of about 5.5cts, importers are to pay about 5.1cts/gal for one 300,000-bbl imported cargo.

The higher RIN cost may add only a few cents per gallon to the arbitrage economics, but arbitrage players also have to factor in freight and port costs, supply costs, prices at destinations and time value of money. The arbitrage window for European gasoline imports into the U.S. is viewed as mostly closed early this week.

Apart from the higher RIN value, the New York Harbor physical gasoline market is
receiving a steady inflow from Europe, and a few cargoes remain unsold for late June and early July.

The average gasoline imports into the U.S. in June have been higher than a year ago.

Average gasoline imports for the four weeks ended June 13 were at 723,750 b/d versus 618,500 b/d for the corresponding four weeks in 2013, according to the Energy Information Administration.

Some traders said that there have been some F1 RBOB grade barrels being shipped on Colonial Pipeline to New York Harbor, in addition to the bulk delivery of M2 conventional regular grade.

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June 19, 2014
Analysis: US Export Terminal Projects Offer Outlet to Rising Refinery Output

The U.S. is enjoying a renaissance in domestic oil and gas production, leading to the arguably best refining margins in the past five years and robust refinery utilization rates across the country.

While domestic demand remains mostly flat and restrictions on U.S. coastal shipping, U.S. refiners and natural gas liquids producers are focusing on export outlets. The U.S. allows free exports of oil products, but the current ban on crude exports remains a talking point. To capitalize on this ongoing and growing need for international sales, many logistics companies have jumped on the bandwagon to build new marine docks and export-focused terminals.

Kinder Morgan is building a products export terminal in Houston, and Enterprise is constructing an ethane export facility on the Houston Ship Channel. Sunoco Logistics is to begin exporting propane and butane from its Nederland terminal next year.

The concentration of these marine export outlets are on the Gulf Coast, mainly due to the significantly higher refining capacity than other regions in the U.S. The PADD3 refining capacity is pegged at 9.154 million b/d. The PADD3 refiners are a regular supplier of products to the net-short PADD1 region, but that south-north flow is limited by pipeline capacity and the Jones Act restriction on U.S. coastal shipping voyages.

"Crude production in West Texas and North Dakota is growing, and the demand is not (growing). There is a lack of arbitrage opportunities because of the Brent price premium over WTI," a logistics player said.

"The U.S. is focusing on exports of distillates, other oil products, ethane, propane and butane," he said.

Another player said that there are currently enough marine docks on the Gulf Coast, but additional docks will help reduce the growing waiting time for ships and long lines amid the rising products export trend. It will also help speed up cargo loading and vessel turnarounds, reducing demurrage and improving shipping and arbitrage economics.

Export Is Key

This summer, Kinder Morgan will start construction on its 1.2-million-bb Houston oil products export terminal project near Lydondell refinery. The $169.5-million terminal is scheduled to be operational in the first quarter of 2016.

Kinder Morgan is also building another three to four greenfield marine docks on the eastern side of the Houston Ship Channel for export purposes. Each dock costs $25 to $30 million to build.

Enterprise Products Partners LP will build an ethane export facility on the Houston Ship Channel. Enterprise has signed a 30-year agreement with the Port of Houston Authority for use of facilities adjacent to Enterprise's existing Morgan's Point terminal.

The ethane export facility is expected to begin operations in the third quarter of 2016.

In May, Enterprise loaded the first cargo of refined products for export from its reactivated marine terminal in Beaumont, Texas. Located on the Neches River, the terminal can load at rates up to 15,000 barrels per hour.

Sunoco Logistics is focused on shipping crude at its Nederland terminal for both domestic and international deliveries. U.S. crude exports are mainly for Canada, but in the past year, the U.S. government has granted export licenses for Canadian crude to the rest of the world.

So far, the Canadian crude export flow out of the Gulf Coast remains sluggish despite the license approval. This could depend on international prices and demand. Also, exporters have one year to use the licenses, which are based on value of the total exports.

Apart from crude, Sunoco Logistics is also working on propane and butane exports out of Nederland terminal for next year. The terminal will receive natural gas liquids supply from Mont Belvieu.

In February, NuStar Energy L.P. completed construction of a private marine loading dock at its North Beach Terminal in Corpus Christi, Texas, and had its first ship at the dock to be loaded with crude oil. Originally scheduled to be completed in the second quarter of this year, NuStar expedited the project in order to meet strong customer interest in using the dock to transport shipments of Eagle Ford crude oil by water.

With this new dock, NuStar now has three loading docks in the Port of Corpus Christi, and can load crude oil onto ships simultaneously on all three docks. NuStar also completed major additions and upgrades to the terminal's pump systems. With all of these upgrades, the North Beach terminal's marine loading capacity was more than tripled to 400,000 b/d.

Oiltanking and Houston Fuel Oil Terminal Company have spare marine docks and terminal space which could be used for exports. The U.S. is facing a declining crude import volume, and the fuel oil trading has been lackluster and challenging on a weak demand. Oiltanking is focused on crude storage and HFOTC is on fuel oil and crude.

Trafigura Terminals LLC is an 84-acre industrial site in Corpus Christi, Texas, consisting of approximately 600,000 barrels of storage for crude oil, fuel and condensate. It began construction of a second oil dock in early 2013. Besides crude and fuel, Trafigura terminal is also involved in LPG exports.

In the Northeast, the refiners and logistics players are also seeing a push for oil products, especially distillates, but that outflow is significantly less than the Gulf Coast due to the comparatively smaller refining capacity and the growing local market demand for ultra-low-sulfur diesel.

In the near future, logistics companies are also eyeing possible condensate exports, depending on a lifting of the current export ban. Some players remain optimistic on the lifting of condensate export ban, but there has been no definitive word on that so far.
Also, it is noted that the U.S. is seeing the liquefied natural gas export trend moving forward as more permits are granted for expensive LNG terminal construction.

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June 11, 2014
Five Northeast States May See 7cts/gal Heating Oil Price Spike July 1

Heating oil buyers in Massachusetts, Vermont, New Jersey, Rhode Island and Connecticut are expected to see a significantly higher price on July 1, following the expected switch to the new 500-ppm maximum sulfur content heating oil from 2,000 ppm high-sulfur heating oil, some major heating oil suppliers told OPIS on Wednesday.

Some suppliers were speaking on the sidelines of New England Fuel Institute Visions conference held in Worcester on Wednesday.

Heating oil prices in the five Northeast states would jump by about 7cts/gal on July 1, based on this week's price gap of about 8cts/gal between ultra-low- sulfur diesel and No. 2 heating oil. It is noted that this estimated price jump could vary on July 1, based on the actual price spread on that day.

While the blending cost of the new 500-ppm heating oil should translate to higher street prices, Northeast refiners may trigger a price war as they could hold a price advantage over other non-refining suppliers.

Refiners may absorb all or most of the blending cost spike for blending a lower sulfur content fuel due to their refining economics. The higher blending cost could be factored into their refinery's overall strong margins instead of passing it on to buyers.

Some refiners offering a substantially lower sulfur content fuel than the state 500-ppm requirement, such as ULSD, may be perceived as leaving a lot of money on the table due to the current wide hi-lo spread. However, this may also not be the case as refiners have the flexibility to eat the "perceived higher blending cost" by adding that cost to their refining margins.

Those suppliers supplying 500-ppm heating oil should have a substantial price advantage over those supplying 15-ppm fuel, based on the current wide price spread between ULSD and No. 2 heating oil.

In theory, the 500-ppm heating oil could be blended with about 80% of ULSD and 20% of No. 2 heating oil, helping to put an estimate on the price tag of the non-existent fuel.

With just a few weeks to go, no suppliers or refiners are offering a new 500-ppm blend yet, but all suppliers said that they will comply with the more stringent lower sulfur requirements by July 1.

So far, there is no 500-ppm physical trading or contract in the New York Harbor or in New England.

Suppliers said that heating oil buyers may get 15-ppm to 500-ppm sulfur content fuel in July.

However, some players maintain that a significant price spread would incentivize blending of the new 500-ppm boutique fuel.

Some, including Gulf Oil, will blend high-sulfur and ultra-low-sulfur diesel to produce the new 500-ppm spec fuel, and some, including PBF Energy, will offer 15-ppm ULSD to meet the new mandate.

The choice of offering ULSD or blending a new 500-ppm fuel to meet the mandate remains debatable, depending on the potentially lucrative blending margin of No. 2 heating oil and ULSD in winter versus the logistics benefits of offering a fungible ULSD grade.

Blenders said that even a small blending margin of a few cents per gallon could offer a price advantage over those who are offering ULSD in the new 500-ppm markets.

Suppliers opting for ULSD expect the cost benefits of maintaining one fungible grade in their systems to outweigh the unpredictable blending margin.

Some Sprague customers told OPIS that Sprague is retaining flexibility to offer 500-ppm heating oil and/or ULSD in those four Northeast states later this year, aiming to capture a potential blending profit margin for the new 500-ppm heating oil grade.

The decision to supply either grade to meet the new state sulfur cut mandate will depend on the price spread between No. 2 heating oil and ULSD next winter.

The price spread between ULSD and No. 2 heating oil was very narrow at close to parity in December-February for the past winter. This effectively eliminates the blending margin for a new 500-ppm heating oil grade.

However, it is noted that that price spread or margin is unpredictable for the next winter.

Also, some suppliers expressed concerns about securing a stable supply of high-sulfur heating oil in the five states and possible logistics issues due to the state sulfur cut.

So far, there has been no physical trading of spot 500-ppm heating oil, but this may change later this year before the next peak winter season.

Trading volume for heating oil in the off-peak summer months is significantly lower than the peak winter season.

It is also possible for suppliers and refiners to deliver pre-blended 500-ppm barges from New York Harbor to New England when demand picks up later this year.

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June 10, 2014
Northeast to See Emergence of New 500-ppm Heating Oil

Suppliers will offer and post daily prices for the new 500-ppm maximum sulfur content heating oil in Massachusetts, Vermont, New Jersey, Rhode Island and Connecticut in July, and there will be a new 500-ppm blend in the market, some marketers told OPIS on Tuesday.

Currently, the Northeast market does not have a 500-ppm heating oil blend.

So far, all suppliers are prepared to meet the new sulfur cut mandate for the five states, but not all will blend and make the new 500-ppm product.

Some, including Gulf Oil, will blend high-sulfur and ultra-low-sulfur diesel to produce the new 500-ppm spec fuel, and some, including PBF Energy, will offer 15-ppm ULSD to meet the new mandate.

The choice of offering ULSD or blending a new 500-ppm fuel to meet the mandate remains debatable, depending on the potentially lucrative blending margin of No. 2 heating oil and ULSD in winter versus the logistics benefits of offering a fungible ULSD grade.

Blenders said that even a small blending margin of a few cents per gallon could offer a price advantage over those who are offering ULSD in the new 500-ppm markets.

Suppliers opting for ULSD expect the cost benefits of maintaining one fungible grade in their systems to outweigh the unpredictable blending margin.

Some Sprague customers told OPIS that Sprague is retaining flexibility to offer 500-ppm heating oil and/or ULSD in those four Northeast states later this year, aiming to capture a potential blending profit margin for the new 500-ppm heating oil grade.

The decision to supply either grade to meet the new state sulfur cut mandate will depend on the price spread between No. 2 heating oil and ULSD next winter.

The price spread between ULSD and No. 2 heating oil was very narrow at close to parity in December-February for the past winter. This effectively eliminates the blending margin for a new 500-ppm heating oil grade.

However, it is noted that that price spread or margin is unpredictable for the next winter.

Also, some suppliers expressed concerns about securing a stable supply of high- sulfur heating oil in the five states and possible logistics issues due to the state sulfur cut.

So far, there has been no physical trading of spot 500-ppm heating oil, but this may change later this year before the next peak winter season.

Trading volume for heating oil in the off-peak summer months is significantly lower than the peak winter season.

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