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As of January 1, 2019, U.S. operable atmospheric crude oil distillation capacity was a record-high 18.8 million barrels per calendar day (b/cd), an increase of 1.1% since the beginning of 2018, according to EIA’s annual Refinery Capacity Report. The previous high of 18.6 million b/cd was set at the beginning of 1981. U.S. annual operable crude oil distillation unit (CDU) capacity has increased slightly in six of the past seven years. Operable capacity includes both idle and operating capacity.

Refinery capacity is measured in two ways: barrels per calendar day and barrels per stream day. Barrels per calendar day reflect the input that a distillation unit can process in a 24-hour period under usual operating conditions, taking into account both planned and unplanned maintenance.

Barrels per stream day reflect the maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude oil and product slate conditions with no allowance for downtime. Stream day capacity is typically about 6% higher than calendar day capacity.


Source: U.S. Energy Information Administration, Refinery Capacity Report

EIA’s Refinery Capacity Report also includes information about secondary refining units—downstream refinery units that process the products coming from the atmospheric crude oil distillation unit into ultra-low sulfur diesel, gasoline, and other petroleum products. Secondary refining capacity, including thermal cracking (coking), catalytic hydrocracking, and hydrotreating and desulfurization, increased by less than 1% from year-ago levels.

The number of operable refineries remained at 135 on January 1, 2019; however, similar to last year’s report, four refineries previously considered separate in survey data were merged into two. Tesoro Refining & Marketing’s Carson and Wilmington plants (now owned by Marathon) in California combined operations, and the Par Hawaii and Island Energy Services plants in Kapolei, Hawaii, also merged.

Targa Resources started up a new condensate splitter in Channelview, Texas, in 2019 that was idle at the start of the year but began operating during the first quarter. Suncor Energy split its reporting of the Commerce City East and West plants in Colorado.

Marathon Petroleum Corporation acquired 10 refineries from Andeavor in 2018, making it the largest refiner in the United States. Marathon’s refineries collectively have an operable capacity of slightly more than 3.0 million b/cd, 16% of total U.S. refining capacity and about 800,000 b/cd more capacity than the second-largest refiner, Valero Energy Corporation.

Refinery runs and crude oil production both continued at record levels in the United States in 2018. U.S. crude oil production, which averaged 11.0 million barrels per day (b/d) in 2018, has more than doubled since 2009. Crude oil inputs to refineries averaged 17.0 million b/d in 2018 compared with 14.3 million b/d in 2009.

Since 2009, operable refinery crude oil distillation capacity increased 1.2 million b/cd, and utilization rose from 83% in 2009 to 93% in 2018, resulting in the 2.6 million b/d increase in crude oil inputs. During the same period, U.S. crude oil imports decreased by 1.3 million b/d, and U.S. crude oil exports increased by 2.0 million b/d, leading to an overall decrease in net imports of 3.3 million b/d.


Source: U.S. Energy Information Administration, Refinery Capacity Report
Note: Differences between crude oil inputs and the sum of production and net imports reflect inventory changes and unaccounted for crude oil.

Note: Differences between crude oil inputs and the sum of production and net imports reflect inventory changes and unaccounted for crude oil.
EIA’s Refinery Capacity Report also includes information on capacity expansions planned for 2019. Based on information reported to EIA in the most recent update, U.S. refining capacity will not expand significantly during 2019. A June 21 fire at the 335,000 b/cd capacity Philadelphia Energy Solutions refinery complex, the largest refinery on the East Coast, has resulted in its announced closure.

Further investment in U.S. refinery expansion projects depends on expectations about crude oil price spreads, the characteristics of the crude oils produced, product specifications, and the relative economic advantage of the U.S. refining fleet compared with refineries in the rest of the world.

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US crude exports hit new high; more Permian crude expected in Gulf


US crude oil exports are expected to remain high moving forward as a new wave of Permian Basin crude oil hits the Gulf Coast in coming months.

Crude exports out of the US hit an all-time high of 3.77 million b/d in the week ended June 21, according to data released Wednesday from the Energy Information Administration, breaking the previous record high of 3.607 million b/d set during the week ended on February 15.

The latest record week was an increase of 350,000 b/d to the week ended June 14, which saw 3.422 million b/d exported, according to the EIA. Furthermore, last week marked the fifth consecutive week in a row at US crude exports exceeded 3 million b/d, which could become a new normal for export volumes.

The jump in exports and its rather steady level at or above 3 million b/d comes at a time when multiple pipeline projects are underway to bring more crude directly from the Permian to the Gulf Coast.

A collection of three new crude pipelines, including the EPIC interim crude line, are expected to start up between now and the end of the year. Together, the lines will have capacity to move an additional 2 million b/d of crude from the Permian Basin to the Gulf Coast.

Linefill on the 400,000 b/d EPIC line was expected to begin in late June, with anticipated startup in July. EPIC will move crude from the Permian Basin to Corpus, Christi, Texas.

Plains All American’s 670,000 b/d Cactus 2 pipeline also will move crude from the Permian to Corpus Christi and is expected to be operational in the third quarter.

Phillips 66’s Gray Oak, with connections to Corpus Christi, Sweeny and Houston is set to start in October, according to sources.

As Gulf Coast refinery demand for light sweet crude is at its maximum level, many of the additional barrels reaching the region will be exported, but in order to exported, the prices on the Gulf Coast must be appealing to international buyers.

“More pipelines coming on means more supply gets to the Gulf Coast with nowhere to go,” a broker said.

Pipelines out of the Permian currently carry more than 4 million b/d of crude to market, which is right around current Permian production of 4.1 million b/d. S&P Global Platts Analytics forecasts Permian production to reach roughly 5 million b/d by the first quarter 2020. With additional pipes coming online, however, there will be sufficient takeaway capacity in the Permian through 2020.

As more crude reaches the Gulf Coast there will be a growing need to increase storage and export infrastructure. Currently, 22 facilities across three Gulf Coast states have the ability to export nearly 6 million b/d, according the Platts data. And there are more projects in the works to meet growing demand. By 2021, Gulf Coast export capacity could reach over 10 million b/d.

For US crude barrels to find buyers on the international market, they must remain competitive and reactive to changes in arbitrages. This is exactly how values for US crude on the Gulf Coast have responded.

Despite large crude stock draws and increased refinery inputs and utilization in the USGC reported last week, which might typically be bullish for oil prices as it points to a decrease in supply, differentials for Gulf Coast grades have remained rather weak.

August barrels of West Texas Intermediate at the Magellan East Houston terminal were heard to trade Wednesday morning at their lowest level since October 23, at a $4.25/b premium to cash WTI. That is a dramatic decline in values. The 30-day rolling average for front-month MEH has been about $6.88/b.

According to market participants, values for crudes along the Gulf Coast, including WTI MEH, are greatly influenced by the change in the Brent/WTI spread. As the spread narrows, it is indicative of US exports becoming less competitive on the international market in comparison to their Brent-based competitors.

Over the last 30 trading days, the swap spread has average $7.86/b, according to data collected by S&P Global Platts. On Tuesday, the swap spread was $6.38/b.

But softer differentials have helped to keep the arbitrage open for crude exports. According to Platts Analytics data, the MEH and Eagle Ford arbitrages to both Northwest Europe and Singapore are currently open.

Strong exports combined with high crude runs have reduced USGC crude inventories.

In the week ended June 21, PADD 3 stocks saw a 6.26 million-barrel draw, according to weekly data from the EIA. Moreover, in the week ending on June 14, PADD 3 stocks saw a 5.83 million-barrel draw, bringing the total draw over the past two weeks to over 12 million barrels, EIA data showed.

Net inputs into PADD 3 refineries increased by 280,000 b/d in the week ending on June 21 to just under 9.3 million b/d, according to EIA data. This increase in net inputs brought PADD 3 refinery utilization up 2.4% to 96.1%, the highest level since early January, EIA data showed.

Edited by ceo_energemsier

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