Title : Monday, November 13, 2017
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Monday, November 13, 2017
Active rigs:| $56.81→ | 11/13/2017 | 11/13/2016 | 11/13/2015 | 11/13/2014 | 11/13/2013 |
|---|---|---|---|---|---|
| Active Rigs | 52 | 38 | 64 | 188 | 182 |
RBN Energy: crude export growth and gulf coast infrastructure needs.
Since the ban on exports of U.S. crude oil was lifted in December 2015, export volumes have soared, and for the week ending October 27, 2017, they surpassed 2 million barrels/day (MMb/d) for the first time ever, according to Energy Information Administration (EIA) statistics.
And while exports slowed last week, it is clear that there’s more to come. But the pace of export growth depends on many things, including the ability of Gulf Coast infrastructure to receive and store increasing volumes of West Texas Intermediate (WTI),
SCOOP/STACK, Bakken and other crudes and load it onto ships — the bigger the ship the better. Fortunately, coastal Texas and Louisiana already had extensive crude-related infrastructure in place when the export ban ended just under two years ago, and elements of that have been repurposed to handle exports. Will it be enough? Today, we begin a new blog series on existing and planned storage facilities and marine terminals targeted to support rising U.S. crude oil exports.
In response to the 1973-74 oil crisis, the U.S. government in 1975 implemented a ban on the export of most U.S.-sourced crude oil — the only exceptions being oil from Alaska, oil exported to Canada, heavy oil from California and very limited trades with Mexico.
Crude exports already had been minimal (only a few thousand barrels/day, on average) when the ban was put in place — in fact, exports actually rose in the late 1970s as Alaska North Slope (ANS) production kicked in (exports peaked, for the time, at 287 Mb/d in 1980). By the early 2000s, though, ANS was on the decline and crude exports amounted to a drop in the bucket, averaging less than 30 Mb/d. With the Shale Revolution, U.S. production of crude oil (including condensate — the ultra-light crude produced in a number of tight-oil plays) started rising, and by 2014, U.S. producers provided most of U.S. refiners’ need for lighter grades of oil, reducing the need for imported light crude in the process. (The increasing availability of heavy western Canadian crude to U.S. refiners also trimmed the need for overseas imports of heavier crude.) As U.S. production continued to rise, stockpiles of lighter crudes built up and the spread between West Texas Intermediate (WTI; the key benchmark for U.S. light crudes) and international benchmark Brent widened.
Some relief for U.S. producers came in June 2014, when the U.S. Commerce Department broadened its definition of refined products (whose export was never banned) to include condensate that was minimally processed (run through a stabilizer or other unit so it could be called “processed condensate”). Exports of processed condensate took off, peaking in December 2015 (the month the crude export ban was lifted) at more than 150 Mb/d. But processed condensate couldn’t be counted as crude exports — after all, it was processed.
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