Downstream Roundup: Light Crude Abundance Changing US Refining


U.S. refiners are reducing their dependence on foreign crude oils, thanks to greater access to discounted domestic grades. Although the changing supply picture has helped U.S. refiners’ bottom line, it has also become a cause for concern, according to industry experts interviewed by DownstreamToday, Rigzone’s sister site covering the downstream side of the oil and gas value chain.

U.S. refiners have been modifying their facilities “to cope with a mismatch between crude slate and refinery configuration,” said Michael Wojciechowski, Americas director of refining and oil markets research with Wood Mackenzie. “U.S. production growth is overwhelmingly light oil, while the complex refinery configuration is optimized for heavier crudes. In response, investments have been made in crude distillation capacity expansions and in standalone condensate splitters.”

The abundance of light oil also begs the question of where that production can find a home. In March, the American Fuel and Petrochemical Manufacturers reported a third-party study found that domestic refiners have plenty of processing capacity for growing U.S.-sourced crude supplies. Meanwhile, U.S. oil producers are eager to pursue a more lucrative global market that is slowly opening up to them.

“In the coming year, exports of minimally processed condensate will increase on the heels of a clarification by the U.S. Commerce Department on the decades-oil crude oil export ban,” said Wojciechowski. “Condensate exports have renewed debate surrounding the potential removal of the ban. If the ban were removed, domestic crude oil prices would rise toward international prices, reducing the margins of U.S. refiners.”

Although lifting or weakening the crude export ban likely would chip away at the discounted crude prices relative to international markets that U.S. refiners now enjoy, the refiners should still maintain some margin advantage, said Kevin Waguespack, executive vice president with Houston-based downstream consultant Baker & O’Brien, Inc.

“The exported oil will have to seek distant waterborne markets, which will still result in price discounts and advantaged margins,” Waguespack explained. “So, there is plenty of opportunity for all refiners to overcome the logistics and processing constraints to increase the amount of light-tight oil processed in their refineries.”

Outside of the United States, refiners are facing a different set of competitive pressures.

As the highest-cost suppliers in the Atlantic Basin, refiners in Western Europe will continue to face stiffer competition from large export refineries in the Middle East, said Waguespack.

“We expect additional capacity reductions going forward” despite the fairly steady margins Europe’s refiners enjoyed throughout the recent oil price collapse period, he added. “However, at the same time, companies are making investments in the better-positioned refineries.”

Margins in Asia have also remained fairly steady during the oil price collapse but Japan has been taking steps to cut refining capacity, continued Waguespack.

“The performance of the export refineries in the region – South Korea, Singapore – will largely depend on China’s long-short position on light products,” he added.

Elsewhere, the oil price crash has curtailed capital spending, added Wojciechowski. It “has severely reduced national oil company budgets, delaying refinery investments in counties such as Mexico, Brazil, Peru, Colombia and Russia,” he said.

Read on for additional trends in various corners of the downstream world.


Cheap and abundant natural gas has been a boon to the U.S. petrochemicals industry in recent years, leading to what has been termed a “renaissance” for the domestic chemicals industry. Much of the industry’s enthusiasm has been directed toward building new ethylene cracking capacity, primarily on the U.S. Gulf Coast.

“The current build of U.S. ethylene crackers and related derivatives is the most concentrated deployment of capital and investment in the history of the U.S. petchem industry,” said Andrew Walberer, partner and leader of the Americas Chemical Practice with global strategy and management consulting firm A.T. Kearney.

The current slump in crude prices, however, has suppressed some of the petchem sector’s appetite for new ethylene cracking capacity, Walberer said. Crackers that use crude oil-based naphtha – as opposed to ethane and propane, which are derived from natural gas liquids (NGL) – find themselves more cost-competitive now that oil prices have fallen dramatically, he explained.

“The decline of oil prices has had a negative effect on petrochemical earnings of U.S.-based chemical firms as their shale gas-based feedstock advantage has been reduced versus naphtha-based competitors in Europe and Asia,” he said. “The decline in natural gas has mitigated the oil decline impact to some degree, however.”

A diminished U.S feedstock cost advantage, coupled with the startup this year of large global projects such as the Dow-Saudi Aramco Sadara complex in Saudi Arabia, could prompt petchem firms to pare down their list of 12 announced U.S. ethylene cracker projects, added Walberer.

“Some of the projects may get delayed or canceled if the owners/investors change their minds … it will be interesting to see how things play out in 2015 and early 2016,” he said. “The current volatility in global gross domestic product, combined with the uncertainty in oil, natural gas liquids and gas prices may cause some to reconsider, but we’ll get more clarity this year on how the industry looks through 2020.”


Many eyes in the North American pipeline community will continue to focus on shipping crude oil from Canada to the United States, predicted Nicole Leonard, analyst with Denver-based BENTEK Energy.

“I think that, obviously, Canada to U.S. crude oil export pipelines will continue to be a big story,” said Leonard, citing TransCanada’s Keystone XL and Enbridge’s Alberta Clipper (Line 67) expansion projects as examples. Enbridge’s Line 9 reversal, which will give Eastern Canada refineries better access to crude oil produced in Western Canada, will also continue to make headlines, she added.

Within the United States, how soon oil pipeline companies relieve shipping bottlenecks will hinge on region and oil price, Leonard added. A prolonged oil price slump would diminish the need to fill new pipelines in plays with higher production costs such as the Bakken shale formation and Denver-Julesburg (D-J) Basin, she noted.

“In the D-J and Bakken, they do need that pipeline infrastructure because they’re so reliant on rail, but the high differentials put them at greatest of not achieving as much production growth,” Leonard said. However, one oil-producing region that is in a stronger position is the Permian Basin in West Texas, she added.

“The Permian is one of the more prolific plays that will weather the storm the best,” Leonard noted. “In the Permian, they want to continue to build pipelines.”

In regard to natural gas pipeline capacity, much of the infrastructure build-out should continue in the Eastern U.S., continued Leonard. Gas supplies from the Marcellus Shale will need to reach the East Coast LNG export terminals as well as industrial facilities in the Southeast, she explained, adding that low gas prices could prevent midstream companies from optimizing new infrastructure.

“Whether the pipelines will all be full, that’s a risk they’re taking,” she said. “In the Northeast, what we’re seeing is so many pipeline projects have been announced in the last year that there’s a very real chance of overbuilding natural gas pipelines. Still, there is a need to increase pipeline capacity between the Northeast and Southeast.”

Industrial demand growth in Mexico should also necessitate new natural gas pipeline capacity from the United States to its southern neighbor, Leonard said.


Because the price of liquefied natural gas (LNG) is tied to that of crude oil, the momentum behind some large LNG export projects in Australia, Canada and the United States has faltered over the past year. However, the developer of a smaller-scale liquefaction project on the Texas Gulf Coast expresses optimism about the long-term outlook for projects with a solid economic footing.

“The volatility of oil and natural gas prices presents both a challenge and an opportunity,” said Kathleen Eisbrenner, founder and CEO of NextDecade, LLC, which is developing the Rio Grande LNG project in Brownsville, Texas. “On one hand, projects that were originally marginally viable are no longer viable, and the market will see them being eliminated or postponed. Meanwhile, those projects with robust economics will continue to be viable at low oil prices, making them even more attractive and viable.”

Eisbrenner is also bullish about the long-term attractiveness of LNG on the energy market.

“LNG continues to enjoy the key benefits associated with natural gas as a feedstock,” she explained. “Its abundance and diverse applications, among other factors, means it will compete very well with other sources of energy.”

In the nearer term, Eisbrenner will be paying close attention to the volatility of oil and natural gas prices.

“One particular topic to watch is how Henry Hub-denominated pricing will hold up versus oil and Japan Crude Cocktail (JCC) pricing with customers,” she said. The JCC index is often used in long-term LNG contracts.


U.S. crude oil inventories have been steadily rising into record territory, and there is a very real possibility that all of the country’s land-based oil storage facilities will run out of capacity in 2015, according to a Houston-based oil markets expert.

“The market is very fluid at this time, but I expect to see storage continue to grow for some time to come,” said Brian Busch, oil markets and business development director with Genscape, Inc.

The change in the forward price curve structure for crude oil – not the recent steep drop in the price of oil – is motivating oil storage facilities to build inventories, Busch noted. The price curve has moved to contango, which occurs when crude oil commands a lower price via near-term spot purchases compared to longer-term futures contracts, he explained. Backwardation, the opposite of contango, is a disincentive to building oil stocks. It occurs when crude oil is relatively scarce and commands a higher price in the short term.

“At current rates, (the U.S. oil storage hub) Cushing, Oklahoma, could be operationally full sometime in early May,” said Busch. “It would take several months before all the on-land storage in the United States would become operationally full, but we could see it happen in this calendar year.”

Oil storage providers are working to relieve the situation by adding new capacity – roughly 40 million barrels in Petroleum Administration for Defense District (PADD) 3 (Gulf Coast) alone, Busch noted.

“This will include a couple of new terminals, all of which will have access to water transportation,” he said. “However, ultimately, storage can’t resolve the situation. Eventually, supply and demand will have to rebalance.”





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