The recent approval of the Dakota Access Pipeline and rising Permian production is expected to leave Asian refiners spoilt for choice as more US light crude oil from the Gulf of Mexico becomes available to them.
Once Dakota Access comes online, roughly “couple of hundred thousand barrels per day of US light oil could be available by capacity for exports,” said Takayuki Nogami, chief economist at Japan Oil, Gas and Metals National Corp.
Nogami said more US light oil could be available for exports as US refiners in the Gulf generally process medium to heavy grades.
The delayed 470,000 b/d Dakota Access Pipeline received final federal approval in early February to complete construction, and start up is targeted between March 6-April 1.
The four-state $3.8 billion pipeline is designed to deliver Bakken and Three Forks crude to Patoka, Illinois, where it will connect with the Energy Transfer Crude Oil Pipeline to Texas, leaving more crude available for export from the Houston terminals.
The Permian is the US’ most active crude play by far and the site of most of rig count increases. Production at the Permian Basin has been climbing steadily since September and is projected to reach 2.25 million b/d in March, according to the US Energy Information Administration.
A number of refiners in China, Japan and South Korea said that they are closely watching the developments and will consider importing more light oil and possibly sour grades from the US whenever they became competitive against their main sour crude imports from the Middle East.
“We will definitely watch this [development over the Dakota Access Pipeline and increasing US oil production] and seek more opportunity,” said a refiner in South Korea.
“Our principle has not changed. We intend to buy attractive [crudes] from around the world, regardless of whether they are from the Gulf of Mexico or the pipeline coming onstream,” said Jun Mutoh, president of Japanese refiner TonenGeneral, an active buyer of US oil including WTI crude and shale.
Gaven Chen, a senior refining engineer with China’s state-owned Sinopec, said he expected US refiners will need at least five years to complete their infrastructure reform to crack shale oil, which could result in more availability of light oil for exports until around 2022.
NO INFRASTRUCTURE CONSTRAINTS
A buildout of pipelines and rising production means that exports of US crudes to Asia will not be limited by infrastructure constraints, said Sandy Fielden, director of oil and products research at Morningstar.
But Fielden said the volumes will eventually depend on price.
“You’ve got a potential for exports into the Asia market, and you’re seeing the first talk of exports of offshore Gulf of Mexico sour crude like Southern Green Canyon potentially going to Asia to make up for a lack of barrels due to the OPEC cuts,” Fielden said.
“There’s going to be circumstances where the price is right and the arbitrage opens up, but I’m thinking this is kind of a sporadic — it’s based on circumstance, it’s not going to be a big, sudden opening up of the market that results in a massive outpouring of crude from the Gulf Coast,” he said. “It’s all going to depend on the relative price.”
Some of the US light oil production could also be used for blending with heavier grades, said Nobuo Tanaka, former executive director of the International Energy Agency.
So increasing availability and production of US light oil production may not necessarily lead to a spike in crude exports, although the current crude price is supporting incremental shale oil production, he added.
Currently, pipelines can transport 1.85 million b/d of crude into the Houston area from offshore Gulf of Mexico and Texas oilfields, including the Permian Basin and Eagle Ford, according to Morningstar. Another 1.55 million b/d of crude can be shipped through pipelines originating at Cushing.
In the next year, an additional 500,000 b/d of pipeline capacity from the Permian Basin to Houston will come online, including the expansion of the BridgeTex pipeline and a new Enterprise Products Partners project.
Export capacity is rising at Corpus Christi, where Occidental Petroleum inaugurated its 200,000 b/d Ingleside export terminal in 2016. Plains All American plans to expand its Cactus pipeline by 140,000 b/d to 390,000 b/d this year, supplying more Permian crude to Corpus Christi export terminals.
RISING US CRUDE SUPPLY TO ASIA
Following the December 2015 US Congress decision to lift crude export restrictions, US crude exports to Asia skyrocketed from just 4,000 b/d in 2015 to 54,000 b/d in 2016, according to US Census Bureau data. China received 23,000 b/d of US crude in 2016 and shipments also arrived in Japan, South Korea, Singapore and Thailand.
This year Chinese independent refiners have started buying US crudes, with 2 million barrels of Mars and Thunderhorse crudes arriving in April, according to market sources. Until last year, only state-run refiners imported US crudes in China.
A widening Dubai premium to WTI and refinery maintenance season in the US are likely to keep export demand healthy in the near term.
A significant amount of coking capacity is currently under maintenance in the region, meaning that previously hard to find grades, like Mars and Southern Green Canyon, may be available for export, market sources said, adding that sour grades have departed the USGC for North Asia in recent weeks.
WTI FOB Houston differentials point to heightened export demand in recent months. The differential rose to average front-month NYMEX WTI plus $2.35/b in December and plus $2.34/b in January, up from plus $1.73/b in November.
The tightening of the Dubai crude market following OPEC’s coordinated supply cuts has led Dubai crude to flip to a premium to WTI in recent months, making US crude more competitive in Asian refineries.
Dubai’s premium to WTI widened to average 95 cents/b in January and $1/b in February, leading many Asian crude buyers to look beyond the Middle East for supply.
The lack of demand for Middle East sours is reflected in weak forward freight rates.
Persian Gulf-Far East VLCC rates declined to $10.47/mt in January from $12.96/mt last December as the Dubai/WTI spread widened.
The market continues to expect weak demand going forward, with February rates to date averaging $8.78/mt.
By comparison, US Gulf Coast-Asia Suezmax freight has held firm, averaging $23.27/mt and $23.94/mt in December and January, before dipping slightly to $21.39/mt in February.
A Suezmax fixture is the latest example of increasing inquiries for Asia. Mercuria was reported to have put the Tony on subjects to lift a 130,000 mt crude cargo for a USGC-Singapore voyage loading March 1.
“USGC to East is the new hot thing,” said a shipbroker.
An industry source said the Suezmax market on Far East runs should continue to firm as tonnage remained tight in the Gulf of Mexico and traders were looking to ship cargo to the East.