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Last Updated: March 6, 2017
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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.

HEIGHTENED ACTIVITY

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.

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U.S. Federal Gulf of Mexico crude oil production to continue to set records through 2020

U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.

Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.

In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.

Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.

anticipated deepwater Federal Gulf of Mexico field starts

Source: Rystad Energy

Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.

Brent crude oil price and U.S. Gulf of Mexico rig count

Source: U.S. Energy Information Administration, Thompson Reuters, Baker Hughes

Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.

October, 17 2019
Crude oil used by U.S. refineries continues to get lighter in most regions

API gravity of U.S. refinery inputs by region

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

The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.

API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.

The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.

Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.

Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.

lower 48 states production of crude oil by API gravity

Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report

When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.

Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.

By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.

U.S. refinery inputs by region

Source: U.S. Energy Information Administration, Monthly Imports Report and Monthly Refinery Report

East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.

October, 14 2019
Your Weekly Update: 7 - 11 October 2019

Market Watch  

Headline crude prices for the week beginning 7 October 2019 – Brent: US$58/b; WTI: US$52/b

  • As Saudi Arabia confirms that it has ‘fully restored’ its crude output, the effects of the attack on the Abqaiq facilities has faded, with the market now turning its focus to the restarted US-China trade talks in hope that a deal can be reached
  • Optimism is not high that a deal can be struck, and the spill over effects on global oil demand and the global economy high, with the IMF having downgraded its projections for global economic growth five times in the last 18 months
  • In OPEC, another blow has been dealt, as Ecuador will quit the organisation in January 2020; linked to ongoing economic unrest, Ecuador states that it is being ‘honest with itself’ over its ability to adhere to the supply deal, prioritising increasing revenue over membership of the oil group
  • There is every chance that Ecuador may return to OPEC once the political situation calms down, with previous members Gabon and Indonesia having also withdrawn and re-entered the club; however, this symbolic exit will raise questions about OPEC’s ability to control and balance supply
  • Given this, Nigeria has reiterated that OPEC is ready to make deeper cuts if necessary if crude oil prices continue to tumble, prioritising market stability
  • The persistent decline of the US active rig count continues, as Baker Hughes data shows the net loss of another five rigs last week; all losses were inland rigs, pointing to consolidation and improved productivity in the sector
  • Rangebound trading should be expected in the short-term, unless an unlikely breakthrough in the US-China trade war happen; Brent should continue to trade in the US$58-60/b range, while WTI maintains its discount at US$53-55/b


Headlines of the week

Upstream

  • Brazil’s planned offshore auction for November is already attracting major attention, with 14 companies registered for acreage in the Buzios, Atapu, Itapu and Sepia blocks that contain proven reserves of at least 5 billion barrels, with the potential for at least 6 billion barrels more
  • Aker BP’s Valhall West Flank platform in the North Sea – tapping into 60 million barrels - will start up this year after approval by the watchdog
  • Angola will be offering nine blocks – 11, 12, 13, 27, 28, 29, 41, 42 and 43 – in the Namibe basin and one in Benguela basin on November 12
  • Iran is going ahead with a US$1.8 billion oil pipeline to the port of Jask, which will bypass the Persian Gulf with its position on the Gulf of Oman, possibly shielding crude exports away from military action as well as boost shipments of Caspian Sea oil through the country
  • Norway’s Petroleum Fund has been given the go-ahead to sell oil and gas stocks worth US$5.9 billion as it moves to focus on cleaner energies, gradually exiting upstream stocks but maintaining downstream ones
  • Africa-focused Delonex Energy announced that it had made four oil discoveries in Chad’s frontier Termit basin, with drilling starting in 2020

Midstream/Downstream

  • LyondellBasell and China’s private petchems player Bora Enterprise has started building their US$2.5 billion petrochemicals plant in Liaoning, the largest petchems investment by a Chinese ‘teapot’ refiner thus far
  • Husky has begun reconstruction activities at the Superior Refinery in Wisconsin, after acquiring the site in 2017 and after a fire that damaged most of the site in 2018, with an expected return in 2021
  • Pertamina and Saudi Aramco’s long-running talks to collaborate on the upgrade of the Cilacap refinery in Java continues to roll on, with the latest delay linked to disagreements over the valuation of the refinery
  • Venezuela’s 955 kb/d Paraguan Refining Center has partially restarted after being knocked out of operation by a lightning storm in early September

Natural Gas/LNG

  • Total has completed its acquisition of Anadarko’s 26.5% operated interest in the Mozambique LNG project for US$3.9 billion, part of its deal with Occidental Petroleum to acquire Anadarko’s assets in Africa
  • After failing to renegotiate the Papua LNG plan with Total, the government of Papua New Guinea has now turned the P’nyang deal, hoping to seek better terms from project operator ExxonMobil
  • Abu Dhabi’s ADNOC has started accepting bids for stakes in its natural gas pipelines system, a move that could potentially bring in US$5 billion
  • Petronas has signed a deal with Korea Midland Power (Komipo) to supply 240,000 tpa of LNG over five years beginning 2020
  • The first liquefaction unit at the US$2 billion, Elba Island LNG plant in Savannah, Georgia has reached commercialisation stage, the first of 10 planned units that will have a production capacity of 2.5 mtpa of LNG
  • The Venture Global Plaquemines LNG project Louisiana will be going ahead after receiving regulatory clearance from the US FERC

Corporate

  • After nearly a decade at the reins, BP’s CEO Bob Dudley will step down in Q1 2020, to be succeeded by the current upstream CEO Bernard Looney
October, 14 2019