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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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The Strait of Hormuz and Oil Prices

The UK has just designated the Persian Gulf as a level 3 risk for its ships – the highest level possible threat for British vessel traffic – as the confrontation between Iran with the US and its allies escalated. The strategically-important bit of water - and in particular the narrow Strait of Hormuz – is boiling over, and it seems as if full-blown military confrontation is inevitable.

The risk assessment comes as the British warship HMS Montrose had to escort the BP oil tanker British Heritage out of the Persian Gulf into the Indian Ocean from being blocked by Iranian vessels. The risk is particularly acute as Iran is spoiling for a fight after the Royal Marines seized the Iranian crude supertanker Grace-1 in Gibraltar on suspicions that it was violating sanctions by sending crude to war-torn Syria. Tensions over the Gibraltar seizure kept the British Heritage tanker in ‘safe’ Saudi Arabian waters for almost a week after making a U-turn from the Basrah oil terminal in Iraq on fears of Iranian reprisals, until the HMW Montrose came to its rescue. Iran’s Revolutionary Guard Corps have warned of further ‘reciprocation’ even as it denied the British Heritage incident ever occurred.

This is just the latest in a series of events around Iran that is rattling the oil world. Since the waivers on exports of Iranian crude by the USA expired in early May, there were four sabotage attacks on oil tankers in the region and two additional attacks in June, all near the major bunkering hub of Fujairah. Increased US military presence resulted in Iran downing an American drone, which almost led to a full-blown conflict were it not for a last-minute U-turn by President Donald Trump. Reports suggest that Iran’s Revolutionary Guard Corps have moved military equipment to its southern coast surrounding the narrow Strait of Hormuz, which is 39km at its narrowest. Up to a third of all seaborne petroleum trade passes through this chokepoint and while Iran would most likely overrun by US-led forces eventually if war breaks out, it could cause a major amount of damage in a little amount of time.

The risk has already driven up oil prices. While a risk premium has already been applied to current oil prices, some analysts are suggesting that further major spikes in crude oil prices could be incoming if Iran manages to close the Strait of Hormuz for an extended period of time. While international crude oil stocks will buffer any short-term impediment, if the Strait is closed for more than two weeks, crude oil prices could jump above US$100/b. If the Strait is closed for an extended period of time – and if the world has run down on its spare crude capacity – then prices could jump as high as US$325/b, according to a study conducted by the King Abdullah Petroleum Studies and Research Centre in Riyadh. This hasn’t happened yet, but the impact is already being felt beyond crude prices: insurance premiums for ships sailing to and fro the Persian Gulf rose tenfold in June, while the insurance-advice group Joint War Committee has designated the waters as a ‘Listed Area’, the highest risk classification on the scale. VLCC rates for trips in the Persian Gulf have also slipped, with traders cagey about sending ships into the potential conflict zone.

This will continue, as there is no end-game in sight for the Iranian issue. With the USA vague on what its eventual goals are and Iran in an aggressive mood at perceived injustice, the situation could explode in war or stay on steady heat for a longer while. Either way, this will have a major impact on the global crude markets. The boiling point has not been reached yet, but the waters of the Strait of Hormuz are certainly simmering.

The Strait of Hormuz:

  • Connects the Persian Gulf to the Gulf of Oman/Indian Ocean
  • Length: 167km
  • Width: 96km (widest) to 39km (narrowest)
  • Controlled by Iran, the UAE and Musandam (Oman)
  • The conduit for 33% of all LNG trade and 20% of total crude oil demand
July, 16 2019
Your Weekly Update: 8 - 12 July 2019

Market Watch 

Headline crude prices for the week beginning 8 July 2019 – Brent: US$64/b; WTI: US$57/b

  • Bolstered by the renewed OPEC+ supply pact but rattled by increasing tensions between Iran and the US, oil prices started the week steady after gaining over the previous week
  • With the OPEC+ supply deal extended to March 2020, focus will now shift to adherence and in particular, Russian commitments to the agreement that previously wavered over 1H19
  • More critical to the market is the escalating standoff between the US and Iran around the Straits of Hormuz and even beyond; British forces seized an oil tanker off Gibraltar that was suspected to carrying Iranian crude to Syria, drawing share criticism from Iran
  • Iran itself confirmed that it was raising its level of nuclear enrichment above levels agreed to in the 2015 deal that ended sanctions, and accused European signatories to the deal of ‘not doing enough’
  • Iranian forces also confronted a British tanker escorted by a warship in the Persian Gulf, with the narrow channel now a flashpoint for action
  • As a recipient of Middle Eastern crude, China has also raised security levels for its vessel passing through the Straits of Malacca after doing the same for the Straits of Hormuz, raising some eyebrows
  • While the confrontation – or lack of – between the US and Iran will be the main driver behind oil prices movement in the second half of 2019, the trade policies of the Trump administration that may now hit secondary Asian manufacturing nations such as Vietnam is also leaving the global economy increasingly fragile
  • Against this backdrop, the US active oil and gas rig count fell again, dropping five oil sites and gaining one gas site for a net loss of four rigs
  • As the Iranian situation deteriorates, the market will be pricing more risk premiums into traded prices, which should inch up towards the US$65-67/b range for Brent and US$59-61/b for WTI

Headlines of the week

Upstream

  • Marathon Oil has completed the sale of its UK businesses to RockRose Energy, handing over the Brae and Foinaven area fields for US$345 million
  • Despite pulling out from the UK North Sea, ConocoPhillips is still active in Norway, recently submitting a new plan to re-develop the Tor field in Great Ekofisk, which was shut down in 2015 despite only 20% of resources extracted
  • In a bit to boost national production, Nigerian independent Aiteo Eastern E&P has announced plans to spend up to US$15 billion over the next five years to drill new wells and re-visit existing assets
  • Eni and Vitol have been awarded rights to Block WB03 in the offshore Tano basin in Ghana, with Eni holding 70% and expanding its presence in the country
  • Total has approved Phase 3 development at the onshore Dunga field in Kazakhstan that will increase capacity by 10% to some 20,000 b/d by 2022
  • Eni has launched production from the Mizton field in Mexico’s Bay of Campeche Area 1 – the first new offshore new field development by an international firm since reforms in 2008
  • Halliburton and Kuwait Oil have signed an agreement to explore for oil offshore Kuwait which makes Kuwait’s first foray in offshore upstream services
  • Energean Oil & Gas has purchased Electricite de France’s Italian unit for US$850 million, gaining assets in Egypt, Italy, Algeria, Croatia and the North Sea to complement its existing fields in Israel and Greece

Midstream/Downstream

  • China will be launching a new low-sulfur bunker fuel oil contract on the Shanghai Futures Exchange by the end of 2019, just as new IMO regulations on marine fuel oil sulfur content caps kick into effect in 2020
  • Just as American crude production hits new highs, American refining capacity has also reached a new record high of 18.8 million b/d
  • China has issued a new round of crude oil import quotas for private oil refiners, allowing them to bring in an additional 56.85 million tonnes (~1 mmb/d) over the remainder of 2019
  • In the fallout over the contaminated crude scandal at the Druzhba pipeline, Russian pipeline operator Transneft has capped volumes of Rosneft crude that can be transported to Germany and Poland on the pipeline
  • The US Environmental Protection Agency (EPA) has proposed an increased biodiesel mandate to 20.04 billion gallons in 2020 up from 19.92 billion gallons in 2019, but may not extend the hardship waiver program which drew criticism
  • Iraq and Oman have signed a new MoU to cooperate in the oil and gas sector which includes plans for a shared Omani refinery processing Iraqi crude

Natural Gas/LNG

  • Kosmos Energy has struck new gas at the Greater Tortue Ahmeyim-1 well in the Albian reservoir offshore Mauritania and Senegal, which will support the Greater Tortue Ahmeyim LNG project that is on track for a 2022 start
  • Kenya and Tanzania have entered into talks to explore cross-border natural gas trading, aimed at delivering Tanzanian natural gas to Kenya to bypass requiring and building facilities for LNG imports
  • Energean Oil & Gas is reportedly looking to sell its stake in the major Glengorn gas discovery in the UK once its acquisition of Edison E&P is completed
  • Saudi Aramco has started work on the Jafurah gas terminal that will take unconventional gas from the Ghawar oil field to the coast for processing
July, 12 2019
TODAY IN ENERGY: U.S. utility-scale battery storage power capacity to grow substantially by 2023

Utility-scale battery storage units (units of one megawatt (MW) or greater power capacity) are a newer electric power resource, and their use has been growing in recent years. Operating utility-scale battery storage power capacity has more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW). Assuming currently planned additions are completed and no current operating capacity is retired, utility-scale battery storage power capacity could exceed 2,500 MW by 2023.

U.S. utility-scale battery storage capacity

Source: U.S. Energy Information Administration, Annual Electric Generator Report and the Preliminary Monthly Electric Generator Inventory

EIA's Annual Electric Generator Report (Form EIA-860) collects data on the status of existing utility-scale battery storage units in the United States, along with proposed utility-scale battery storage projects scheduled for initial commercial operation within the next five years. The monthly version of this survey, the Preliminary Monthly Electric Generator Inventory (Form EIA-860M), collects the updated status of any projects scheduled to come online within the next 12 months.

Growth in utility-scale battery installations is the result of supportive state-level energy storage policies and the Federal Energy Regulatory Commission’s Order 841 that directs power system operators to allow utility-scale battery systems to engage in their wholesale energy, capacity, and ancillary services markets. In addition, pairing utility-scale battery storage with intermittent renewable resources, such as wind and solar, has become increasingly competitive compared with traditional generation options.

The two largest operating utility-scale battery storage sites in the United States as of March 2019 provide 40 MW of power capacity each: the Golden Valley Electric Association’s battery energy storage system in Alaska and the Vista Energy storage system in California. In the United States, 16 operating battery storage sites have an installed power capacity of 20 MW or greater. Of the 899 MW of installed operating battery storage reported by states as of March 2019, California, Illinois, and Texas account for a little less than half of that storage capacity.

U.S. operating utlity-scale battery storage by state

Source: U.S. Energy Information Administration, Annual Electric Generator Report and the Preliminary Monthly Electric Generator Inventory

In the first quarter of 2019, 60 MW of utility-scale battery storage power capacity came online, and an additional 108 MW of installed capacity will likely become operational by the end of the year. Of these planned 2019 installations, the largest is the Top Gun Energy Storage facility in California with 30 MW of installed capacity.

As of March 2019, the total utility-scale battery storage power capacity planned to come online through 2023 is 1,623 MW. If these planned facilities come online as scheduled, total U.S. utility-scale battery storage power capacity would nearly triple by the end of 2023. Additional capacity beyond what has already been reported may also be added as future operational dates approach.

Of all planned battery storage projects reported on Form EIA-860M, the largest two sites account for 725 MW and are planned to start commercial operation in 2021. The largest of these planned sites is the Manatee Solar Energy Center in Parrish, Florida. With a capacity of 409 MW, this project will be the largest solar-powered battery system in the world and will store energy from a nearby Florida Power and Light solar plant in Manatee County.

The second-largest planned utility-scale battery storage facility is the Helix Ravenswood facility located in Queens, New York. The site is planned to be developed in three stages and will have a total capacity of 316 MW.

July, 11 2019