In the July 2019 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that Brent crude oil prices will average $67 per barrel (b) in 2019 and in 2020. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $60/b in 2019 and $63/b in 2020 (Figure 1). The forecast of relatively stable crude oil prices in the mid-$60/b range reflects EIA’s expectation that heading into 2020, global oil consumption will grow at a similar rate as global oil supply at current price levels. However, several risks to both consumption and supply could push prices out of this range.
Brent crude oil spot price averaged $64/b in June, down from an average of $71/b in both April and May. The recent price declines largely reflect increasing concerns about global oil demand growth as a result of increasingly weak global economic signals. Weakening global oil demand and strong supply growth in the United States contributed to global petroleum and other liquid fuels inventory builds in the first half of 2019 and limited any sustained upward pressure on crude oil prices. In terms of price formation in recent months, these factors have outweighed decreasing crude oil supply from members of the Organization of the Petroleum Exporting Countries (OPEC). OPEC output fell because of declining crude oil production in Venezuela and Iran, the extension of the agreement between OPEC and non-OPEC participants (OPEC+) through the first quarter of 2020, and Saudi Arabia’s continued over compliance with the existing OPEC+ agreements.
EIA expects that the combination of strong growth in U.S. and other non-OPEC liquid fuels production and slowing global oil demand growth will contribute to a balanced market in the second half of 2019 and about 150,000 barrels per day (b/d) growth in global petroleum and other liquid fuels inventories in 2020 (Figure 2). The global oil inventory builds in 2020 are expected to put some downward pressure on crude oil prices; however, EIA assumes that the downward pressure will be offset by upward price pressures as a result of the IMO 2020 regulations going into effect. Although EIA expects the new regulations to have a limited impact on crude oil prices, many unknowns remain about how the global refining and shipping industries will respond to the regulation and how actual outcomes of these decisions will affect crude oil prices.
Developments regarding the rate of economic growth and its effect on global oil demand further contribute to crude oil price uncertainty. Based on forecasts from Oxford Economics, EIA lowered its global oil-weighted gross domestic product (GDP) growth projection to 2.2% in 2019, which would be the lowest annual growth rate since 2009. The low GDP growth rate, in turn, is expected to result in an annual oil consumption growth of 1.1 million b/d, the lowest level of growth since 2011 and similar to growth levels seen in 2016.
EIA forecasts that both economic growth and liquid demand growth will rebound in 2020. Annual oil-weighted GDP growth is expected to increase to 2.7% in 2020, leading to increased oil demand growth. EIA expects world liquid fuels demand growth of more than 1.4 million b/d in 2020, more than two-thirds of which is forecast to come collectively from China, the United States, India, and Russia.
On the supply side, EIA expects continuing declines (albeit at a slower pace) in OPEC production to be more than offset by supply growth in the United States and other non-OPEC countries. However, compliance with OPEC+ production targets and the potential for supply disruptions in key oil-producing countries could pose risks to the forecast.
On July 2, 2019, OPEC+ extended production cuts announced in December 2018 through the end of the first quarter of 2020. EIA’s forecast assumes the OPEC+ agreement will remain in place through the end of the first quarter of 2020, with OPEC+ continuing to target a balanced market after that. The degree of adherence to production targets from the OPEC+ agreement will be a key determinant of whether global crude oil inventories remain higher than the five-year (2014–18) average during the forecast period and will be a significant driver of crude oil prices. EIA forecasts OPEC total liquids production will average 35.3 million b/d in the second half of 2019 and 34.8 million b/d in 2020, down from 37.3 million b/d in 2018. The decline through 2019 to date is mainly the result of Saudi Arabia’s over compliance with the December 2018 OPEC+ agreement and rapidly decreasing crude oil production in Iran and Venezuela. Combined production in Iran and Venezuela fell to an estimated 2.8 million b/d as of June 2019, a 2.4 million b/d decrease compared with June 2018. These factors contributed to OPEC’s crude oil production averaging 29.9 million b/d in June, the lowest level since mid-2014.
Additional supply disruptions may potentially remove large volumes of crude oil from the global market and cause crude oil prices to increase. Events in Venezuela and Libya, in particular, could cause production to drop quickly. In Venezuela, widespread power outages, long-term inefficient management of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and state-owned Petróleos de Venezuela (PdVSA) have all contributed to accelerating declines. Although Libya’s crude oil production increased during the first half of 2019, supply disruptions will remain a significant risk through 2020 because of the tentative security situation in the country and the lack of investment in existing infrastructure. Disruptions to shipping through the Strait of Hormuz would also cause prices to increase.
Finally, the U.S. tight oil sector continues to be dynamic, and quickly evolving trends in this sector could affect both current crude oil prices and expectations for future prices. EIA expects U.S. crude oil production, which reached a record-high 11.0 million b/d in 2018, to average 12.4 million b/d in 2019 and 13.3 million b/d in 2020. Much of the growth in U.S. crude oil production is attributable to tight oil formations in the Permian region of Texas and New Mexico, which account for 950,000 b/d of the U.S. growth expected in 2019 and 740,000 b/d of the growth in 2020. A downside risk to Permian crude oil production is the increased production of natural gas from this region. Drilling in areas with high concentrations of natural gas in the Permian region might increase only if natural gas pipeline constraints are eased and tighter flaring limits are not implemented.
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price increased 3 cents from the previous week to $2.74 per gallon on July 8, 11 cents lower than the same time last year. The Gulf Coast price increased 5 cents to $2.42 per gallon, and the Midwest and East Coast prices each increased nearly 4 cents to $2.67 per gallon and $2.66 per gallon, respectively. The Rocky Mountain price fell nearly 3 cents to $2.80 per gallon, and the West Coast price fell nearly 1 cent to $3.38 per gallon.
The U.S. average diesel fuel price increased more than 1 cent to $3.06 per gallon on July 8, 19 cents lower than a year ago. The Midwest price increased over 4 cents to $2.97 per gallon, and the East Coast and the Gulf Coast prices each increased less than 1 cent, remaining at $3.08 per gallon and $2.80 per gallon, respectively. The Rocky Mountain price fell nearly 2 cents to $2.98 per gallon, and the West Coast price fell less than 1 cent to $3.62 per gallon.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 0.2 million barrels last week to 76.9 million barrels as of July 5, 2019, 5.7 million barrels (7.9%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest and Gulf Coast inventories decreased by 0.4 million barrels and 0.2 million barrels, respectively, while Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. East Coast inventories increased by 0.4 million barrels. Propylene non-fuel-use inventories represented 6.0% of total propane/propylene inventories.
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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:
Headline crude prices for the week beginning 8 July 2019 – Brent: US$64/b; WTI: US$57/b
Headlines of the week
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.
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.
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.