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Brent and WTI prices are now at their highest levels in two years. With Brent almost touching US$65/b and WTI within shot of US$60/b, this is cheer for the market, where most participants had resigned themselves to a prolonged period of US$50/b oil. There are several factors propelling this rise. OPEC 's insistence that its supply freeze is working is proving true; despite the rise in American production (and American exports hitting all-time highs), the OPEC deal appears to be slowly clearing out the global glut. And then there has been a re-emergence of something the market hasn’t seen in a while – geopolitical risk premium.
Saudi Arabia’s decision to embark on a corruption purge in early November shocked the market. The arrest of some 11 princes – as well as the mysterious killing of a 12th as his helicopter was downed – sparked fears of turmoil was imminent in Saudi Arabia. While much of what goes on (and is going on) in the world’s largest crude producer remains a black box. Detractors within the sprawling House of Saud are not unknown, but have previously been dealt with quietly. This very public campaign – which included ‘imprisoning’ the ‘corrupt’ in the plush Ritz-Carlton – is unusual, and the market worries about what the future could hold. The politics of Saudi Arabia are complicated, and it is unclear where things will end with Crown Prince Salman’s current actions. If its future growth from a more diversified economy is all that he wants, things should go on track. If it’s just a power grab, things turn out differently.
What is truly more worrying is the part of an ongoing escalation between Saudi Arabia (and its allies, including the US) against Iran. On the day the purge was announced, Saudi Arabia said it had intercepted a missile fired from Yemen. Then the Prime Minister of Lebanon resigned while in Saudi Arabia, saying he ‘feared for his life’. Bahrain recently blamed a pipeline fire on Iran. This is a slowburn intensification since the Gulf states decided to blockade Qatar. There must be a lot of politicking going on behind the scenes, but one thing is clear – the Middle East is rapidly positioning themselves into two camps, for Saudi Arabia and for Iran. Threats of war have been declared, and even though it is unlikely right now, the danger is still real. With American diplomacy learning towards the Saudis under Donald Trump with no real peace maker in sight, bold moves could be made and hostilities could break out. Oil prices, naturally, would rise if that happens. But even the notion of it happening is making traders nervous. And keeping prices up. It is a repeat of the situation in 2011-2013, when the Arab Spring sent prices soaring.
Based on basic supply/demand fundamentals, the level of crude prices right now should probably be with the range of US$50-55/b. The market has been adding on a risk premium to prices due to the current Middle East tensions. This could rise if Iran-Saudi Arabia relations continue to sour or unless it also derails the planned extension of OPEC production cuts in March 2018! Rising American production is also not pacifying the market, after five weeks of declines, American rig owners added nine new rigs last week, tempted by rising prices. It is likely oil price stay within US$60/level through the end of the year. Some traders are betting it will go further. A flurry of trades last week betted on Brent to hit US$80/b by Christmas. There might be smiles if that happens, but for that to occur there will have to be some serious supply disruptions in the Middle East.
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The U.S. Energy Information Administration’s (EIA) Annual Coal Report shows that coal mining employment has declined in the past decade as coal demand has decreased. Most U.S. coal is consumed in the electric power sector and has faced increased competition from electricity generation from natural gas and renewable technologies. U.S. coal mining employment fell from a high of 92,000 employees in 2011 to 54,000 employees in 2018, with the most dramatic decrease in the Appalachian region.
Annual U.S. coal production peaked in 2008, three years before coal mining employment reached its record high. In 2008, the United States produced 1.2 billion tons of coal from 1,458 mines. Since then, coal production has fallen and many mines have closed: in 2018, U.S. coal production was 756 million tons from 679 mines. As was the case with employment, much of coal’s production decline was concentrated in the Appalachian region. More than half of the region’s mines have closed since 2008, and production has fallen from 390 million tons in 2008 to 200 million tons in 2018.
Source: U.S. Energy Information Administration, Annual Coal Report
Appalachian mines tend to be smaller than mines in the Interior and Western regions and to use labor-intensive underground mining techniques, as opposed to machinery-intensive longwall mining and surface mining operations. A slight increase in coal mining employment in the Appalachia region from 2016 to 2018 corresponded to an increase in coal exports because this region is the dominant source of coal shipped overseas.
The decline in operating mines has been steeper than the changes in employment and production. EIA’s review of operating mines showed that smaller mines have had greater difficulty competing in the current market and have been the first to close.
Source: U.S. Energy Information Administration, Annual Coal Report
As smaller, less productive mines were idled or closed, overall coal labor productivity, measured in tons per labor hour, gradually increased from 5.2 tons per labor hour in 2011 to 6.2 tons per labor hour in 2018. The large surface mines in the Powder River Basin (PRB) in Wyoming and Montana have much higher productivity, but even PRB productivity has declined as the region’s producing coal seams become deeper and the amount of overburden, or top soil and rock above the coal seam, increases.
In contrast, the Appalachia and Interior regions both have shown improvements in labor productivity between 2011 and 2018, largely because they are increasingly relying on less labor-intensive longwall and highwall mining systems and closing or idling the least productive mines.
Data from EIA’s Annual Coal Report are available in EIA’s Coal Data Browser. In addition to data from the U.S. Mine Safety and Health Administration, EIA’s Annual Coal Report also includes mine-level data from EIA’s Survey of Coal Production and Preparation and coal exports data from the U.S. Department of Commerce.
Pipelines are the primary method of transporting crude oil in the United States. The increase in U.S. crude oil production in recent years has required the construction of new pipelines and reconfiguration of existing pipelines, including the conversion of natural gas pipelines to crude oil pipelines. The Gulf Coast region, which was responsible for 70% of the growth in U.S. crude oil production between 2010 and 2018, has experienced the largest pipeline buildout during that time period. The Permian Basin, covering West Texas and southeastern New Mexico, contributed the most to crude oil production growth and supported higher crude oil inventories in the region, including increased pipeline fill.
According to EIA’s Liquid Pipeline Projects Database, more than 100 crude oil pipeline projects were completed between March 2011 and September 2019. During this time, about 90% of projects were located in either the Gulf Coast or Midwest regions (Figure 2). The most prevalent project types were pipeline expansions and new pipeline builds. The vast majority of the projects were for transporting crude oil within their respective regions.
Many pipeline expansions increased crude oil takeaway capacity from producing regions. For example, in 2018, Enterprise Products Partners L.P.’s 418-mile Midland-to-Echo 1 Pipeline System was placed into service to transport crude oil from the Permian Basin to locations near Houston, Texas. Other Permian Basin projects completed in 2018 included Plains All American’s Sunrise Pipeline Expansion and Enterprise Products Partners L.P.’s new Loving County Pipeline. The Sunrise Pipeline Expansion transports crude oil from the Permian region to Cushing, Oklahoma, and destinations in the Gulf Coast and the Loving County Pipeline transports crude oil from Permian Basin fields in New Mexico to Midland, Texas, a crude oil supply hub.
About 64% of crude oil production, 52% of U.S. petroleum refining capacity (measured by operable distillation capacity), and 52% of crude oil storage is located in the Gulf Coast (Figure 3). Rising Permian crude oil production decreased crude oil imports, and increased demand for crude oil at petroleum refineries have coincided with several projects aimed at increasing crude oil pipeline deliveries to Gulf Coast refineries. For example, the 264-mile Kinder Morgan Crude & Condensate Pipeline (KMCC), which includes a converted 109-mile natural gas pipeline, initiated deliveries of crude oil and condensate from the Eagle Ford region to Houston in 2012. Kinder Morgan later included a 27-mile lateral to Phillips 66’s refinery in Old Ocean, Texas. In 2014, TC Energy’s Keystone Gulf Coast Expansion was placed into service to supply refineries in Port Arthur, Texas.
In the Midwest, Cushing, Oklahoma—a key crude oil storage hub—has experienced significant increases in crude oil pipeline capacity as new crude oil tank farms were built to handle rising supplies. Crude oil working storage capacity in Cushing rose 59% between March 2011 and September 2019 to reach 76 million barrels. Cushing receives large volumes of crude oil by pipeline and rail from various areas such as Canada and the Rocky Mountains (PADD 4). For example, TC Energy’s 2014 expansion of the Keystone Pipeline transports crude oil that originated in Alberta, Canada, to Gulf Coast refineries via Cushing. Several additional pipeline projects that entered service between 2014 and 2018 were designed to move crude oil from the Rocky Mountains, which includes the Bakken formation, to Cushing.
Growing crude oil exports have also supported increases in crude oil pipeline capacity. The removal of restrictions on U.S. crude oil exports at the end of 2015, combined with higher crude oil production, allowed an increase in crude oil exports in the Gulf region, which grew from 3,000 barrels per day (b/d) in 2010 to 1.8 million b/d in 2018. Petroleum terminals in the Gulf Coast that once imported large volumes of crude oil now load crude oil tankers for export to international destinations. Enterprise Products Partners L.P. recently completed an expansion to its Midland-to-Sealy Pipeline and conversion of its Seminole Red Pipeline to service the Enterprise Crude Houston (ECHO) terminal, a facility where shippers can load U.S. crude oil for export.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell more than 1 cent from the previous week to $2.56 per gallon on December 9, 14 cents higher than the same time last year. The West Coast price fell 7 cents to $3.34 per gallon, the Rocky Mountain price fell nearly 3 cents to $2.79 per gallon, and the Gulf Coast price fell more than 2 cents to $2.20 per gallon. The East Coast and Midwest prices remained unchanged at $2.48 per gallon and $2.42 per gallon, respectively.
The U.S. average diesel fuel price fell more than 2 cents from the previous week to $3.05 per gallon on December 9, 11 cents lower than a year ago. The West Coast price fell by nearly 6 cents to $3.65 per gallon, the Rocky Mountain price fell by more than 3 cents to $3.21 gallon, the Gulf Coast price fell by 2 cents to $2.76 per gallon, the Midwest price fell by nearly 2 cents to $2.97 per gallon, and the East Coast price fell by nearly 1 cent to $3.05 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.7 million barrels last week to 93.5 million barrels as of December 6, 2019, 7.4 million barrels (8.6%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and Rocky Mountain inventories increased by 3.3 million barrels and 0.1 million barrels, respectively. Midwest and East Coast inventories decreased by 1.1 million barrels and 0.6 million barrels, respectively. Propylene non-fuel-use inventories represented 5.8% of total propane/propylene inventories.
Residential heating oil prices increase, propane prices decrease
As of December 9, 2019, residential heating oil prices averaged almost $3.02 per gallon, more than 1 cent per gallon above last week’s price but more than 18 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.07 per gallon, more than 2 cents per gallon higher than last week’s price and more than 7 cents per gallon higher than a year ago.
Residential propane prices averaged more than $2.02 per gallon, almost 1 cent per gallon lower than last week’s price and nearly 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.83 per gallon, more than 7 cents per gallon lower than last week’s price and nearly 8 cents per gallon below last year’s price.
The global bioethanol market is estimated at USD 53.19 Billion in 2017 and is projected to reach USD 68.95 Billion by 2022, at a CAGR of 5.3% from 2017 to 2022. The market is driven by the increased demand for bioethanol from various end-use industry segments, such as transportation, pharmaceuticals, cosmetics, alcoholic beverages, and others. The transportation end-use industry segment led the global bioethanol market, in terms of volume, in 2016.
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Major Growth Drivers:Starch-based feedstock is estimated to be the largest feedstock type in the global bioethanol market.
The starch-based segment is estimated to be the largest feedstock segment of the global bioethanol market. This feedstock type uses corn, barley, wheat, and other starch raw materials as feedstocks to produce bioethanol. Corn has the highest percentage of starch, about 70-72%. The growth in this segment is attributed to the rising demand from Asia Pacific and South America and the wide variety of feedstocks that can be used to produce starch-based bioethanol. The feedstocks used are available in almost all over the world.
Alcoholic beverages segment is estimated to be the fastest growing end-use industry segment of the global bioethanol market.
Among end-use industries, the alcoholic beverages segment is estimated to be the fastest growing end-use segment of the global bioethanol market. The growth of this segment is attributed to the increasing purchasing power in developing countries and the growing acceptance of drinking alcoholic beverages in some cultures.
North America contributes as the largest market of bioethanol
In 2016, North America accounted for largest share of the bioethanol market. Currently, the US is the largest market for bioethanol in North America, and is expected to continue to be the largest market till 2022. In the US, the demand for bioethanol is expected to increase due to the increasing government and environment regulations in the country. Regulations such as the Federal Reformulated Gasoline (RFG) and E15 regulations contribute to the growing use of bioethanol in fuels. The other driving factor for the bioethanol market is the low price of corn, which is a prime feedstock used in the production of bioethanol in the country. Many bioethanol manufacturers are based in this region.
Key companies profiled in the global bioethanol market research report include Archer Daniels Midland Company (US), POET LLC (US), Green Plains (US), Valero Energy Corporation (US), Flint Hills Resource (US), Abengoa Bioenergy SA (Spain), Royal Dutch Shell plc (Netherlands), Pacific Ethanol, Inc. (US), Petrobras (Brazil), and The Andersons (US).
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