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Headline crude prices for the week beginning 12 November 2018 – Brent: US$71/b; WTI: US$60/b

  • Crude prices continue their retreat from recent highs, as a bear market engulfed sentiment last week over fears of oversupply from frantic OPEC+ pumping offsetting the loss of Iranian crude volumes, which itself was mitigated by the US handing out waivers to eight key crude importers
  • After stating that OPEC was in a ‘pump as much as you can’ mode, the quick fall in prices has caused alarm across the cartel, with Saudi Arabia reversing gear to curb its exports by 500,000 b/d in December to shore up prices
  • With the OPEC meeting in Vienna imminent, it is possible that a new output cut agreement could be reached within OPEC+, to counter an oversupply situation stemming from declining demand, as well as surging US shale production – which will rise to a record 7.94 mmb/d across seven major shale basins in December, according to the EIA
  • However, beyond Saudi Arabia, there is not much appetite within the OPEC+ alliance to reduce output, with Iraq happy with its record production and Russia dismissing the oversupply situation as a ‘seasonal glitch’
  • Saudi Arabia’s plan to cut its oil production was criticised by US President Donald Trump, stung by losses in midterm elections that Trump chalks up to, in part, high fuel prices
  • News that Saudi Arabia was researching the topic of breaking up OPEC rattled the markets, but the Kingdom moved to quash rumours as Aramco raised the pricing for its medium and heavy crudes sold to Asia
  • Despite this, trends have turned bearish for crude prices over this week, propelled by large jumps in US crude output and worries over a global economic slowdown, particularly in China; Brent and WTI fell by over US$4/b on Tuesday alone, falling below the US$70/b and US$60/b levels again
  • After several weeks of caution, US drillers added 14 new rigs this week – up by 12 oil rigs and 2 gas rigs to 1,081 in total – with the most gains once again coming from the prolific Permian Basin
  • Crude price outlook: After the large drop on Tuesday, crude prices appear to have stabilised somewhat around the US$65-66/b level for Brent and the US$55-56/b level for WTI


Headlines of the week

Upstream

  • Another setback for TransCanada’s beleaguered Keystone XL pipeline, as a judge in Montana halted the project over two lawsuits filed asserting that its environmental impact assessment required further review
  • Phillips 66 and Bridger Pipeline are launching two new crude pipelines connecting Rockies and Bakken oil to the Texas Gulf Coast; the Liberty Pipeline will carry 350 kb/d from Bakken/Rockies to Corpus Christi, while the 400 kb/d Red Oak Pipeline connects Corpus Christi to Houston
  • Magellan Midstream Partners is looking to build a new pipeline connecting Cushing to Houston, with the 250 kb/d Voyager pipeline targeted at end-2020
  • The Kurdistan Regional Government in Iraq has increased capacity of its oil pipeline from Kirkuk to Ceyhan, Turkey, from 700,000 b/d to 1 mmb/d
  • After previously fleeing from Canadian oil sands, ExxonMobil is investing again, with its Imperial Oil unit earmarking some US$2 billion for the new Aspen project in northern Alberta
  • Senrica Energy continues its buying spree in the North Sea, acquiring Marubeni Oil & Gas’ 3.75% and 8.33% interest in the Bruce and Keith fields
  • ADNOC is implementing a comprehensive hydrocarbons strategy that will increase its crude output capacity to 4 mmb/d by 2020 and 5 mmb/d by 2030
  • Croatia has launched the country’s second onshore licensing round, offering seven blocks in the prolific Pannonian basin
  • Eni and Lukoil have signed a farm-out deal, transferring participating interests in three shallow-water offshore Mexican licenses, including Area 10, 12 and 14
  • Buoyed by recent gas successes, Israel has announced its second offshore licensing round, offering up 19 blocks in its southern waters
  • Senegal is overhauling its own code, with plans to raise royalties and have the state take a bigger stake in projects after a string of major discoveries
  • CNOOC is kickstarting a development drive aimed at eking out additional volumes from several marginal fields in Bohai Bay and the South China Sea

Downstream

  • Nigeria’s ambitious overhaul of its state-owned refineries has been pushed back to end-2019 over slow progress in NNPC’s attempt to seek joint financing
  • NNPC is looking to sign crude-for-product swap deals with Shell and ExxonMobil, after signing one with BP, to acquire crude for its refineries
  • France is pushing ahead with its attempt to introduce a new fuel tax, despite a series of major blockades and protests planned to oppose the measure

Natural Gas/LNG

  • Total and Sempra Energy have signed a new MoU on LNG cooperation, covering the Cameron LNG in Louisiana, USA and Energía Costa Azul in Baja California, Mexico, with Total potentially taking up to 9 mtpa of LNG for its global portfolio from both projects
  • Cuadrilla has had first shale gas flow at its exploration well in the UK’s Preston New Road site, sparking optimism for the commercialisation of Bowland Shale
  • Croatia has picked Golar Power to deliver an FSRU for a planned floating LNG terminal in the northern Adriatic Sea
  • Tellurian confirms that construction on its Driftwood LNG terminal Louisiana will begin in 2H2019, which operations planned to begin in 2023
  • Japan’s Toshiba Corp is exiting the US LNG business, selling off its assets to China’s ENN Ecological Holdings for over US$800 million

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U.S. coal production employment has fallen 42% since 2011

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.

U.S. coal production by region

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.

U.S. coal mining labor productivity

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.

December, 12 2019
This Week in Petroleum: With pipeline development, U.S. crude oil pipeline fill has increased by more than 60% since 2011
Crude oil held in pipelines (pipeline fill) in the United States grew from 75 million barrels in March 2011, the earliest data available, to nearly 124 million barrels in September 2019, a 64% increase, according to the U.S. Energy Information Administration’s (EIA) Working and Net Available Shell Storage Capacity report (Figure 1). The increase is due to the significant expansion of the U.S. crude oil pipeline system over that period. Almost 97% of the 48 million barrel increase in crude oil pipeline fill, which includes some volumes of crude oil in transit via water and rail, occurred in the Gulf Coast (Petroleum Administration for Defense District, or PADD, 3) and the Midwest (PADD 2).

Figure 1. . Crude oil pipeline fill

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.

Figure 2. Crude oil pipeline projects (2nd Quarter 2011-3rd Quarter 2019)

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.

Figure 3. Crude oil production, distillation capacity, and crude oil storage

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.

December, 12 2019
Bioethanol Market to reach 68.95 Billion USD by 2022, Growing at a CAGR of 5.3%

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. 

Download PDF Brochure @ https://www.marketsandmarkets.com/pdfdownloadNew.asp?id=131222570

Major Growth Drivers: 
  • Government policies and mandates
    • Agricultural policies
    • Blending mandates
    • Subsidies and support
    • Tariffs & tax incentives
  • Volatile petroleum prices
  • Increase in awareness of climate change and green-house gas emission
  • Higher octane rating at a lower price than unleaded/pure gasoline

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.

bioethanol-market-131222570

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).

Speak to Analyst @ https://www.marketsandmarkets.com/speaktoanalystNew.asp?id=131222570

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December, 11 2019