· This edition of the Short-Term Energy Outlook is the first to include forecasts for 2019.
· Benchmark North Sea Brent crude oil spot prices averaged $64 per barrel (b) in December, an almost $2/b increase from the November average and the highest monthly average since November 2014.
· Brent crude oil prices averaged $54/b in 2017 and are forecast to average $60/b in 2018 and $61/b in 2019. West Texas Intermediate (WTI) crude oil spot prices are forecast to average $4/b less than Brent prices in both 2018 and 2019. EIA’s forecast for the average WTI price for December 2018 of $58/b should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $40/b to $85/b encompasses the market expectation for WTI prices in December 2018 at the 95% confidence level.
· U.S. regular gasoline retail prices averaged $2.48 per gallon (gal) in December, down almost 9 cents/gal from the average in November but 22 cents/gal higher than at the same time last year. U.S. regular gasoline retail prices averaged $2.42/gal in 2017 and are forecast to average $2.57/gal in 2018 and $2.58/gal in 2019.
· U.S. crude oil production averaged an estimated 9.3 million barrels per day (b/d) in 2017 and is estimated to have averaged 9.9 million b/d in December. U.S. crude oil production is forecast to average 10.3 million b/d in 2018, which would mark the highest annual average production in U.S. history, surpassing the previous record of 9.6 million b/d set in 1970. EIA forecasts production to increase to an average of 10.8 million b/d in 2019 and to surpass 11 million b/d in November 2019.
· Dry natural gas production is forecast to average 80.4 billion cubic feet per day (Bcf/d) in 2018, a 6.9 Bcf/d increase from the 2017 level, which would be the highest year-over-year increase on record. Forecast dry natural gas production increases by an average of 2.6 Bcf/d in 2019.
· Henry Hub natural gas spot prices are forecast to average $2.88 per million British thermal units (MMBtu) in 2018 and $2.92/MMBtu in 2019, compared with the 2017 average of $2.99/MMBtu. EIA’s forecast for the average Henry Hub price for December 2018 of $3.04/MMBtu should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $1.83/MMBtu to $4.89/MMBtu encompasses the market expectation for Henry Hub prices in December 2018 at the 95% confidence level.
· Coal production increased by 45 million short tons (MMst) (6%) in 2017 in response to high demand for U.S. coal exports. Coal production is forecast to decline by 14 MMst (2%) in 2018 and by 18 MMst (2%) in 2019, as export demand is expected to slow and natural gas prices are expected to stay below $3/MMBtu during much of the forecast period, which contributes to less coal use for electricity generation.
· EIA expects the share of U.S. total utility-scale electricity generation from natural gas to rise from 32% in 2017 to 33% in 2018 and to 34% in 2019, as a result of low natural gas prices. Coal's forecast generation share falls from 30% in 2017 to slightly lower than 30% in 2018 and 28% in 2019. The nuclear share of generation was 20% in 2017 and is forecast to average 20% in 2018 and 19% in 2019. Nonhydropower renewables provided almost 10% of electricity generation in 2017, and its 2018 share is expected be similar before increasing to almost 11% in 2019. The generation share of hydropower was more than 7% in 2017 and is forecast to be slightly lower than 7% in both 2018 and 2019.
· After declining by 1.0% in 2017, energy-related carbon dioxide (CO2) emissions are forecast to increase by 1.7% in 2018 and by 0.2% in 2019. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, and energy prices.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
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.
Download PDF Brochure @ https://www.marketsandmarkets.com/pdfdownloadNew.asp?id=131222570Major 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).
Speak to Analyst @ https://www.marketsandmarkets.com/speaktoanalystNew.asp?id=131222570
MarketsandMarkets™ provides quantified B2B research on 30,000 high growth niche opportunities/threats which will impact 70% to 80% of worldwide companies’ revenues. Currently servicing 5000 customers worldwide including 80% of global Fortune 1000 companies as clients. Almost 75,000 top officers across eight industries worldwide approach MarketsandMarkets™ for their painpoints around revenues decisions.
Our 850 fulltime analyst and SMEs at MarketsandMarkets™ are tracking global high growth markets following the "Growth Engagement Model – GEM". The GEM aims at proactive collaboration with the clients to identify new opportunities, identify most important customers, write "Attack, avoid and defend" strategies, identify sources of incremental revenues for both the company and its competitors. MarketsandMarkets™ now coming up with 1,500 MicroQuadrants (Positioning top players across leaders, emerging companies, innovators, strategic players) annually in high growth emerging segments. MarketsandMarkets™ is determined to benefit more than 10,000 companies this year for their revenue planning and help them take their innovations/disruptions early to the market by providing them research ahead of the curve.
MarketsandMarkets’s flagship competitive intelligence and market research platform, "RT" connects over 200,000 markets and entire value chains for deeper understanding of the unmet insights along with market sizing and forecasts of niche markets.
Mr. Shelly Singh
701 Pike Street,
Suite 2175, Seattle,
WA 98101, United States
Email: [email protected]