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Last Updated: August 7, 2019
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Forecast HighlightsGlobal liquid fuels

  • Brent crude oil spot prices averaged $64 per barrel (b) in July, almost unchanged from the average in June 2019 but $10/b lower than the price in July of last year. EIA forecasts Brent spot prices will average $64/b in the second half of 2019 and $65/b in 2020. The forecast of stable crude oil prices is the result of EIA’s expectations of a relatively balanced global oil market. EIA forecasts global oil inventories will increase by 0.1 million barrels per day (b/d) in 2019 and 0.3 million b/d in 2020.
  • EIA expects West Texas Intermediate (WTI) crude oil prices will average $5.50/b less than Brent prices during the fourth quarter of 2019 and in 2020, narrowing from the $6.60/b spread during July. The narrowing spread reflects EIA’s assumption that crude oil pipeline transportation constraints from the Permian Basin to refineries and export terminals on the U.S. Gulf Coast will ease in the coming months. In the July STEO, EIA forecast the Brent-WTI spread to average $4.00/b in 2020. The updated differential forecast reflects EIA’s revised assumptions about the marginal cost of moving crude oil via pipeline from Cushing, Oklahoma, to the Gulf Coast.
  • EIA estimates that U.S. crude oil production averaged 11.7 million b/d in July, down by 0.3 million b/d from the June level. The declines were mostly in the Federal Gulf of Mexico (GOM), where operators shut platforms for several days in mid-July because of Hurricane Barry. EIA estimates that GOM crude oil production fell by more than 0.3 million b/d in July. Those declines were partially offset by the Lower 48 States onshore region, which is mostly tight oil production, where supply rose by more than 0.1 million b/d. EIA expects monthly growth in Lower 48 onshore production to slow during the rest of the forecast period, averaging 50,000 b/d per month from the fourth quarter of 2019 through the end of 2020, down from an average of 110,000 b/d per month from August 2018 through July 2019. EIA forecasts U.S. crude oil production will average 12.3 million b/d in 2019 and 13.3 million b/d in 2020, both of which would be record levels.
  • U.S. regular gasoline retail prices averaged $2.74 gallon (gal) in July, up 2 cents/gal from June but 11 cents/gal lower than the average in July of last year. EIA expects that monthly average gasoline prices peaked for the year in May at an average of $2.86/gal and will fall to an average of $2.64/gal in September. EIA expects regular gasoline retail prices to average $2.62/gal in 2019 and $2.71/gal in 2020.

Natural gas

  • The Henry Hub natural gas spot price averaged $2.37/million British thermal units (MMBtu) in July, down 3 cents/MMBtu from June. However, by the end of the month, spot prices had fallen below $2.30/MMBtu. Based on this price movement and EIA’s forecast of continued strong growth in natural gas production, EIA lowered its Henry Hub spot price forecast for the second half of 2019 to an average of $2.36/MMBtu. In the July STEO, EIA expected prices to average $2.50/MMBtu during this period. EIA expects natural gas prices in 2020 will increase to an average of $2.75/MMBtu. EIA’s natural gas production models indicate that rising prices are required in the coming quarters to bring supply into balance with rising domestic and export demand in 2020.
  • EIA forecasts that U.S. dry natural gas production will average 91.0 billion cubic feet per day (Bcf/d) in 2019, up 7.6 Bcf/d from 2018. EIA expects monthly average natural gas production to grow in late 2019 and then decline slightly during the first quarter of 2020 as the lagged effect of low prices in the second half of 2019 reduces natural gas-directed drilling. However, EIA forecasts that growth will resume in the second quarter of 2020, and natural gas production in 2020 will average 92.5 Bcf/d.
  • EIA estimates that natural gas inventories ended July at 2.7 trillion cubic feet (Tcf), 13% higher than levels from a year earlier and 4% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections during the 2019 April-through-October injection season will outpace the previous five-year average and that inventories will rise to more than 3.7 Tcf at the end of October, which would be 16% higher than October 2018 levels and slightly above to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA has expanded its forecasts for electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. A STEO Supplement provides more information about the changes.
  • Lower costs for natural gas drive EIA’s forecast that annual average wholesale electricity prices will be lower in 2019 than last year in all areas of the United States. The forecast year-over-year declines range from -0.2% in the Southwest Power Pool (SPP) to -28% in the Electric Reliability Council of Texas (ERCOT) market.
  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and then decline slightly in 2020. EIA forecasts that the share of U.S. generation from coal will average 24% in 2019 and in 2020, down from 28% in 2018. The forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects electric power sector demand for coal to fall by 2% in 2020, compared with an expected decline of 15% in 2019. However, planned coal plant retirements will continue to put downward pressure on overall electricity demand for the fuel. Almost 13 gigawatts of coal-fired electricity generation capacity has retired this year or is scheduled to retire by the end of 2020, accounting for 5% of the capacity existing at the end of 2018.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and 19% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA is improving its regional-level trend analysis by inserting a generator-level production cost model that simulates hourly generation at individual power plants. This improves our insight into generation, especially from fast-growing renewable sources like wind and solar.
  • This additional granularity and the assumption that wind will return to more normal levels in 2019, after a windy first half of 2018, results in an EIA forecast that electricity generation from wind power will average 295 billion kilowatthours (kWh) in 2019 and 335 billion kWh in 2020, estimates that are 4% and 7% lower, respectively, than forecast in the July STEO. In addition, the application of hourly dispatch that better models solar incidence lowers the solar electric production forecast by 1.1% in 2019 and by 2.8% in 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.3% in 2019 and by 0.5% in 2020. In 2019, EIA forecasts that space cooling demand (as measured in cooling degree days) will be lower than in 2018, when it was 13% higher than the previous 10-year (2008–17) average. In addition, in 2019, EIA expects U.S. CO2 emissions to decline because the forecast share of electricity generated from natural gas and renewables is increasing while the forecast share generated from coal, which is a more carbon-intensive energy source, is decreasing. EIA’s projected emissions decline is lower in 2020 than in 2019 because it forecasts that both heating and cooling requirements will be slightly lower than normal. At the same time, the forecast coal share of generation will remain about the same as in 2019 while the natural gas share declines. Although EIA forecasts that generation from renewables will continue to increase in 2020, a forecast decrease in nuclear power offsets 24% of the renewables’ gain.

Changes to the August STEO

Beginning with the August 6, 2019, publication of the STEO, EIA has expanded its forecasts for regional electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. 

To better present the expanded forecast, EIA will no longer publish table 7e, and the data in tables 7a, 7b, 7d, and 8b will now be stated in billion kilowatthours.

EIA has posted a STEO Supplement that provides more information about the new electricity supply and wholesale price forecasts.

Price Summary
 2017201820192020
aWest Texas Intermediate.
bAverage regular pump price.
cOn-highway retail.
dU.S. Residential average.
WTI Crude Oila
(dollars per barrel)
50.7965.0657.8759.50
Brent Crude Oil
(dollars per barrel)
54.1571.1965.1565.00
Gasolineb
(dollars per gallon)
2.422.732.622.71
Dieselc
(dollars per gallon)
2.653.183.073.22
Heating Oild
(dollars per gallon)
2.513.012.993.07
Natural Gasd
(dollars per thousand cubic feet)
10.8610.4910.4910.61
Electricityd
(cents per kilowatthour)
12.8912.8913.0513.17

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The United States now exports crude oil to more destinations than it imports from

As U.S. crude oil export volumes have increased to an average of 2.8 million barrels per day (b/d) in the first seven months of 2019, the number of destinations (which includes countries, territories, autonomous regions, and other administrative regions) that receive U.S. exports has also increased. Earlier this year, the number of U.S. crude oil export destinations surpassed the number of sources of U.S. crude oil imports that EIA tracks.

In 2009, the United States imported crude oil from as many as of 37 sources per month. In the first seven months of 2019, the largest number of sources in any month fell to 27. As the number of sources fell, the number of destinations for U.S. crude oil exports rose. In the first seven months of 2019, the United States exported crude oil to as many as 31 destinations per month.

This rise in U.S. export destinations coincides with the late 2015 lifting of restrictions on exporting domestic crude oil. Before the restrictions were lifted, U.S. crude oil exports almost exclusively went to Canada. Between January 2016 (the first full month of unrestricted U.S. crude oil exports) and July 2019, U.S. crude oil production increased by 2.6 million b/d, and export volumes increased by 2.2 million b/d.

monthly U.S. crude oil production and exports

Source: U.S. Energy Information Administration, Petroleum Supply Monthly

The United States has also been importing crude oil from fewer of these sources largely because of the increase in domestic crude oil production. Most of this increase has been relatively light-sweet crude oil, but most U.S. refineries are configured to process medium- to heavy-sour crude oil. U.S. refineries have accommodated this increase in production by displacing imports of light and medium crude oils from countries other than Canada and by increasing refinery utilization rates.

Conversely, the United States has exported crude oil to more destinations because of growing demand for light-sweet crude oil abroad. Several infrastructure changes have allowed the United States to export this crude oil. New, expanded, or reversed pipelines have been delivering crude oil from production centers to export terminals. Export terminals have been expanded to accommodate greater crude oil tanker traffic, larger crude oil tankers, and larger cargo sizes.

More stringent national and international regulations limiting the sulfur content of transportation fuels are also affecting demand for light-sweet crude oil. Many of the less complex refineries outside of the United States cannot process and remove sulfur from heavy-sour crude oils and are better suited to process light-sweet crude oil into transportation fuels with lower sulfur content.

The U.S. Energy Information Administration’s monthly export data for crude oil and petroleum products come from the U.S. Census Bureau. For export values, Census trade data records the destinations of trade volumes, which may not be the ultimate destinations of the shipments.

October, 23 2019
Recalibrating Singapore’s Offshore Marine Industry

The state investment firm Temasek Holdings has made an offer to purchase control of Singaporean conglomerate Keppel Corp for S$4.1 billion. News of this has reverberated around the island, sparking speculation about what the new ownership structure could bring – particularly in the Singaporean rig-building sector.

Temasek already owns 20.5% of Keppel Corp. Its offer to increase its stake to 51% for S$4.1 billion would see it gain majority shareholding, allowing a huge amount of strategic flexibility. The deal would be through Temasek’s wholly-owned subsidiary Kyanite Investment Holdings, offering S$7.35 per share of Keppel Corp, a 26% premium of the traded price at that point. The financial analyst community have remarked that the bid is ‘fair’ and ‘reasonable’, and there appears to be no political headwinds against the deal being carried out with the exception of foreign and domestic regulatory approval.

The implications of the deal are far-ranging. Keppel Corp’s business ranges from property to infrastructure to telecommunications, including Keppel Land and a partial stake in major Singapore telco M1. Temasek has already said that it does not intend to delist and privatise Keppel Corp, and has a long-standing history of not interfering or getting involved in the operations or decisions of its portfolio companies.

This might be different. Speculation is that this move, if successful could lead to a restructuring of the Singapore offshore and marine industry. Since 2015, Singapore’s rig-building industry has been in the doldrums as global oil prices tumbled. Although prices have recovered, cost-cutting and investment reticence have provided a slower recovery for the industry. In Singapore, this has affected the two major rigbuilders – Keppel O&M and its rival Sembcorp Marine. In 2018, Keppel O&M reported a loss of over SS$100 million (although much improved from its previous loss of over SS$800 million); Sembcorp Marine, too, faces a challenging market, with a net loss of nearly 50 million. Temasek itself is already a majority shareholder in Sembcorp Marine.

Once Keppel Corp is under Temasek’s control, this could lead to consolidation in the industry. There are many pros to this, mainly the merging of rig-building operations and shipyards will put Singapore is a stronger position against giant shipyards of China and South Korea, which have been on an asset buying spree. With the overhang of the Sete Brasil scandal over as both Keppel O&M and Sembcorp Marine have settled corruption allegations over drillship and rig contracts, a merger is now increasingly likely. It would sort of backtrack from Temasek’s recent direction in steering away from fossil fuel investments (it had decided to not participate in the upcoming Saudi Aramco IPO for environmental concerns) but strengthening the Singaporeans O&M industry has national interest implications. As a representative of Temasek said of its portfolio – ‘(we are trying to) re-purpose some businesses to try and grasp the demands of tomorrow.’ So, if there is to be a tomorrow, then Singapore’s two largest offshore players need to start preparing for that now in the face of tremendous competition. And once again it will fall on the Singaporean government, through Temasek, to facilitate an arranged marriage for the greater good.

Keppel and Sembcorp O&M at a glance:

Keppel Offshore & Marine, 2018

  • Revenue: S$1.88 billion (up from S$1.80 billion)
  • Net Profit: -S$109 million (up from -S$826 million)
  • Contracts secured: S$1.7 billion

Sembcorp Marine, 2018

  • Turnover: S$4.88 billion (up from S$3.03 billion)
  • Net Profit: -S$48 million (down from S$157 million)
  • Contracts secured: S$1.2 billion
October, 22 2019
Global energy consumption driven by more electricity in residential, commercial buildings

Energy used in the buildings sector—which includes residential and commercial structures—accounted for 20% of global delivered energy consumption in 2018. In its International Energy Outlook 2019 (IEO2019) Reference case, the U.S. Energy Information Administration (EIA) projects that global energy consumption in buildings will grow by 1.3% per year on average from 2018 to 2050. In countries that are not part of the Organization for Economic Cooperation and Development (non-OECD countries), EIA projects that energy consumed in buildings will grow by more than 2% per year, or about five times the rate of OECD countries.

building sector energy consumption

Source: U.S. Energy Information Administration, International Energy Outlook 2019 Reference case

Electricity—the main energy source for lighting, space cooling, appliances, and equipment—is the fastest-growing energy source in residential and commercial buildings. EIA expects that rising population and standards of living in non-OECD countries will lead to an increase in the demand for electricity-consuming appliances and personal equipment.

EIA expects that in the early 2020s, total electricity use in buildings in non-OECD countries will surpass electricity use in OECD countries. By 2050, buildings in non-OECD countries will collectively use about twice as much electricity as buildings in OECD countries.

average annual change in buildings sector electricity consumption

Source: U.S. Energy Information Administration, International Energy Outlook 2019 Reference case
Note: OECD is the Organization for Economic Cooperation and Development.

In the IEO2019 Reference case, electricity use by buildings in China is projected to increase more than any other country in absolute terms, but India will experience the fastest growth rate in buildings electricity use from 2018 to 2050. EIA expects that use of electricity by buildings in China will surpass that of the United States by 2030. By 2050, EIA expects China’s buildings will account for more than one-fifth of the electricity consumption in buildings worldwide.

As the quality of life in emerging economies improves with urbanization, rising income, and access to electricity, EIA projects that electricity’s share of the total use of energy in buildings will nearly double in non-OECD countries, from 21% in 2018 to 38% in 2050. By contrast, electricity’s share of delivered energy consumption in OECD countries’ buildings will decrease from 24% to 21%.

building sector electricity consumption per capita by region

Source: U.S. Energy Information Administration, International Energy Outlook 2019 Reference case
Note: OECD is the Organization for Economic Cooperation and Development.

The per capita use of electricity in buildings in OECD countries will increase 0.6% per year between 2018 and 2050. The relatively slow growth is affected by improvements in building codes and improvements in the efficiency of appliances and equipment. Despite a slower rate of growth than non-OECD countries, OECD per capita electricity use in buildings will remain higher than in non-OECD countries because of more demand for energy-intensive services such as space cooling.

In non-OECD countries, the IEO2019 Reference case projects that per capita electricity use in buildings will grow by 2.5% per year, as access to energy expands and living standards rise, leading to increased use of electric-intensive appliances and equipment. This trend is particularly evident in India and China, where EIA projects that per capita electricity use in buildings will increase by 5.3% per year in India and 3.6% per year in China from 2018 to 2050.

October, 22 2019