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Last Updated: May 13, 2020
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Forecast Highlights

Global liquid fuels

  • Although all market outlooks are subject to many risks, the May edition of EIA’s Short-Term Energy Outlook remains subject to heightened levels of uncertainty because the effects on energy markets of mitigation efforts related to the 2019 novel coronavirus disease (COVID-19) are still evolving. Reduced economic activity related to the COVID-19 pandemic has caused significant changes in energy supply and demand patterns. Crude oil prices, in particular, have fallen significantly since the beginning of 2020, largely driven by reduced oil demand because of COVID-19 mitigation efforts. Despite the April agreement between the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) to reduce production levels beyond the end of the STEO forecast period, crude oil prices have remained at some of their lowest levels in more than 20 years. Uncertainties persist across EIA’s outlook for other energy sources, including natural gas, electricity, coal, and renewables.
  • Brent crude oil prices averaged $18 per barrel (b) in April, a decrease of $13/b from the average in March. EIA forecasts Brent crude oil prices will average $34/b in 2020, down from an average of $64/b in 2019. EIA expects prices will average $23/b during the second quarter of 2020 before increasing to $32/b during the second half of the year. EIA forecasts that Brent prices will rise to an average of $48/b in 2021, $2/b higher than forecast last month, as EIA expects that declining global oil inventories next year will put upward pressure on oil prices.
  • EIA estimates global petroleum and liquid fuels consumption averaged 94.1 million barrels per day (b/d) in the first quarter of 2020, a decline of 5.8 million b/d from the same period in 2019. EIA expects global petroleum and liquid fuels demand will average 92.6 million b/d in 2020, a decrease of 8.1 million b/d from last year, before increasing by 7.0 million b/d in 2021. Lower global oil demand growth for 2020 in the May STEO reflects growing evidence of disruptions to global economic activity along with reduced expected travel globally as a result of restrictions related to COVID-19.
  • EIA expects that global liquid fuels inventories will grow by an average of 2.6 million b/d in 2020 after falling by 0.2 million b/d in 2019. EIA expects inventory builds will be largest in the first half of 2020, rising at a rate of 6.6 million b/d in the first quarter and increasing to builds of 11.5 million b/d in the second quarter as a result of widespread travel limitations and sharp reductions in economic activity. Firmer demand growth as the global economy begins to recover and slower supply growth will contribute to global oil inventory draws beginning in the third quarter of 2020. EIA expects global liquid fuels inventories will fall by 1.9 million b/d in 2021.
  • EIA forecasts significant decreases in U.S. liquid fuels demand during the first half of 2020 as a result of COVID-19 travel restrictions and disruptions to business and economic activity. EIA expects the largest impacts will occur in the second quarter of 2020 before gradually dissipating over the next 18 months. EIA expects U.S. motor gasoline consumption to fall from 8.6 million b/d in the first quarter of 2020 to an average of 7.0 million b/d in the second quarter before gradually increasing to 8.7 million b/d in the second half of the year. U.S. jet fuel consumption will fall from 1.6 million b/d in the first quarter of 2020 to an average of 0.8 million b/d in the second quarter. U.S. distillate fuel oil consumption is forecast to decline by 0.6 million b/d to average 3.3 million b/d during the same period. For all of 2020, EIA forecasts that U.S. motor gasoline consumption will average 8.3 million b/d, a decrease of 11% compared with 2019, while jet fuel and distillate fuel oil consumption will fall by 25% and 10%, respectively, during the same period.
  • EIA has revised its current forecast of domestic crude oil production down from the April STEO as a result of lower crude oil prices. EIA forecasts U.S. crude oil production will average 11.7 million b/d in 2020, down 0.5 million b/d from 2019. In 2021, EIA expects U.S. crude oil production to decline further by 0.8 million b/d. If realized, the 2020 production decline would mark the first annual decline since 2016. U.S. crude oil production has not declined for two years in a row since the 17-year period of declines beginning in 1992 and running through 2008. Typically, price changes affect production after about a six-month lag. However, current market conditions will likely reduce this lag as many producers have already announced plans to reduce capital spending and drilling levels.

Natural gas

  • In April, the Henry Hub natural gas spot price averaged $1.73 per million British thermal units (MMBtu). EIA forecasts that natural gas prices will generally rise through the rest of 2020 as U.S. production declines. EIA forecasts that Henry Hub natural gas spot prices will average $2.14/MMBtu in 2020 and then increase in 2021, reaching an annual average of $2.89/MMBtu. EIA expects prices to rise largely because of lower natural gas production compared with 2020.
  • EIA expects total consumption of natural gas to average 81.7 billion cubic feet per day (Bcf/d) in 2020, down 3.9% from the 2019 average primarily because of lower industrial sector consumption of natural gas. EIA forecasts industrial natural gas consumption to average 21.3 Bcf/d in 2020, down 7.1% from 2019 as a result of lower expected manufacturing activity. This expected decline is lower than the 0.3% decline forecast in the April STEO because of large downward revisions to the macroeconomic forecast in the May STEO.
  • U.S. dry natural gas production set a record in 2019, averaging 92.2 Bcf/d. EIA forecasts dry natural gas production will average 89.8 Bcf/d in 2020, with monthly production falling from an estimated 93.1 Bcf/d in April to 85.4 Bcf/d in December. Natural gas production declines the most in the Appalachian region and Permian region. In the Appalachian region, low natural gas prices are discouraging producers from engaging in natural gas-directed drilling, and in the Permian region, low oil prices reduce associated gas output from oil-directed wells. In 2021, forecast dry natural gas production averages 84.9 Bcf/d, rising in the second half of 2021 in response to higher prices.
  • EIA estimates that total U.S. working natural gas in storage ended April at 2.3 trillion cubic feet (Tcf), 20% more than the five-year (2015–19) average. In the forecast, inventories rise by 2.1 Tcf during the April through October injection season to reach almost 4.2 Tcf on October 31, which would be a record level.
  • EIA forecasts that U.S. liquefied natural gas exports will average 5.8 Bcf/d in the second quarter of 2020 and 4.8 Bcf/d in the third quarter of 2020. U.S. liquefied natural gas exports are expected to decline through the end of the summer as a result of lower expected global demand for natural gas.

Electricity, coal, renewables, and emissions

  • Although some stay-at-home orders are beginning to be relaxed, the effects of social distancing guidelines are likely to continue affecting U.S. electricity consumption during the next few months. EIA expects retail sales of electricity in the commercial sector will fall by 6.5% in 2020 because many businesses have closed and many people are working from home. Similarly, EIA expects industrial retail sales of electricity will fall by 6.5% in 2020 as many factories cut back production. Forecast U.S. sales of electricity to the residential sector fall by 1.3% in 2020 because of lower electricity demand as a result of milder winter and summer weather, which is offset slightly by increased household electricity consumption as much of the population spends relatively more time at home.
  • EIA forecasts that total U.S. electric power sector generation will decline by 5% in 2020. Most of the expected decline in electricity supply is reflected in lower fossil fuel generation, especially at coal-fired power plants. EIA expects that coal generation will fall by 25% in 2020. Forecast natural gas generation is relatively flat this year, reflecting favorable fuel costs and the addition of new generating capacity. Renewable energy sources account for the largest portion of new generating capacity in 2020, driving EIA’s forecast of 11% growth in renewable generation by the electric power sector. Renewable energy is typically dispatched whenever it is available because of its low operating cost.
  • Although EIA expects renewable energy to be the fastest-growing source of electricity generation in 2020, the effects the economic slowdown related to COVID-19 are likely to affect new generating capacity builds during the next few months. EIA expects the electric power sector will add 20.4 gigawatts of new wind capacity and 12.7 gigawatts of utility-scale solar capacity in 2020. However, these forecasts are subject to a high degree of uncertainty, and EIA will continue to monitor reported planned capacity builds.
  • EIA forecasts U.S. average coal consumption will decrease by 23% to 453 MMst in 2020. The decrease is primarily driven by a 24% decline in electric power sector consumption and persistently low natural gas prices. In 2021, consumption is expected to increase by 10% to 498 MMst because of stronger natural gas prices and an overall economic recovery that results in rising electricity generation.
  • After decreasing by 2.8% in 2019, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decrease by 11% (572 million metric tons) in 2020. This record decline is the result of restrictions on business and travel activity and slowing economic growth related to COVID-19. CO2 emissions decline from all fossil fuels, particularly coal (23%) and petroleum (11%). In 2021, EIA forecasts that energy-related CO2 emissions will increase by 5% as the economy recovers and stay-at-home orders are lifted. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

STEO Short-Term Energy Outlook liquid fuels EIA Brent Natural Gas Coal renewables emissions electricity
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Libya & OPEC’s Quota

The constant domestic fighting in Libya – a civil war, to call a spade a spade, has taken a toll on the once-prolific oil production in the North African country. After nearly a decade of turmoil, it appears now that the violent clash between the UN-recognised government in Tripoli and the upstart insurgent Libyan National Army (LNA) forces could be ameliorating into something less destructive with the announcement of a pact between the two sides that would to some normalisation of oil production and exports.

A quick recap. Since the 2011 uprising that ended the rule of dictator Muammar Gaddafi, Libya has been in a state of perpetual turmoil. Led by General Khalifa Haftar and the remnants of loyalists that fought under Gaddafi’s full-green flag, the Libyan National Army stands in direct opposition to the UN-backed Government of National Accord (GNA) that was formed in 2015. Caught between the two sides are the Libyan people and Libya’s oilfields. Access to key oilfields and key port facilities has changed hands constantly over the past few years, resulting in a start-stop rhythm that has sapped productivity and, more than once, forced Libya’s National Oil Corporation (NOC) to issue force majeure on its exports. Libya’s largest producing field, El Sharara, has had to stop production because of Haftar’s militia aggression no fewer than four times in the past four years. At one point, all seven of Libya’s oil ports – including Zawiyah (350 kb/d), Es Sider (360 kb/d) and Ras Lanuf (230 kb/d) were blockaded as pipelines ran dry. For a country that used to produce an average of 1.2 mmb/d of crude oil, currently output stands at only 80,000 b/d and exports considerably less. Gaddafi might have been an abhorrent strongman, but political stability can have its pros.

This mutually-destructive impasse, economically, at least might be lifted, at least partially, if the GNA and LNA follow through with their agreement to let Libyan oil flow again. The deal, brokered in Moscow between the warlord Haftar and Vice President of the Libyan Presidential Council Ahmed Maiteeq calls for the ‘unrestrained’ resumption of crude oil production that has been at a near standstill since January 2020. The caveat because there always is one, is that Haftar demanded that oil revenues be ‘distributed fairly’ in order to lift the blockade he has initiated across most of the country’s upstream infrastructure.

Shortly after the announcement of the deal, the NOC announced that it would kick off restarting oil production and exports, lifting an 8-month force majeure situation, but only at ‘secure terminals and facilities’. ‘Secure’ in this cases means facilities and fields where NOC has full control, but will exclude areas and assets that the LNA rebels still have control. That’s a significant limitation, since the LNA, which includes support from local tribal groups and Russian mercenaries still controls key oilfields and terminals. But it is also a softening from the NOC, which had previously stated that it would only return to operations when all rebels had left all facilities, citing safety of its staff.

If the deal moves forward, it would certainly be an improvement to the major economic crisis faced by Libya, where cash flow has dried up and basic utilities face severe cutbacks. But it is still an ‘if’. Many within the GNA sphere are critical of the deal struck by Maiteeq, claiming that it did not involve the consultation or input of his allies. The current GNA leader, Prime Minister Fayyaz al Sarraj is also stepping down at the end of October, ushering in another political sea change that could affect the deal. Haftar is a mercurial beast, so predictions are difficult, but what is certain is that depriving a country of its chief moneymaker is a recipe for disaster on all sides. Which is why the deal will probably go ahead.

Which is bad news for the OPEC+ club. Because of its precarious situation, Libya has been exempt for the current OPEC+ supply deal. Even the best case scenarios within OPEC+ had factored out Libya, given the severe uncertainty of the situation there. But if the deal goes through and holds, it could potentially add a significant amount of restored crude supply to global markets at a time when OPEC+ itself is struggling to manage the quotas within its own, from recalcitrant members like Iraq to surprising flouters like the UAE.

Mathematically at least, the ceiling for restored Libyan production is likely in the 300-400,000 b/d range, given that Haftar is still in control of the main fields and ports. That does not seem like much, but it will give cause for dissent within OPEC on the exemption of Libya from the supply deal. Libya will resist being roped into the supply deal, and it has justification to do so. But freeing those Libyan volumes into a world market that is already suffering from oversupply and weak prices will be undermining in nature. The equation has changed, and the Libyan situation can no longer be taken for granted.

Market Outlook:

  •  Crude price trading range: Brent – US$41-43/b, WTI – US$39-41/b
  • While a resurgence in Covid-19 cases globally is undermining faith that the ongoing oil demand recovery will continue unabated, crude markets have been buoyed by a show of force by Saudi Arabia and US supply disruptions from Tropical Storm Sally
  • In a week when Iraq’s OPEC+ commitments seem even more distant with signs of its crude exports rising and key Saudi ally the UAE admitting it had ‘pumped too much recently’, the Saudi Energy Minister issued a force condemnation on breaking quotas
  • On the demand side, the IEA revised its forecast for oil demand in 2020 to an annual decline of 8.4 mmb/d, up from 8.1 mmb/d in August, citing Covid resurgences
  • In a possible preview of the future, BP issued a report stating that the ‘relentless growth of oil demand is over’, offering its own vision of future energy requirements that splits the oil world into the pro-clean lobby led by Europeans and the prevailing oil/gas orthodoxy that remains in place across North America and the rest of the world

END OF ARTICLE

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September, 22 2020
Average U.S. construction costs for solar and wind generation continue to fall

According to 2018 data from the U.S. Energy Information Administration (EIA) for newly constructed utility-scale electric generators in the United States, annual capacity-weighted average construction costs for solar photovoltaic systems and onshore wind turbines have continued to decrease. Natural gas generator costs also decreased slightly in 2018.

From 2013 to 2018, costs for solar fell 50%, costs for wind fell 27%, and costs for natural gas fell 13%. Together, these three generation technologies accounted for more than 98% of total capacity added to the electricity grid in the United States in 2018. Investment in U.S. electric-generating capacity in 2018 increased by 9.3% from 2017, driven by natural gas capacity additions.

Solar
The average construction cost for solar photovoltaic generators is higher than wind and natural gas generators on a dollar-per-kilowatt basis, although the gap is narrowing as the cost of solar falls rapidly. From 2017 to 2018, the average construction cost of solar in the United States fell 21% to $1,848 per kilowatt (kW). The decrease was driven by falling costs for crystalline silicon fixed-tilt panels, which were at their lowest average construction cost of $1,767 per kW in 2018.

Crystalline silicon fixed-tilt panels—which accounted for more than one-third of the solar capacity added in the United States in 2018, at 1.7 gigawatts (GW)—had the second-highest share of solar capacity additions by technology. Crystalline silicon axis-based tracking panels had the highest share, with 2.0 GW (41% of total solar capacity additions) of added generating capacity at an average cost of $1,834 per kW.

average construction costs for solar photovoltaic electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Wind
Total U.S. wind capacity additions increased 18% from 2017 to 2018 as the average construction cost for wind turbines dropped 16% to $1,382 per kW. All wind farm size classes had lower average construction costs in 2018. The largest decreases were at wind farms with 1 megawatt (MW) to 25 MW of capacity; construction costs at these farms decreased by 22.6% to $1,790 per kW.

average construction costs for wind farms

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Natural gas
Compared with other generation technologies, natural gas technologies received the highest U.S. investment in 2018, accounting for 46% of total capacity additions for all energy sources. Growth in natural gas electric-generating capacity was led by significant additions in new capacity from combined-cycle facilities, which almost doubled the previous year’s additions for that technology. Combined-cycle technology construction costs dropped by 4% in 2018 to $858 per kW.

average construction costs for natural gas-fired electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

September, 17 2020
Fossil fuels account for the largest share of U.S. energy production and consumption

Fossil fuels, or energy sources formed in the Earth’s crust from decayed organic material, including petroleum, natural gas, and coal, continue to account for the largest share of energy production and consumption in the United States. In 2019, 80% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.

The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production and imports) to disposition (consumption, exports, and net stock additions). In this diagram, losses that take place when primary energy sources are converted into electricity are allocated proportionally to the end-use sectors. The result is a visualization that associates the primary energy consumed to generate electricity with the end-use sectors of the retail electricity sales customers, even though the amount of electric energy end users directly consumed was significantly less.

U.S. primary energy production by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but production has also risen for non-fossil fuel sources such as nuclear power and renewables. As a result, fossil fuels have accounted for about 80% of U.S. energy production in the past decade.

Since 2008, U.S. production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 15 quadrillion British thermal units (quads), 14 quads, and 4 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 10 quads since its peak in 2008.

U.S. primary energy overview and net imports share of consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

In 2019, U.S. energy production exceeded energy consumption for the first time since 1957, and U.S. energy exports exceeded energy imports for the first time since 1952. U.S. energy net imports as a share of consumption peaked in 2005 at 30%. Although energy net imports fell below zero in 2019, many regions of the United States still import significant amounts of energy.

Most U.S. energy trade is from petroleum (crude oil and petroleum products), which accounted for 69% of energy exports and 86% of energy imports in 2019. Much of the imported crude oil is processed by U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 42% of total U.S. energy exports in 2019.

U.S. primary energy consumption by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2019. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption has decreased by 11 quads. In 2019, renewable energy consumption in the United States surpassed coal consumption for the first time. The decrease in coal consumption, along with a 3-quad decrease in petroleum consumption, more than offset an 8-quad increase in natural gas consumption.

EIA previously published articles explaining the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

Principal contributor: Bill Sanchez

September, 15 2020