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Last Updated: March 13, 2019
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Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $64 per barrel (b) in February, up $5/b from January 2019 and about $1/b lower than at the same time last year. EIA forecasts Brent spot prices will average $63/b in 2019 and $62/b in 2020, compared with an average of $71/b in 2018. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $9/b lower than Brent prices in the first half of 2019 before the discount gradually falls to $4/b in the fourth quarter of 2019 and throughout 2020.
  • EIA estimates that U.S. crude oil production averaged 11.9 million barrels per day (b/d) in February, down slightly from the January average. EIA forecasts that U.S. crude oil production will average 12.3 million b/d in 2019 and 13.0 million b/d in 2020, with most of the growth coming from the Permian region of Texas and New Mexico.
  • Net imports of U.S. crude oil and petroleum products fell from an average of 3.8 million b/d in 2017 to an average of 2.3 million b/d in 2018. EIA forecasts that net imports will continue to fall to an average of 1.0 million b/d in 2019 and to an average net export level of 0.1 million b/d in 2020. In the fourth quarter of 2020, EIA forecasts that the United States will be a net exporter of crude oil and petroleum products by about 0.9 million b/d.

Natural gas

  • The Henry Hub natural gas spot price averaged $2.69/million British thermal units (MMBtu) in February, down 42 cents/MMBtu from January. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices will average $2.85/MMBtu in 2019, down 30 cents/MMBtu from 2018. NYMEX futures and options contract values for June 2019 delivery traded during the five-day period ending March 7, 2019, suggest a range of $2.40/MMBtu to $3.51/MMBtu encompasses the market expectation for June 2019 Henry Hub natural gas prices at the 95% confidence level.
  • EIA forecasts that dry natural gas production will average 90.7 billion cubic feet per day (Bcf/d) in 2019, up 7.4 Bcf/d from 2018. EIA expects natural gas production will continue to rise in 2020 to an average of 92.0 Bcf/d.
  • EIA expects natural gas inventories will end March at 1.2 trillion cubic feet (Tcf), which would be 14% lower than levels from a year earlier and 28% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the April-through-October injection season and that inventories will reach 3.6 Tcf at the end of October, which would be 12% higher than October 2018 levels and 2% below the five-year average.


World liquid fuels production and consumption balance

U.S. natural gas prices


Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 37% in 2019 and in 2020. EIA forecasts that the share of electricity generation from coal will average 25% in 2019 and 23% in 2020, down from 27% in 2018. The nuclear share of generation was 19% in 2018, and EIA forecasts that it will stay near that level in 2019 and in 2020. The generation share of hydropower is forecast to average slightly less than 7% of total generation in 2019 and in 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided about 10% of electricity generation in 2018. EIA expects they will provide 11% in 2019 and 13% in 2020.
  • In 2019, EIA expects wind’s annual share of electricity generation will exceed hydropower’s share for the first time. EIA forecasts that wind generation will rise from 753,000 megawatt hours per day (MWh/d) in 2018 to 861,000 MWh/d in 2019 (a share of 8%). Wind generation is projected to rise to 963,000 MWh/d (a share of 9%) by 2020.
  • EIA estimates that U.S. coal exports increased by 19 million short tons (MMst) (19%) in 2018, totaling 116 MMst. EIA expects declines in both steam coal and metallurgical coal (used in the steelmaking process) exports in 2019 and in 2020. Metallurgical coal exports are forecast to decline by 10 MMst (16%) in 2019 and by an additional 3 MMst (5%) in 2020 as the forecast’s global economic growth slows and decreases the demand for steel. Exports of steam coal, used primarily in electricity generation, are expected to decline by 5 MMst (10%) in 2019 and in 2020. Although forecast steam coal exports to non-traditional markets (North Africa, non-EU Europe, Central and South America) remain strong, exports to traditional markets, particularly the EU, will see demand for steam coal decline as countries initiate plans to limit/eliminate coal-fired electricity generation.
  • After rising by 2.9% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.6% in 2019 and by 0.5% in 2020. The 2018 increase largely reflected increased weather-related natural gas use because of additional heating needs during a colder winter and for higher electric generation to support more summer cooling use than in 2017. EIA expects emissions to fall in 2019 and in 2020 because of forecasted temperatures that will return to near normal and natural gas and renewables making up a higher share of electricity generation. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

U.S. residential electricity price

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Renewables became the second-most prevalent U.S. electricity source in 2020

In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.

In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.

Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.

We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.

monthly U.S electricity generation from all sectors, selected sources

Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.

July, 29 2021
PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021
Abu Dhabi Lifts The Tide For OPEC+

The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.

How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.

The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.

The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.

On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.

But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.

For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.

End of Article 

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Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Worries about new Covid-19 infections worldwide dragging down demand just as OPEC+ announced that it would be raising production by 400,000 b/d a month from August onward triggered a slide in Brent and WTI crude prices below US$70/b
  • However, that slide was short lived as near-term demand indications showed the consumption remained relatively resilient, which lifted crude prices back to their previous range in the low US$70/b level, although the longer-term effects of the Covid-19 delta variants are still unknown at this moment
  • Clarity over supply and demand will continue to be lacking given the fragility of the situation, which suggests that crude prices will remain broadly rangebound for now

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July, 26 2021