Written by Sig Silber
Updated at 9:08 pm EST December 11, 2020 to add some additional comments and to include the now issued Week 3-4 Weather Forecast.
The NASS Executive Briefing focused on cotton which recovered from a bad start but still had a subpar year. We had a science theme, mainly atmospheric waves, and how the phases of ENSO might interact with the Madden Julian Oscillation (MJO). We provided information on a wide variety of subjects from Western reservoir storage to horticulture. And of course, this article contains the intermediate-term weather forecast. This is the week when NOAA updates their ENSO forecast and we reported on that as well. We initiated coverage of the energy market.
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FLASH: NWS decides to only report good weather. Read here for more information. Well, that is not exactly it but it is kind of close to it. When the weather is good, the demands on their network are low. It will be interesting to see how they dig their way out of this PR fiasco.
Executive Briefing
Changing the focus let’s discuss a little meteorology which caught my attention because of the recent report that the Indo-Pacific warm pool was impacting not only ENSO but the higher frequency MJO waves that circumnavigate the globe every 30 to 60 days.
Catch a wave: how waves from the MJO and ENSO impact U.S. rainfall (Link to full article)
Author: Marybeth Arcodia September 24, 2020
Last week we took a look at how the Indo-Pacific Warm Pool has changed and the article mentioned the terms constructive and destructive interference. Perhaps a better term would be reinforcement. At any rate, the above article explains it and I selected one graphic and animations from the above article to explain the concept.
The MJO launches into action
Particularly important to U.S. weather and climate are atmospheric waves that start in the tropics and travel to the midlatitudes. One major source of these waves is the Madden-Julian Oscillation (MJO). The MJO sounds fancy and, let’s be honest, boring, but it’s not! The MJO is a system of very tall or deep convective clouds (storminess) that travels eastward along the tropical Indian and Pacific Oceans approximately every 30-60 days. The convective region of the MJO has enhanced storms and rainfall, and it is usually sandwiched to the east and west by dry, sunny areas.
Averages of all January – March MJO events from 1979 – 2016. Green shading shows below-average OLR (outgoing longwave radiation, or heat energy) values, indicating more clouds and rainfall, and brown shading identifies above-average OLR (drier and clearer skies than normal). The purple contours show the location and strength of the Pacific jet at the 200-hPa level (roughly 38,000 feet at that location). Note the eastward movement of the wet and dry areas. How far the Pacific jet extends past the international dateline also changes with the phase of the MJO. NOAA Climate.gov animation, adapted from original images provided by Carl Schreck.
To complicate things further, these modified MJO waves and the ENSO waves are now both traveling at different speeds at the top of the atmosphere and interact with each other, in the same way the wakes from two boats interfere. The interaction of these waves and their signals plays a role in U.S. weather via changes in pressure, temperature, etc.
Two climate signals interfering (i.e., combining) with each other. Bold blue curve sketches the result of the combination. Horizontal bars indicate conceptual thresholds for the occurrence of extremely wet and dry events. Animation adapted by Climate.gov from http://www.acs.psu.edu/drussell/Demos/superposition/superposition.html.
The waves from the MJO and the waves from ENSO together impact U.S. rainfall through constructive or destructive interference. Constructive interference occurs when two waves are in phase (4), and the resultant wave has a much larger amplitude, resulting in a stronger signal than either of the individual waves. The opposite, called destructive interference, occurs when two waves are out of phase and cancel each other (5). You may have experienced destructive signal interference when your radio signal gets interrupted by another station and you hear a mix of two stations or no sound at all.
Severe Weather
Let’s look at the current drought situation.
And the week to week change
And the three-month change
Here we look at four-time periods: one week, one month, six months, and a full year.
And the discussion released with the drought report
December Drought Outlook
Here is the weekly U.S. Crop Progress Report.
Actually, there was no report this week probably because we are down to winter wheat in most places. So I provided a report on horticulture instead.
Intermediate-Term Weather Forecast
Showing from left to right, Days 1- 5, 6 – 10, 8 – 14, and Weeks 3 – 4 You can click on these maps to have them enlarge. Also, the discussions that go with these forecast maps can be found here (first two weeks) and here (Weeks 3 and 4).
First Temperature
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And then Precipitation
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Since I am updating this article on Friday, I might as well include the discussion which was issued with the Week 3-4 Update.
Week 3-4 Forecast Discussion Valid Sat Dec 26 2020-Fri Jan 08 2021
A weak Madden-Julian Oscillation (MJO) event is located over the Maritime Continent with most of its active convection over northern Australia. Its RMM projection is enhanced by an equatorial Rossby wave, which both the CFS and ECMWF forecast to quickly move into the Indian Ocean by the middle of Week-1. At that point we expect the RMM index to weaken again as the MJO shifts eastward and interacts with the anomalously cold central Pacific sea surface temperatures (SSTs). Since the MJO isn’t expected to play a major role in the Week 3-4 pattern, this forecast is based primarily on a combination of dynamical models and an expected La Nina contribution.
There is good agreement among the ECMWF, JMA, and SubX multi-model ensemble means regarding the predicted 500-hPa height pattern. Positive height anomalies are forecast over the southwestern U.S. and New England while negative height anomalies are forecast over Alaska. Negative height anomalies also extend over the Southeast, but they are significantly weaker than those found over Alaska and the predicted temperature fields don’t align well with this southeastern extension.
The expected height pattern is often favorable for Nor’easter cyclones along the East Coast and associated above normal precipitation is predicted throughout the Northeast and mid-Atlantic. Precipitation odds tilt below normal over most of Alaska, with the highest probabilities of below normal precipitation in the westernmost regions of the state. Chances increase for above normal precipitation associated with the aforementioned troughing off the Pacific Northwest coast as well. Dry conditions are favored along the southern tier of the U.S., from southwestern California to Florida. This pattern is common during La Nina winters and is also predicted in most dynamical model guidance. Warm SSTs and consistency amongst the dynamical models suggest weak probabilities of above normal rainfall over Hawaii. A 55-60% chance is forecast throughout the state.
Temperatures are favored to be above normal for most of the Lower 48, with equal chances of above and below normal over much of the Southeast. The warmest temperatures are likely to be west of the Rockies, where there is a 60-70% chance of above normal temperatures. Below normal temperatures are expected over most of Alaska, with probabilities of 60-70% extending westward to the Aleutians. Elevated above normal temperatures probabilities are also forecast uniformly throughout Hawaii as SSTs remain above normal throughout the region.
Turning to Energy
December 8, 2020 Release
Highlights
The December Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply patterns in 2020 and will continue to affect these patterns in the future. U.S. gross domestic product (GDP) declined by 4.4% in the first half of 2020 from the same period a year ago. GDP began rising in the third quarter of 2020, and this STEO assumes it will grow by 3.1% annually in 2021 from 2020. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit completed in early November.
Brent crude oil spot prices averaged $43 per barrel (b) in November, up $3/b from the average in October. Brent prices increased in November in part because of news about the viability of multiple COVID-19 vaccines, along with market expectations that the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) would delay or limit production increases planned for January 2021.
The U.S. Energy Information Administration (EIA) expects that Brent prices will average $49/b in 2021, up from an expected average of $43/b in the fourth quarter of 2020. The forecast for higher crude oil prices next year reflects EIA’s expectation that while inventories will remain high, they will decline with global oil demand and restrained OPEC+ oil production. EIA forecasts Brent prices will average $47/b in the first quarter of 2021 and rise to an average of $50/b by the fourth quarter. The first quarter 2021 average is $5/b more than forecast in last month’s STEO, and the fourth quarter average is $1/b more. The higher expected first quarter prices reflect steeper expected global oil inventory draws as a result of the December 3 OPEC+ decision to limit its previously planned production increases in January 2021. EIA expects high global oil inventory levels and surplus crude oil production capacity will limit upward pressure on oil prices through much of 2021.
EIA forecasts OPEC crude oil production will average 27.5 million barrels per day (b/d) in 2021, up from an estimated 25.6 million b/d in 2020. The increase reflects OPEC’s announced potential increases to production targets and production increases in Libya. At the December 3 meeting, OPEC and OPEC+ participants decided to limit oil production increases planned for January 2021. OPEC+ announced it will increase its production target by 0.5 million b/d in January 2021. The group had initially planned to increase its target by 2.0 million b/d. The group will also assess the state of global oil markets and petroleum demand monthly, adjusting targets based on market conditions. EIA now forecasts OPEC crude oil production will average 25.7 million b/d in the first quarter of 2021, which is 1.7 million b/d lower than forecast in the November STEO and reflects the announced changes to OPEC+ targets and more effective assumed compliance with targets.
EIA estimates that the world consumed 95.6 million b/d of petroleum and liquid fuels in November, which is down 6.3 million b/d from November 2019 but up from the third-quarter 2020 average of 93.5 million b/d. EIA forecasts that global consumption of petroleum and liquid fuels will average 92.4 million b/d for all of 2020, which is down by 8.8 million b/d from 2019, before increasing by 5.8 million b/d in 2021.
EIA estimates that U.S. crude oil production was 11.2 million b/d in November, which is up from 10.9 million b/d in September (the most recent month for which historical data are available). The increase mostly reflects greater production in the U.S. Federal Gulf of Mexico after hurricane-related disruptions. EIA expects that U.S. crude oil production will decline to less than 11.0 million b/d in March 2021 because of falling production in the Lower 48 states, where EIA expects declining production rates at existing wells will outpace production from newly drilled wells in the coming months. EIA expects crude oil production in the Lower 48 states will increase from 8.7 million b/d in February 2021 to 9.1 million b/d in December 2021, as drilling increases in response to rising oil prices. This increase contributes to total U.S. crude oil production reaching 11.4 million b/d in December 2021. On an annual average basis, EIA expects U.S. crude oil production to fall from 12.2 million b/d in 2019 to 11.3 million b/d in 2020 and 11.1 million b/d in 2021.
In November, the Henry Hub natural gas spot price averaged $2.61 per million British thermal units (MMBtu), up from the October average of $2.39/MMBtu. Price increases last month were moderated by significantly warmer-than-normal temperatures, which reduced residential space heating demand for natural gas despite many remaining at home in response to the pandemic. EIA expects Henry Hub spot prices to reach a monthly average of $3.10/MMBtu in January 2021, which is down from the forecast January average price of $3.42/MMBtu in last month’s STEO. Although EIA still expects prices to increase in the coming months because of rising space heating demand and rising U.S. liquefied natural gas (LNG) exports amid declining U.S. natural gas production, the lower January price forecast reflects higher forecast storage levels this winter compared with last month’s forecast. EIA expects that monthly average spot prices will average $3.01/MMBtu in 2021, which is up from the forecast average of $2.07/MMBtu for 2020.
U.S. working natural gas in storage ended October at almost 4.0 trillion cubic feet (Tcf), 5% more than the five-year (2015 – 19) average and the second-highest end-of-October level on record. EIA estimates that inventories fell by 20 billion cubic feet (Bcf) in November, compared with a five-year average November withdrawal of 103 Bcf and a forecast withdrawal of 222 Bcf in last month’s STEO. The lower-than-expected withdrawal is the result of warmer-than-normal November temperatures that reduced natural gas use for space heating. However, EIA forecasts that declines in U.S. natural gas production this winter compared with last winter will more than offset the declines in natural gas consumption, which will contribute to inventory withdrawals outpacing the five-year average during the remainder of the winter season that ends in March. Forecast natural gas inventories end March 2021 at 1.6 Tcf, 15% lower than the 2016 – 20 average.
EIA expects that total U.S. consumption of natural gas will average 83.4 billion cubic feet per day (Bcf/d) in 2020, down 2.0% from 2019. The decline in total U.S. consumption reflects warmer temperatures in 2020 compared with 2019 that lowered residential space heating demand for natural gas despite many staying home in response to the pandemic. EIA expects residential demand in 2020 to average 12.9 Bcf/d (down 0.8 Bcf/d from 2019) and commercial demand in 2020 to average 8.6 Bcf/d (down 1.0 Bcf/d from 2019). EIA forecasts industrial consumption will average 22.5 Bcf/d in 2020 (down 0.5 Bcf/d from 2019) as a result of reduced manufacturing activity. EIA expects total U.S. natural gas consumption will average 79.4 Bcf/d in 2021, a 4.8% decline from 2020. The forecast decline in 2021 results from rising natural gas prices that lower forecast natural gas demand in the electric power sector.
EIA forecasts U.S. dry natural gas production will average 90.9 Bcf/d in 2020, which is down from an average of 93.1 Bcf/d in 2019. In the forecast, monthly average production falls from a record 97.0 Bcf/d in December 2019 to 87.1 Bcf/d in April 2021 before increasing slightly. EIA forecasts dry natural gas production in the United States to average 87.9 Bcf/d in 2021. EIA expects production to begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices. The increase in crude oil prices is expected to raise associated gas production from oil-directed wells in late-2021, especially in the Permian region.
EIA estimates that the United States exported 9.4 Bcf/d of LNG in November – the most for any month on record. International spot and forward LNG prices continued to increase in November, supported by reduced global LNG supply because of outages at LNG export plants in several countries and reported congestion at the Panama Canal, which affected westbound U.S. LNG exports to Asia. EIA expects LNG demand to continue increasing. The primary drivers of this increase are forecasts of colder-than-normal winter weather in Northern Asia and Europe and coal plant closures in South Korea that could increase demand for natural gas for power generation. EIA forecasts that U.S. LNG exports will exceed 9.5 Bcf/d from December through February and will average 8.5 Bcf/d in 2021, a 30% increase from 2020.
EIA forecasts that consumption of electricity in the United States will decrease by 3.9% in 2020. EIA expects retail sales of electricity in the commercial sector to fall this year by 5.9% and by 8.8% in the industrial sector. EIA forecasts residential sector retail sales will rise by 1.5% in 2020. Milder winter temperatures in early 2020 led to less residential consumption for space heating, but this effect was offset by increased summer cooling demand and increased electricity use by more people staying home in response to the pandemic. EIA forecasts total U.S. electricity consumption will rise by 1.3% in 2021. The increase in electricity consumption next year is a result of forecast colder temperatures in the first quarter compared with the same period last year, in addition to continued higher consumption as many people will still be at home more because of the pandemic.
EIA expects the share of U.S. electric power sector generation from natural gas will increase from 37% in 2019 to 39% this year. In 2021, the forecast natural gas share declines to 34% in response to a forecast increase in the price of natural gas delivered to electricity generators from an average of $2.44/MMBtu in 2020 to $3.38/MMBtu in 2021 (an increase of 39%). Coal’s forecast share of electricity generation falls from 24% in 2019 to 20% in 2020 and then returns to 24% in 2021. Electricity generation from renewable energy sources rises from 18% in 2019 to 20% in 2020 and to 21% in 2021. The nuclear share of U.S. generation remains close to 20% through the forecast period.
In 2020, EIA expects U.S. residential electricity prices to average 13.1 cents per kilowatthour, which is 0.8% higher than the average electricity price in 2019. Annual changes in regional residential electricity prices this year range from 0.4% lower in the South Atlantic region to 3.7% higher in the Pacific region.
EIA forecasts that planned additions to wind and solar generating capacity in 2020 and 2021 will contribute to increasing electricity generation from those sources. EIA expects the U.S. electric power sector will add 23.0 gigawatts (GW) of new wind capacity in 2020 and 9.5 GW of new capacity in 2021. Expected utility-scale solar capacity rises by 12.8 GW in 2020 and by 14.0 GW in 2021.
EIA forecasts U.S. coal production to total 521 million short tons (MMst) in 2020, a 26% decline from 2019. Forecast coal production rises to 624 MMst in 2021, a 20% increase from 2020 levels. EIA expects coal production to grow because of increased coal demand from the electric power sector amid higher natural gas prices in 2021.
EIA expects that U.S. energy-related carbon dioxide (CO2) emissions, after decreasing by almost 3% in 2019 from the previous year’s level, will decrease by 11% in 2020. This decline in emissions is the result of less energy consumption related to slowing economic growth in response to the COVID-19 pandemic. EIA expects emissions from coal will be down 19% from 2019 and emissions from petroleum will be down 13% from 2019. In 2021, EIA forecasts that energy-related CO2 emissions will increase by 6% from the 2020 level as the economy recovers and energy use increases.
International
This week we do not have a map.
Major Sources of Information
In the box are shown the major resources we use. We will not be using them all each week but the reader is welcome to refer to these resources.
Major Sources of Information Used in this Weekly Report
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