About the Energy Outlook
Get the details on pricing trends, weather, storage levels, tariffs and more.
The Energy Outlook is designed to inform you about the current state of the natural gas and electric energy markets. While prices are most important, we offer insights into the drivers of the energy markets and shed some light on how these drivers impact market prices. The primary energy market drivers fall into 2 areas: Fundamentals and Politics.
- Fundamentals are the factors influencing energy supply and demand of electricity and natural gas. Supply factors include power generation, natural gas production (drilling rigs, fracking, and horizontal boring), underground gas storage, and pipeline capacity. Demand factors include consumer usage and weather (driving how much energy is required for heating and air conditioning seasons).
- Politics include changes to the legal and regulatory environment that can cause major moves in energy prices. Political impacts can be new emission standards, such as mandated movement to cleaner generation facilities with higher operating costs, new energy taxes or fees, and restrictions on new pipeline or transmission line placement. Political factors can be domestic or international.
Q2 2020 Outlook
Long-Term Energy Prices Remain Attractive
Natural Gas Storage
Healthy Storage Continues to Grow
NOAA Predicts a Warmer Summer
Near-Term Prices Slightly Up, Long-Term Prices Are Flat
COVID-19 Containment Measures Depress Global Energy Demand
New England’s Average Real-Time Electricity Lowest in Market History
Long-Term Natural Gas Prices Remain Low
Long-Term Energy Prices Remain Attractive
Cooler than normal temps dominate the forecast over the next few weeks. This should relate to a slight jump in Heating Degree Day demand, but it won’t offset the demand declines due to COVID-19 shutdowns. The complete demand picture for the near term has yet to come into focus as the market fluctuates based on current news cycles. Markets recently trended higher as the 12-month NYMEX natural gas curve moved up 1.9% and the 12-month PJM Western Hub increased 0.72%.
Natural Gas Storage
Healthy Storage Continues to Grow
The Energy Information Administration (EIA) “Natural Gas Storage Report” shows working gas in storage was 2,210 as of Friday, April 24, 2020, according to EIA estimates. This represents a net increase of 70 BCF from the previous week. Stocks were 783 BCF higher than last year at this time and 360 BCF above the five-year average of 1,850 BCF. At 2,210 BCF, total working gas is within the five-year historical range.
|Natural Gas Storage Levels (Bcf)|
|Current Storage Level||2,210|
|Storage – One Year Ago||1,427|
|5-Year Average Level||1,850|
The traditional injection season into the natural gas storage starts in April and ends in October. The industry recently recorded its fourth injection of the season. The first two injections were bigger than normal, but the latest April cold snap caused the last two injections to come in below average with the last one registering at 70 BCF, a volume 5% below the 5-year average.
Regardless, due to the unusually warmer winter we just experienced, we had enough natural gas in storage for a nice head start. We are currently almost at 20% above the 5-year average compared to 18% below average in the same period last year. We shall see how this story unfolds in the next few months due to COVID-19, reduced production and weather influence.
NOAA Predicts a Warmer Summer
This past winter was the sixth warmest on record. The unusually low heating demands combined with record-high gas supplies placed downward pressure on energy prices over the winter period. NOAA’s weather service is predicting a high probability of above-average temperatures across much of the country during the upcoming summer months with the exception of the middle of the country, where we have a 50/50 chance.
Several weather models point to increased hurricane activity for the 2020 season. The risk for a direct hit from a storm is higher than normal for the Gulf & East Coasts. Warmer-than-normal water temperatures can be a big factor for increased number and intensity of storms. The transition toward La Niña is adding to the favorable environment for storm development.
Near-Term Prices Are Slightly Up – Long-Term Prices Are Flat
The Energy Outlook mainly focuses on natural gas prices because gas prices lead electricity prices. As natural gas prices increase or decrease, electricity prices often follow suit – but hours, days or weeks later. Also, natural gas has a national price established on the NYMEX. Other regional prices and markets exist but are compared with the NYMEX prices. Electricity is different because the U.S. is divided into 6 regional markets, each setting its own price and having its unique market rules. All six regions tend to move in the same direction, but price volatility and generation vary considerably between regions.
Natural Gas 12-month strip prices have maintained levels over the last quarter with a recent uptick. The projected drop in natural gas demand due to COVID-19 didn’t materialize because April was much cooler than normal. People stayed home and kept their heat on throughout the month. Currently, 12-month strip prices are at $2.60. Monthly settlement prices have stayed below $2.00 since February 2020. Next winter strip (November 2020 through March 2022) is averaging at just below $3.00.
Global Energy Review 2020
The impacts of the COVID-19 crisis on global energy demand and CO2 emissions
IEA Report Overview – April 2020
The current COVID-19 pandemic is, above all, a global health crisis. As of 28 April, there were 3 million confirmed cases and over 200,000 deaths due to the illness. As a consequence of the efforts to slow the spread of the virus, the share of energy use that was exposed to containment measures jumped from 5% in mid-March to 50% in mid-April. Several European countries and the United States have announced that they expect to reopen parts of the economy in May, so April may be the hardest-hit month.
Beyond the immediate impact on public health, the current crisis has major implications for global economies, energy use and CO2 emissions. Our analysis of daily data through mid-April shows that countries in full lockdown are experiencing an average 25% decline in energy demand per week, and countries in partial lockdown average an 18% decline. Daily data collected for 30 countries until 14 April, representing over two-thirds of global energy demand, show that demand depression depends on duration and stringency of lockdowns.
Global energy demand declined by 3.8% in the first quarter of 2020, with most of the impact felt in March as confinement measures were enforced in Europe, North America and elsewhere.
Global coal demand was hit the hardest, falling by almost 8% compared with the first quarter of 2019. Three reasons converged to explain this drop: China – a coal-based economy – was the country the hardest hit by COVID 19 in the first quarter; cheap gas and continued growth in renewables elsewhere challenged coal; and mild weather also capped coal use.
Oil demand was also hit strongly, down nearly 5% in the first quarter, mostly by curtailment in mobility and aviation, which account for nearly 60% of global oil demand. By the end of March, global road transport activity was almost 50% below the 2019 average and aviation 60% below.
The impact of the pandemic on gas demand was more moderate at around 2%, as gas-based economies were not strongly affected in the first quarter of 2020.
Renewables were the only source that posted a growth in demand, driven by larger installed capacity and priority dispatch.
Electricity demand has been significantly reduced as a result of lockdown measures, with knock-on effects on the power mix. Electricity demand has been depressed by 20% or more during periods of full lockdown in several countries, as upticks for residential demand are far outweighed by reductions in commercial and industrial operations. For weeks, the shape of demand resembled that of a prolonged Sunday. Demand reductions have lifted the share of renewables in the electricity supply, as their output is largely unaffected by demand. Demand fell for all other sources of electricity, including coal, gas and nuclear power.
Looking at the full year, we explore a scenario that quantifies the energy impacts of a widespread global recession caused by months-long restrictions on mobility and social and economic activity. Within this scenario, the recovery from the depths of the lockdown recession is only gradual and is accompanied by a substantial permanent loss in economic activity, despite macroeconomic policy efforts.
The result of such a scenario is that energy demand contracts by 6%, the largest in 70 years in percentage terms and the largest ever in absolute terms. The impact of COVID 19 on energy demand in 2020 would be more than 7 times larger than the impact of the 2008 financial crisis on global energy demand.
All fuels will be affected:
Oil demand could drop by 9%, or 9 mb/d on average across the year, returning oil consumption to 2012 levels.
Coal demand could decline by 8%, in large part because electricity demand will be nearly 5% lower over the course of the year. The recovery of coal demand for industry and electricity generation in China could offset larger declines elsewhere.
Natural Gas demand could fall much further across the full year than in the first quarter, with reduced demand in power and industry applications.
Nuclear power demand would also fall in response to lower electricity demand.
Renewables demand is expected to increase because of low operating costs and preferential access to many power systems. Recent growth in capacity, some new projects coming online in 2020, would also boost output.
In our estimate for 2020, global electricity demand falls by 5%, with 10% reductions in some regions. Low-carbon sources would far outstrip coal-fired generation globally, extending the lead established in 2019.
Global CO2 emissions are expected to decline by 8%, or almost 2.6 gigatons (Gt), to levels of 10 years ago. Such a year-on-year reduction would be the largest ever – 6 times larger than the previous record reduction of 0.4 Gt in 2009 (caused by the global financial crisis)and twice as large as the combined total of all previous reductions since the end of World War II. As after previous crises, however, the rebound in emissions may be larger than the decline, unless the wave of investment to restart the economy is dedicated to cleaner and more resilient energy infrastructure.
Full report can be found here: https://www.iea.org/reports/global-energy-review-2020
Regional Electricity Outlook
Energy markets are complex with many regional markets. The regional markets may differ from the overall continental energy outlook. Warmer-than-normal winter temperatures and social distancing measures due to COVID-19 are the major factors for the foreseeable future.
New England’s average real-time electricity lowest in market history.
Mild weather, low fuel prices, and a drop in consumer demand for electricity due to the COVID-19 pandemic contributed to real-time wholesale power prices in March 2020 being the lowest of any month since the launch of the current market structure in March 2003.
Average prices were down 54.4% in the Real-Time Energy Market when compared to the previous year, falling to $16.82 per megawatt-hour (MWh). Prices were down by 54.9% in the Day-Ahead Energy Market when compared to March 2019, averaging $17.18/MWh.
Power plant fuel: Fuel is typically one of the major input costs in producing electricity. Natural gas is the predominant fuel in New England, used to generate 49% of the power produced in 2019 by New England’s power plants, and natural gas-fired power plants usually set the price of wholesale electricity in the region. As a result, average wholesale electricity prices are closely linked to natural gas prices.
Electricity demand: Demand is driven primarily by weather as well as economic factors. As an example, energy usage during March declined 7.4% compared to March 2019. The average temperature during March was 41˚ Fahrenheit (F) in New England, five degrees higher than prior year. The average dewpoint, a measure of humidity, was 26˚F in March, up five degrees from March 2019. There were 738 heating degree days (HDD) during March, while the normal number of HDD in March is 882 in New England. In March 2019, there were 904 HDD. Social distancing measures due to COVID-19 are causing an additional 3-5% decline in consumer demand.
PJM reports operations through mild winter conditions of 2019-2020.
Last winter was remarkable for the lack of even brief periods of peak demand. Even mild winters are historically characterized by stints of freezing weather that spark brief, peak demand and correspondingly higher energy prices.
Measured against average winter cold temperatures from 1981 to 2010, the mild winter temperatures in the region served by PJM consistently ranged between 4 to 6 degrees higher – resulting in only one Cold Weather Alert, PJM reported at the April 16 Operating Committee meeting. However, last winter’s remarkably even and elevated temperatures produced instead the lowest peak demands in recent years. As a result, locational marginal pricing fell overall compared even to the similarly warm winters of recent years.
Last winter’s real-time locational marginal prices (LMPs) averaged $21.31, compared to $26.16 and $29.33, respectively, during the mild winters of 2015–2016 and 2016–2017. This coincided with natural gas prices nearly $1.50 lower than 2018–2019 at hubs throughout PJM’s 13-state footprint, from Chicago to Washington, D.C. In contrast, more typical, recent winter energy price peaks are characterized by LMPs in the mid $40s, apart from the record LMP average of $72.50 during the 2013–2014 Polar Vortex.
As milder temperatures consistently prevailed, PJM recorded no natural gas pipeline conditions impacting winter operations and only 12 Emergency Procedures, compared to 43 during the 2013–2014 Polar Vortex season.
PJM’s resource mix mirrored prevailing trends, marked by the rising incidence of natural gas and renewables, a decline in coal, and a slight decline in nuclear.
The New York Independent System Operator (NYISO) released an updated analysis of estimated COVID-19 demand impacts.
Demand reductions are largest in the morning, particularly in New York City (referred to in the analysis as Zone J).
- New York City hourly demand for the period of April 6-April 10 ranged from roughly 2% to 18% below typical levels.
- For weekdays, reductions in electric consumption in New York City averaged 18% below expected during the 8 a.m. hour.
- Meanwhile, NYC-wide reductions in electric consumption compared to typical demand levels ranged from roughly 1% during the 12 a.m. hour to just under 12% during the 7 a.m. hour.
“Electricity demand across New York State is clearly impacted by COVID-19-related closures,” said Rich Dewey, President and CEO of the NYISO. “Even when normalizing electric consumption data for weather, we have seen daily energy use down by nearly 9% during the second week of April.”
The NYISO also observed the morning peak arriving later in the day. This pattern is similar to what we would observe during a widespread snow day. NYISO forecasters noted that the reduction in electric demand from commercial customers is driving the reduction, while also observing an increase in residential energy use, especially during the midday.
The NYISO’s Operations and Demand Forecasting teams continue to monitor and assess changes in electricity demand level and consumption patterns to further refine daily and longer-term demand forecasts. This ongoing assessment includes evaluating demand patterns, updating economic forecasts, and engaging with local utilities.
Record electricity use expected this summer, ERCOT prepares for potentially tight conditions.
The Electric Reliability Council of Texas (ERCOT) expects record electric use this summer and grid conditions similar to summer 2019. ERCOT released its final Seasonal Assessment of Resource Adequacy for the upcoming spring season (March-May) and its preliminary assessment for the summer season (June-September).
“ERCOT has added new electric supply resources, and strong economic growth continues to push up demand in ERCOT,” said ERCOT President and CEO Bill Magness. “We expect grid operations to be very similar to last summer.”
As in 2019, the need to declare an energy emergency will depend on a combination of factors, including demand, wind output and the number of generators on outage on any given day. ERCOT and its market participants are taking steps to ensure system reliability can be maintained during tight conditions. Declaring an energy emergency allows the grid operator to take advantage of additional resources that are only available under these types of conditions. Additionally, the ERCOT wholesale market is designed to send appropriate price signals to encourage generators to be available when needed and for customers to lower their energy use.
Total resource capacity for the upcoming summer season is expected to be 82,417 megawatts (MW). The preliminary summer SARA report includes a 76,696 MW summer peak load forecast based on normal summer peak weather conditions from 2004-2018.
The final summer SARA report will be released later in May and will reflect the expected summer weather conditions. Based on the spring SARA report, ERCOT anticipates there will be sufficient generation to meet systemwide demand under a range of extreme system conditions. The spring SARA includes a 64,233 MW spring peak load forecast and is unchanged from the preliminary spring SARA.
Western Energy Imbalance Market gross benefits exceed $900 million.
Nine balancing authorities share $57.9 million in first-quarter benefits for 2020. The Western Energy Imbalance Market (EIM), the real-time energy market operated by the California Independent System Operator (ISO), reports generating $57.9 million in first-quarter gross benefits, putting the total at $919.69 million since 2014. The Western EIM uses advanced technology to find and deliver the lowest-cost energy to utilities throughout the West while enhancing reliability.
In addition to the economic results, the total greenhouse gas emission reduction since 2014 is 470,245 metric tons, the equivalent of removing 98,867 passenger cars off of the roads.
Because of the renewable energy transfers facilitated by the Western EIM, there was a reduced need for renewable curtailments during periods of oversupply. The avoided renewable energy curtailment for the quarter was 86,740 MWh, resulting in a total of 1,098,890 MWh since 2014. Over the next two years, the Western EIM will experience one of its largest expansion periods with the participation of Los Angeles Department of Water and Power, Northwestern Energy, Turlock Irrigation District, Public Service Company of New Mexico, and BANC Phase 2 in 2021; and Tucson Electric Power, Avista, Tacoma Power, and Bonneville Power Administration in 2022.
Xcel Energy, together with Black Hills Colorado Electric, Colorado Springs Utilities, and Platte River Power Authority, announced in December 2019 their intent to join the Western EIM. The group is working with the ISO to finalize the implementation agreement.