Summer Energy Market 

and Reliability 

Assessment 

2020 

A Staff Report to the Commission 

May 21, 2020 

FEDERAL ENERGY REGULATORY COMMISSION 

Office of Energy Policy and Innovation 

Office of Electric Reliability

This report is a product of the staff of the Federal Energy Regulatory Commission. The opinions and preliminary 

views expressed in this paper represent the preliminary analysis of the Commission staff. This report does not 

necessarily reflect the views of the Commission. 
1 

Preface 

The 2020 Summer Energy Market and Reliability Assessment (Summer Assessment) is a joint report from the 

Office of Energy Policy and Innovation’s Division of Energy Market Assessments and the Office of Electric 

Reliability’s Division of Engineering and Logistics. This report uses preliminary North American Electric 

Reliability Corporation (NERC) Summer Assessment data. The final version of NERC Summer Assessment 

is scheduled to be released June 1, 2020. 

The Summer Assessment provides staff’s outlook for energy markets and electric reliability, focusing on June, 

July, and August 2020. The report is divided into two main sections—the first on major market events and 

the second on market fundamentals. The report first presents the key findings and expectations for the 

summer, beginning with impacts from the COVID-19 pandemic on the electric, natural gas, and oil markets. 

It then focuses on electric reserve margins, western energy and natural gas market conditions, and electric 

market fundamentals for the summer, such as a weather outlook and expected generation capacity additions 

and retirements. The report then analyzes natural gas market fundamentals, including prices, demand, imports 

and exports, production, and storage, before concluding with a summary of the main findings. 

Key Findings 

Staff bases the Summer Assessment on predictions about the energy markets. As with any market this year, 

COVID-19 has increased the uncertainty of those predictions. COVID-19 continues to impact both electric 

and natural gas markets. Social distancing and regional “stay-at-home” policies, which have closed many 

businesses, have reduced natural gas and electric demand. Demand for electricity has decreased by 

approximately 3 to 11 percent based on estimates for a given week in some ISOs/RTOs or relative to when 

social distancing rules took effect in others. The shape of hourly electric demand in many regions has changed 

and now reflects that many schools and businesses are closed, and people remain at home. 

COVID-19 has also delayed some maintenance on both natural gas and electric infrastructure; as a result, 

additional maintenance may be required later in the year. According to a report by the North American 

Electric Reliability Cooperation (NERC), deferred generation maintenance and other factors could potentially 

impact unit availability during the summer months.1 Nonetheless, ISOs/RTOs have not reported reliability 

concerns for the summer. Weekly U.S. gas demand remains slightly higher than that of previous years, with 

demand for LNG feedgas, electric generation, and residential and commercial increasing year-over-year. 

However, industrial demand is 1.7 billion cubic feet per day (Bcfd), or 8 percent, lower in April 2020 compared 

to April 2019. Oil markets are being significantly disrupted due to global market dynamics and COVID-19. 

West Texas Intermediate (WTI) Crude spot prices decreased 58 percent in March alone, causing financial and 

credit challenges, including oil company bankruptcies. WTI prices remained depressed in April, reaching the 

lowest price in history of negative $37.63/barrel (bbl) on April 20, as excess storage capacity became scarce. 

The negative close on April 20 was exacerbated by the expiration of the May contract on the following day. 

All NERC Planning Regions should have enough generation available to exceed their reserve margins, except 

for the Electric Reliability Council of Texas (ERCOT), whose anticipated reserves are expected to be below 

1 See NERC, “Special Report: Pandemic Preparedness and Operational Assessment: Spring 2020,” 

https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/NERC_Pandemic_Preparedness_and_Op_Assessment_Spring_2020.pdf 
2 

its reference reserve margin. ERCOT has identified an increased potential to call an emergency energy alert 

under various constrained circumstances.  In 2019, ERCOT was similarly below its reference reserve margin 

and experienced an all-time peak load and real-time Locational Marginal Prices (LMPs) (including price adders 

for reserve shortages) of $9,000/megawatt hour (MWh), and continued to operate reliably. 

In other market events, several natural gas pipeline segments in Southern California Gas Company’s 

(SoCalGas) service territory have returned to service after not being available since summer 2019. However, 

California has lower-than-average snowpack levels and a high risk of wildfires, according to weather and 

drought outlooks. Lower-than-average snowpack would cause lower hydropower generation in California 

than in the 2019 summer, which, all things being equal, could add to the need for imports and natural gasfired and other generation to meet summer loads in CAISO. Moreover, as part of their Public Safety Power 

Shutoff Plans, the utilities in the state may continue to selectively de-energize transmission and distribution 

lines to reduce the potential for wildfires, although these actions last year did not have significant effects on 

the wholesale electric or natural gas markets in California. 

Turning to market fundamentals, weather forecasts for June, July, and August 2020 suggest higher than normal 

temperatures through the western, southern, and eastern United States, with the upper Midwest expected to 

have normal temperatures. Early forecasts predict an above average 2020 Atlantic hurricane season, which 

lasts from June 1 through November 30, peaking in late summer or early fall. 

Nationally, the majority of generation capacity additions are forecast to come from natural gas, solar, and wind 

resources this summer. Nearly 1 GW of coal-fired generating capacity, largely in PJM and MISO, and about 

235 MW of natural gas capacity in PJM are scheduled to retire this summer. Electric generation’s demand for 

natural gas could average 38 Bcfd, a 0.6 percent decrease from summer 2019 but still an increase in electric 

generation’s overall share of domestic natural gas demand, reflecting a prolonged structural and economic 

trend. The decrease in demand for electricity caused by COVID-19 influenced the slight decrease in electric 

generation’s natural gas demand. 

Summer 2020 natural gas prices are expected to be lower across the U.S., with futures prices at Henry Hub 

averaging $1.91 per million British Thermal Units (MMBtu) for June through August, $0.44/MMBtu lower 

compared to 2019 settled futures prices.2 Natural gas production continues to be dominated by shale 

formations such as the Marcellus and Permian Basins, and is forecast to decrease to 88 Bcfd. The decrease 

marks a reversal in the trend of annual growth for domestic natural gas production over the last decade as 

COVID-19 is expected to impact associated natural gas production as well as natural gas demand. Large 

natural gas production and a larger than average natural gas storage balance are met by slightly smaller gains 

in natural gas demand. As of May 2020, natural gas demand is forecast to average 78 Bcfd for summer 2020, 

a decrease from an average of 80.6 Bcfd in 2019. The natural gas demand forecasts reflect projected increases 

of 2.7 Bcfd of domestic feedgas for LNG exports and 0.5 Bcfd in cross-border exports to Mexico and declines 

in the electric generation and industrial sectors. 

2 Henry Hub is a natural gas pricing point, located in Louisiana, which is generally used as the benchmark for U.S. 

natural gas prices. 
3 

Notable Energy Market Events 

Effects of COVID-19 on Energy Markets 

Most ISO/RTO regions are seeing lower demand for electricity due to social distancing and regional “stayat-home” policies from state or local governments, which has led to the closure of many businesses to reduce 

the spread of the virus. Regional operators note a decrease in demand around 3 to 11 percent, and in many 

regions, the morning peak hour is now occurring later in the morning. This change in load shape reflects that 

many schools and businesses are closed, and people remain at home. Wholesale electric prices are generally 

lower than last year at this time, due to the reduced loads, as well as mild weather conditions, and lower natural 

gas prices due to an abundance of supply. Each ISO/RTO has taken measures to ensure the safety of their 

personnel as well as the reliability of the bulk power system. For example, some regions, including NYISO 

and PJM, have sequestered control room operators, and PJM and SPP have set up additional backup control 

centers. 

Typically, spring is a time when maintenance activities occur because of reduced demand and mild weather, 

and to prepare for the upcoming summer season. While some generation and transmission maintenance is 

proceeding as scheduled, the scope of maintenance is being reduced and other maintenance is being deferred 

to reduce COVID-19-related risks to personnel. For example, as of May 6, approximately 21,000 MW of 

planned generation outages in MISO had been cancelled or rescheduled, representing roughly half of the 

generation capacity in MISO that would be on maintenance outage during a typical spring outage season. In 

SPP, scheduled generation maintenance reached almost 15,000 MW by late March but is expected to drop to 

10,000 MW by late May, which is 5,000 MW below 2018 and 2019 levels for the spring maintenance period. 

Transmission outages similarly declined below 2018 and 2019 levels starting in mid-March. PJM said some 

generators reported contractor crew shortages from travel restrictions and parts shortages from COVID-19 

related supply chain issues. However, no nuclear refueling outages have been deferred or canceled in PJM, 

ISO-New England, or NYISO for summer 2020. Furthermore, no ISO/RTO expects reliability problems to 

arise this summer due to the delayed or cancelled maintenance outages. 

U.S. natural gas markets are also being affected by the COVID-19 pandemic. S&P Global Platts estimates 

that industrial demand averaged 1.7 Bcfd, or 8 percent, lower in April 2020 compared to 2019. Despite the 

decrease in industrial demand, total estimated natural gas demand was 5.3 Bcfd, or 7 percent, higher than total 

demand in 2019 due to increases in natural gas demand for electric generation, LNG feedgas, and the 

residential and commercial sectors. Operationally, falling natural gas demand has pipelines in the Northeast 

calling operational flow orders (OFOs). Typically, OFOs during the spring would be due to low pressure. 

However, pipelines are experiencing very high levels of natural gas supply, causing high-pressure concerns in 

some of the pipelines. 

There is also significant downside risk to LNG feedgas demand for summer 2020, as global LNG markets 

have been affected by COVID-19 as well. Futures prices for natural gas in Europe and Asia suggest that U.S. 

LNG will be only marginally profitable or even unprofitable through summer 2020. The LNG market is 

currently oversupplied having added over 35 million tonnes per annum, or roughly 4.6 Bcfd, of new capacity 

over the past year. This combined with declining demand in Europe and Asia due to a mild winter, high 

storage levels, and the impact of COVID-19 have reduced the prices at the major trading hubs in both regions. 

For example, India’s shelter-in-place order is significantly reducing demand for natural gas in the country, 

which could impact U.S. LNG exports, given that the Indian utility GAIL (India) Limited holds a collective 

0.7 Bcfd in contracts for LNG from Sabine Pass Liquefaction, LLC and Dominion Energy Cove Point, Inc. 
4 

On April 20, the Japan-Korea Marker (JKM), a proxy for LNG cargoes into those markets, traded at 

$1.80/MMBtu, $0.12/MMBtu below the Henry Hub May futures contract. This marks the first time that the 

JKM spot price has ever traded at a discount to the comparable Henry Hub price. The Northwest Europe 

Marker also traded at $1.90/MMBtu, a 58 percent decrease from its value in April 2019. The profitability of 

shipping U.S. LNG to these regions has accordingly declined. This could lead to cargo cancellations and 

reduced utilization at the six operable liquefaction facilities in the U.S. However, U.S. LNG exports could 

benefit from renewed demand from China due to eased trade tensions. On April 20, China received its first 

U.S. LNG cargo since March 2019. 

More than natural gas markets, oil markets are being 

significantly disrupted going into summer 2020. 

WTI Crude spot prices decreased 56 percent over 

March alone. WTI Crude spot prices remained 

depressed in April, reaching an all-time low of 

negative $37.63 on April 20, marking the first time 

WTI prices ever traded in the negatives. The 

negative trading was largely due to markets nearing 

full storage capacity and was exacerbated by the May 

contract expiring the next day on April 21. This 

expiration effectively forced contract holders to 

either sell off or take physical delivery of crude 

barrels. In total, the EIA forecasts global petroleum 

and other liquids consumption to decrease 5.2 

million barrels per day, roughly 5 percent, in 2020 

compared to average 2019 consumption. The sharp 

decrease in WTI Crude prices cannot be solely 

attributed to COVID-19, however; OPEC and Russia in early March failed to reach an agreement on crude 

oil production targets that would have reduced global oil production levels. Despite the fact that OPEC and 

Russia reached agreement on April 12, markets have yet to fully balance. The combination of weakened 

demand related to COVID-19 and oversupply has led to a significant build in storage levels in both the U.S. 

and internationally. As of April 21, the EIA storage report puts inventories at 70 percent of capacity while 

U.S. storage operators are reporting nearly full capacity at Cushing, Oklahoma, and other major hubs. With 

few options to store oil, prices are expected to remain depressed throughout summer 2020. As of April 21, 

WTI NYMEX futures contracts for the months of June and July are priced at $11.57/bbl and $18.69/bbl, 

respectively. These low prices are likely to result in less oil production and reduce natural gas production in 

the Permian and North Dakota, where oil recovery is accompanied by associated gas shale plays. 

Capital spending has also declined. As of April 7, 12 of the world’s largest integrated public oil and gas 

companies have announced cuts to their 2020 capital spending programs, totaling $43.6 billion, a 23 percent 

decrease, in capital spending compared to their initial plans. Oil and gas exploration and production 

companies have also announced cuts of $17.82 billion in 2020 capital spending. Of the top 25 largest oil and 

gas companies, 21 saw their market capitalization decrease by more than 30 percent in 2020 Q1. The top 

three, Exxon Mobil Corp., Chevron Corp. and Royal Dutch Shell PLC, each saw at least a 40 percent drop in 

equity values. 

Figure 1 WTI Crude Spot Prices 

Source: EIA
5 

Regional Reserve Margins 

Data from the NERC Regional Entities and ISOs/RTOs indicate that planning reserve margins for all regions, 

except ERCOT, will be adequate this summer. The blue columns shown on Figure 2 display the anticipated 

reserve margins for the markets and regions, while the black bars indicate the reference reserve margins. Note 

that the data for forecasted reserve margins were prepared prior to the beginning of impacts from COVID19 and deviations from these forecasts are possible as the situation evolves. 

ERCOT anticipates that its reference reserve margin for 

this summer will be 12.6 percent,3 an increase from the 

10.67 percent initially expected, though that remains 

below NERC’s reference margin level of 13.75 percent. 

As ERCOT’s reserve margin in 2019 was 8.5 percent, 

this represents an increase relative to its reserve margin 

in summer 2019. While ERCOT faced some challenges 

last year, it maintained system reliability with no load 

curtailments even as it set several new peak loads, 

including its current standing all-time peak load of 

74,820 MW on August 12, 2019. 

However, while no load curtailments occurred, ERCOT 

did declare an Emergency Energy Alert (EEA) on 

several occasions in 2019. An EEA declaration occurs 

when available operating reserves fall below a certain 

threshold. Declaring an EEA allows operators to call on a variety of additional resources that are only available 

during scarcity conditions, defined by the operating reserves available, such as encouraging voluntary 

conservation by consumers, activating demand response measures, and increasing generation imports from 

neighboring regions.4 These resources are expected to mitigate capacity shortages, should they occur. 

Although ERCOT declared an EEA on August 13, 2019, expecting high load and low wind generation, it was 

still short on reserves, causing a real-time LMP (including price adders) of $9,000/MWh. Notwithstanding 

the reserve shortage, ERCOT concluded, “market outcomes supported reliability needs” during the summer.5 

According to the EIA, ERCOT is scheduled to have roughly 3 GW of additional net summer generating 

capacity come online during the summer 2020, as shown in Figure 7 below. 

Based on its projected reference reserve margin for this summer, ERCOT expects to rely on similar 

operational flexibility provided by declaring an EEA when necessary to ensure that its resources are sufficient 

3 See ERCOT, “ERCOT Summer 2020 Final Seasonal Assessment of Resource Adequacy,” May 13, 2020, 

http://www.ercot.com/content/wcm/lists/197378/SARA-FinalSummer2020.xlsx. 

4 ERCOT has a series of emergency procedures known as Energy Emergency Alerts (EEAs) that may be used when 

operating reserves drop below specified levels. These procedures are designed to protect the reliability of the electric system as a 

whole and prevent an uncontrolled system-wide outage. 

5 ERCOT, “Project No. 49852, Review of Summer 2019 ERCOT Market Performance,” ERCOT’s Review of Summer 

2019, October 11, 2019, http://www.ercot.com/content/wcm/lists/172485/Review_of_ERCOT_Summer_2019_-

_PUC_Workshop_-_FINAL_10-8-19.pdf. 

Figure 2 NERC 2020 Anticipated Reserve 

Margins 

Source: North American Electric Reliability Corp.
6 

to mitigate any capacity shortages. In studying scenarios for the upcoming summer, ERCOT identified the 

potential increased need to call an EEA under various constrained circumstances. 

Western Energy Markets 

California Natural Gas Pipelines 

Pipeline maintenance and storage issues will continue to 

affect natural gas supplies in southern California this 

summer. SoCalGas completed repairs to Line 235-2 on 

February 17, 2020, adding 170 MMcfd of additional 

capacity. Line 235-2 supplies natural gas to the Topock 

and Needles areas. However, there are maintenance 

projects scheduled for mid-June and mid-September 

that could affect pipeline capacity.6

 Other factors in 

place for the 2020 summer that could affect gas prices 

in the western U.S. include a modified California Public 

Utilities Commission (CPUC) Aliso Canyon Protocol to 

increase the amount of, and circumstances in which, 

withdrawals and injections can occur at the natural gas 

storage facility, specifically when a Stage 2 Low OFO is 

called. A Low OFO is called when pressure on the gas 

pipelines is low, perhaps because of low supply levels. 

In addition, the CPUC in July 2019 lowered SoCalGas’s 

imbalance penalties associated with OFOs during 

specific thresholds. Together, these changes allow 

SoCalGas and natural gas shippers additional flexibility 

to make withdrawals from the facility anytime a Stage 2 low or high OFO is issued and limits the penalty for 

violations to $5 per dekatherm.7 For summer 2020, Aliso Canyon inventories will be relied upon in a similar 

fashion to the 2019/2020 winter, allowing the system to balance in times of high strain and help mitigate price 

spike frequency and severity. 

6 See Sempra Envoy Electronic Bulletin Board, System Maintenance Outlooks, March 2, 2020. 

7 See California Public Utility Commission, Aliso Canyon Withdrawal Protocol, July 23, 2019,

https://www.cpuc.ca.gov/uploadedFiles/CPUCWebsite/Content/News_Room/NewsUpdates/2019/UpdatedWithdrawalProto

col_2019-07-23%20-%20v2.pdf. Pipelines and Local Distribution Companies (LDCs) issue an OFO to help maintain a balance 

of gas receipts onto its system with gas deliveries off of its system. For the period June 1 through September 30, the Low OFOs 

penalties for Stage 4 and Stage 5 OFOs are lowered from $2.50/Dth to $0.50/Dth, while the Emergency Flow Order penalty is 

$5/Dth. 

Source: ABB Velocity Suite, SoCalGas. Note:

an “X” represents the location of a recent

pipeline outage.

Figure 3 SoCal Gas Pipelines and Outage 

Locations
7 

Hydropower Season in the West 

Snowpack varies across the West this year. 

California’s snowpack is 54 percent below 

average as of April 1st—the lowest levels since 

2018. Typical snowpack levels are an indicator 

of how much hydro generation the state will have 

during spring and summer. Since smaller 

snowpacks melt faster than larger ones, the low 

snowpack also suggests that available hydro 

generation would peak earlier in the year and that 

less hydro generation would be available to help 

meet peak electric demand mid- to late-summer. 

Further north, normal level snowpack in 

Washington state and above normal levels in 

lower British Columbia indicate that the West 

may see normal hydropower generation overall 

when considered with California’s below normal 

levels. Washington and British Columbia basins 

feed the Columbia River, a major source of hydro 

generation in the West. British Columbia’s 

snowpack also provides hydro generation imported into California and the rest of the West. 

Lower than normal hydro generation tends to put upward pressure on natural gas prices, as natural gas 

generation typically replaces some of the hydro generation deficit. The effect may not be perceptible this year, 

due to other factors, including the restoration of SoCal Gas’s natural gas pipeline service discussed above, oil 

price changes and the related effects on natural gas output and prices, and the natural gas and electric demand 

consequences resulting from COVID-19. 

Power Shutoffs and Wildfire Risks 

From June through November 2019, Pacific Gas & Electric, Southern California Edison, and San Diego Gas 

and Electric instituted Public Safety Power Shutoffs that de-energized select parts of the transmission and 

distribution networks in northern, central and southern California. These Public Safety Power Shutoff events 

were responses to the risk of wildfires fueled by high winds in their service territories. Despite the disruption 

to retail customers, in the State of the Markets 2019 report, staff concluded that these events did not have 

significant impacts on the wholesale electric markets in CAISO or the Energy Imbalance Market of the 

Western Interconnection.8

8 See Federal Energy Regulatory Commission, “State of the Markets 2019,” March 19, 2020, https://www.ferc.gov/marketassessments/reports-analyses/st-mkt-ovr/2019-som.pdf. 

Source: Natural Resource Conservation

Service, US Department of Agriculture

Figure 4 Western Snowpack Levels through March
8 

The National Interagency Fire Center expects a 

significant risk of wildfires in northern California 

through this summer. Precipitation in February 2020 

was well below average in northern California, with 

some cities not experiencing any rainfall. The National 

Drought Monitor Center classifies most of northern 

California as in abnormally dry or moderate drought 

conditions as of April 14. By contrast, a winter storm 

brought significant rainfall to southern California, 

improving soil moisture and stream flow levels. 

Additionally, parts of the Sierra Nevada received over 

two feet of snow. As a result, southern California is 

not currently in a drought condition, unlike northern 

California. 

Market Fundamentals 

Weather Outlook 

For June, July and August 2020, the National Oceanic 

and Atmospheric Administration (NOAA) assesses a 

greater than 50 percent probability of above average 

temperatures throughout the western United States, 

parts of the southern United States, and much of the 

eastern United States. Elsewhere, the upper Midwest 

is expected to experience average temperatures during 

the same months. NOAA’s average temperature 

outlook for each area is based on temperatures 

recorded during the 1981 through 2010 period. In 

addition, NOAA’s early forecasts predict an above 

average 2020 Atlantic hurricane season with up to 16 

named storms, eight hurricanes and four major storms 

forecasted. The hurricane season runs from June 1 

Figure 5 Drought Conditions in the West as of 

April 14, 2020 

Source: National Drought Monitor Center,

University of Nebraska-Lincoln

Figure 6 Summer 2020 Temperature 

Source: National Oceanic and Atmospheric 

Administration
9 

through November 30, peaking in late summer or early fall. 

Electricity Markets 

Generation Capacity 

Preliminary data from the EIA indicates that over 

1.3 Gigawatts (GW) of generating capacity are 

scheduled to retire and approximately 5.6 GW of 

generating capacity are scheduled to enter 

commercial operations this summer. Although the 

EIA reports that the economic slowdown related to 

COVID-19 is likely to affect building of new 

generating capacity during the next few months, 

current projections indicate that adequate resources 

are available to meet peak demand this summer.9 A 

majority of the capacity additions will come from 

natural gas, solar, and wind resources. MISO is 

projected to add 1 GW of natural gas-fired capacity. 

ERCOT will add approximately 2.9 GW of 

renewable capacity, split between wind and solar, 

with solar capacity expected to be available on peak 

also increasing. Elsewhere, approximately 0.9 GW 

of coal-fired generation within the PJM footprint is expected to retire, although COVID-19 load reductions 

and price reductions may accelerate future retirements in PJM and other regions. 

9 See U.S. EIA, ”Short-Term Energy Outlook,” May 12, 2020, https://www.eia.gov/outlooks/steo/ 

Figure 7 Planned Generation Capacity Additions 

and Retirements for the 2020 Summer

Source: EIA
10 

Natural gas fired generation will continue to play a 

pivotal role in the summer of 2020, as new 

installations of natural gas generators and 

retirements of generators using other fuels continue 

to make it the largest source of electric generating 

capacity in each organized wholesale electric 

market. In NYISO, installed natural gas generators 

account for 55 percent of the total net summer 

capacity. Renewable sources of energy, such as 

wind and solar, also continue to make up an 

increasing portion of capacity across the United 

States. This summer, wind will make up 25 percent 

of the net summer capacity in SPP. Similarly, in 

CAISO solar energy will make up 22 percent of net 

summer capacity, accelerating ongoing trends 

affecting load peaks and shape. 

NERC Peak Load Forecast 

NERC forecasts net demand for electricity to 

increase by approximately 0.9 percent for summer 

2020 when compared to summer 2019, with growth 

in demand concentrated in ERCOT and WECC and 

reductions in load forecasts for PJM and MISO, 

while other regions remain similar to 2019 demand. 

However, demand forecasts remain in flux due to 

uncertainty related to the impacts of COVID-19, 

which could result in lower actual demand than 

current forecasts.10 NERC also forecasts total 

generating capacity to increase by approximately 0.2 

percent from summer 2019. The increasing demand 

marks a shift from the 2019 net demand forecast, 

which predicted an overall decrease in demand. The 

expected growth in generation is also lower than 

summer 2019, falling from 1.1 to 0.2 percent. These 

projections were calculated with preliminary data 

from ISOs/RTOs and NERC Regions for NERC’s upcoming 2020 Summer Reliability Assessment. 

Similarly, generator capacity additions scheduled to come online for the summer could also change or be 

subject to delays, as noted above. 

10 See U.S. EIA, “Short-Term Energy Outlook,” May 12, 2020, https://www.eia.gov/outlooks/steo/

Figure 8 Installed Generation Capacity for the 

2020 Summer

Source: EIA

Figure 9 NERC 2020 Demand and Generation 

Source: North American Electric Reliability Corp.
11 

Natural Gas Markets 

Natural Gas Prices 

Natural gas futures prices for summer 2020 are 

lower at nearly every major trading hub across the 

U.S. compared to the final settled futures prices of 

summer 2019. As of May 12, 2020, the Henry 

Hub futures contract, generally the largest 

component of summer futures prices, is 19 

percent lower than the summer 2019 settled price, 

falling $0.44/MMBtu to $1.91/MMBtu. The 

largest nominal year-over-year futures price 

decrease is in southern California, where futures 

prices fell by $0.98/MMBtu, or 28 percent lower, 

trading at $2.55/MMBtu for summer 2020. . 

Futures prices at other major demand hubs of 

New York City, Boston, and Chicago are all at 

least 16 percent lower than in summer 2019, as well. On the supply side, prices decreased the most at the 

Appalachian hub Dominion South, decreasing by $0.65/MMBtu, or 33 percent. Despite the lower expected 

prices for summer 2020, significant uncertainty exists for summer 2020 natural gas prices due to COVID-19 

and its effects on energy markets. Market shocks associated with COVID-19 have led to lower-than-normal 

demand while short-term production levels remain high, potentially placing downward pressure on natural 

gas prices. However, after the short-term price decrease, prices may face upward pressure should oil prices 

remain depressed and producers are forced to decrease oil and associated gas output. 

The Permian Basin’s Waha trading hub is the only major trading hub to see a significant increase in year-overyear summer futures prices. Prices at the West Texas hub increased by $1.40/MMBtu to $1.63/MMBtu, but 

the region contines to face capacity constraints. Last year, natural gas futures prices settled at $0.23/MMBtu 

due to large increases in natural gas production associated with rising crude oil production, which often 

exceeded or constrained regional pipeline capacity. Permian prices have strengthened since last summer with 

the addition of new pipeline capacity in late 2019 that relieved some of the infrastructure bottleneck. COVID19 has provided further upward price pressure as market participants expect associated gas production in the 

basin to decrease due to falling oil prices. Still, futures prices at the Waha hub remain low compared to many 

hubs across the U.S. 

Fig. 10 U.S. Natural Gas Summer Futures 

Source: InterContinental 

Exchange Inc.
12 

Natural Gas Demand 

As of May, forecasted demand for natural gas in 

summer 2020 is expected to decrease by 3 percent 

over summer 2019 to 78 Bcfd. This contrasts with 

summer growth reported in 2018 and 2019 of 8.5 

percent and 11 percent, respectively. Demand 

growth this year is only forecast in the export and 

residential and commercial sectors. Natural gas 

consumption by the electric power sector for the 

generation of electricity, or power burn, is forecasted 

to average 38 Bcfd, down 1.6 percent from summer 

2019, after averaging 5 percent growth annually since 

2015. While the EIA’s forecast expects a decrease in 

power burn during the peak electric demand months 

of July and August, low natural gas prices are 

expected to give natural gas generators a slightly 

larger than normal market share during the month of 

June. However, EIA forecasts natural gas power burn to grow by only 1.5 percent over June 2019. 

Through summer 2020, the share of U.S. electric 

generation provided by natural gas is expected to 

increase slightly, from 41 percent in 2019 to 42 

percent in 2020. In 2015, natural gas generation 

represented 34 percent of total U.S. generation. 

Regionally, the largest forecast increase is in PJM, 

while CAISO, ERCOT, New England, and the U.S. 

West see small declines in natural gas’ share of 

generation against the five-year average. New 

England, NYISO, the Southeast, and ERCOT are 

most dependent on natural gas, each deriving 

approximately half of its electricity from the fuel. If 

broken out of the larger Southeast region, Florida 

has the largest share of natural gas generation at 79 

percent. 

Natural Gas Imports and Exports 

Exports of natural gas from the U.S. are forecast to reach new highs this summer, in part due to 5.3 Bcfd of 

aggregate capacity additions at four LNG liquefaction terminals: Corpus Christi Liquefaction, LLC, Cameron 

LNG, LLC, Elba Liquefaction Company, L.L.C., and Freeport LNG Development LP. In addition, pipelinetransported exports to Mexico are also forecast to increase due to new pipeline connections. The Mexican 

natural gas pipeline transportation system has at least 2.6 Bcfd of new capacity expected to be in-service in 

2020, including the 1.2 Bcfd La Laguna-Aguascalientes pipeline in central Mexico and the 0.5 Bcfd 

Samalayuca-Sasabe pipeline in the west. Although near completion, these projects may face delays in 

commerical operation related to COVID-19. Pipeline exports to Mexico and LNG exports collectively are 

Figure 11 Natural Gas Summer Power Burn

Source: EIA

Figure 12 Summer Natural Gas Share of 

Generation

Source: EIA
13 

forecast to average 14 Bcfd in June, July, and August 2020, up from 10.9 Bcfd last summer.11 S&P Global 

Platts estimates a 0.5 Bcfd year-over-year increase in natural gas pipeline exports this summer. Natural gas 

exports could experience the largest sequential gain on record, though several conditions could keep exports 

from reaching those levels. One of the biggest potential impediments to growth in exports, particularly for 

LNG, is the weakening economics of sending U.S. natural gas to overseas markets that are increasingly seeing 

lower prices due to weaker demand and growing production from Australia and other global producers. 

Building on the mild winter, COVID-19-related demand reductions in major LNG-consuming markets has 

kept the global market for LNG weak in early 2020. However, U.S. LNG exports could benefit from renewed 

demand from China due to eased trade tensions. In April, China received its first U.S. LNG cargo since 

March 2019. 

Feedgas – dry natural gas used as raw material for 

LNG – into the six operational terminals in the U.S. 

averaged 5.6 Bcfd during the summer of 2019 and 

S&P Global Platts forecasts an average LNG 

export terminal demand of 8.2 Bcfd this summer, 

with a high of 9.1 Bcfd in July. The average 

summer consumption of natural gas would equate 

to a 2.7 Bcfd increase year-over-year, the largest 

sequential gain since LNG exports from the 

continental U.S. started in 2016. The forecast 

reflects large additions of liquefaction capacity 

between 2019 and mid-2020 and a 85 percent 

average utilization rate of LNG facilities. Between 

the start of summer 2019 and the end of summer 

2020, 5.2 Bcfd of LNG liquefaction capacity is 

expected to be added at the Cameron, Corpus 

Christi, Elba Island, and Freeport facilities, 

collectively increasing nameplate LNG export capacity from 5.0 Bcfd to an expected 10.2 Bcfd, with the 

majority of the capacity additions occuring before the start of summer. 

There are several factors which could reduce LNG feedgas this summer. Planned and unplanned maintenance 

outages of the LNG terminals or on connected transmission pipelines could take place over an extended 

period of time and could temporarily reduce natural gas demand. For example, in previous years, Cove Point 

and Sabine Pass have conducted maintenance during the summer, lasting as much as three weeks. The 2020 

forecast accounts for these seasonal maintenance events, reflecting a lower utilization rate similar to those in 

2017, 2018, and 2019. Similarly for pipeline exports to Mexico, cross-border flows are forecast to increase by 

about 0.5 Bcfd from summer 2019, which matches the increase in 2019 for natural gas trade between the two 

countries. Pipeline exports south to Mexico are forecast to average 5.8 Bcfd in June, July, and August, up 

from 5.3 Bcfd in summer 2019. Pipeline capacity additions, both on the U.S. side and in Mexico, are driving 

the expected increase. The 2.6 Bcfd Sur de Texas – Tuxpan pipeline, which links south Texas to northern 

Mexico, began service in September 2019. Several additional pipelines went in-service in Mexico, furthering 

the integration of its national pipeline grid, which has facilitated greater imports of U.S. natural gas. 

11 These projections come from S&P Global Platts, US Gas Short-Term Forecast, released April 24, 2020. 

Figure 13 U.S. LNG Exports and Feedgas 

Source: S&P Global Platts
14 

Imports of natural gas play a smaller role in the U.S. natural gas supply mix, particularly in the summer. 

Canadian imports into U.S. markets in the Northeast, Midwest, and West Coast are forecast to average 4.7 

Bcfd, up 0.4 Bcfd from summer 2019. The increase is mainly due to 2019’s historically low level of Canadian 

pipeline imports. However, pipeline imports from Canada are vital to supply markets in the U.S. West Coast 

and in the Northeast, and there is a high-level of integration of pipeline and storage facilities in the Midwest. 

LNG imports from Canada are a lesser part of the supply mix and represent just 0.1 Bcfd in the summer 2020 

supply forecast. The projected LNG imports are effectively the same as in 2019. 

Natural Gas Production 

Natural gas production in the United States may 

end its recent growth trend, as it is forecast to 

average just over 88 Bcfd during summer 2020, a 

decrease of 3.7 percent compared to the previous 

year. Summer production had grown by over 10 

percent in each of the past two years. Shale 

formations, such as the Marcellus and Permian 

basins, represent the largest shares of natural gas 

production with 24 percent and 12 percent, 

respectively, of domestic production at the end of 

2019. The COVID-19 pandemic has added 

downward pressure to the summer 2020 natural gas 

production forecast due to lower expected demand 

for natural gas. Added downward pressure also 

results from recent low oil prices affecting 

expectations of oil-associated natural gas 

production. The Marcellus basin is expected to 

remain the largest production basin in the U.S. despite slower production growth in the region. The Permian 

Basin has been a strong source of increased natural gas production, adding 2.7 Bcfd in 2019. However, natural 

gas is not the primary target of drillers in the region as most are seeking to find crude oil. While most oil wells 

produce at least some associated natural gas, such output in the Permian is higher than in many other oil fields. 

With significantly lower oil prices, less drilling is expected in the basin, which could lead to less natural gas 

production. 

Natural Gas Storage 

Natural gas storage inventory projections are well positioned this year, beginning the injection season at the 

fourth highest inventory level in the past 10 years of 2.02 trillion cubic feet (Tcf). The current natural gas 

storage inventory is a result of a relatively low withdrawal season, running from November 1, 2019, to March 

31, 2020, due to mild weather conditions. Storage inventories began the 2019/2020 withdrawal season at 3.73 

Tcf, 16 percent higher than the start of the 2018/2019 withdrawal season but nearly identical to the five-year 

average for the first week of November. Warm weather during the winter led to the second lowest level of 

Figure 14 Summer Natural Gas Production and 

Demand

Source: EIA
15 

withdrawals for a season in the past 10 years. 

However, ending the withdrawal season with 

relatively high inventories is balanced with tempered 

expectations for this summer as additional natural 

gas fired generation demand could increase 

competition for storage injections this year. 

Furthermore, the amount of natural gas injected 

into storage each summer is highly correlated with 

the relative cost of natural gas relative to the 

beginning storage inventories of each season. The 

second largest injection season in the past ten years 

occurred in 2019, when natural gas prices at the 

Henry Hub averaged $2.39/MMBtu and withdrawal 

season levels ended at 1.16 Tcf (the second lowest 

figure in the past ten years). The 2020 injection 

season is forecast to add 1.82 Tcf this summer, 

which would lead to storage levels of nearly 3.84 

Tcf, more the five-year average at the start of the 

2020/2021 withdrawal season. However, summer 2020 storage levels could exceed expectations due to 

decreased natural gas demand caused by COVID-19. 

Conclusion 

In summary, COVID-19 has lowered demand for electricity by approximately 3 to 11 percent because of 

social distancing and “stay-at-home” policies, which also closed many businesses. Moreover, COVID-19 has 

delayed some maintenance on natural gas and electric infrastructure. Deferred generation maintenance and 

other factors could potentially impact unit availability during the summer months. 

All NERC Planning Regions are expected to have enough generation available to exceed their reserve margins, 

except for ERCOT. ERCOT anticipates extreme weather, low wind output, and higher-than-normal 

generation outages may result in the need to declare EEAs. Several natural gas pipelines in California that 

were out of service in 2019 are expected to be in service at or near full capacity this summer, possibly alleviating 

natural gas-related constraints in the state during the peak load season. However, California is forecast to 

have below-average hydropower generation this summer due to lower than average snowpack levels. In 

addition, the risk of wildfires and Public Safety Power Shutoffs in California remains. 

Regarding market fundamentals, weather forecasts for June, July, and August 2020 suggest higher than normal 

temperatures through the western, southern, and eastern United States, with the upper Midwest expected to 

have normal temperatures. Several solar, wind, and natural gas resources are expected to come online by the 

summer, while certain coal resources are scheduled to retire. Natural gas is expected to continue to play a 

large role in the wholesale electric markets during the summer. Natural gas prices are expected to decrease at 

most hubs, as production and demand decrease from last summer’s levels. New LNG liquefaction capacity 

will continue to facilitate the U.S.’s position as a net exporter of natural gas. 

Figure 15 U.S. Seasonal Change in Lower 48 

Natural Gas Inventories

Source: EIA