FERC Federal Energy Regulatory Commission : October 15, 2020 Winter Energy Market Assessment Report | Presentation (As Presented)

Winter Energy Market and

Reliability Assessment

2020/2021

A Staff Report to the Commission

October 15, 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.

Preface

The 2020/2021 Winter Energy Market and Reliability Assessment (Winter 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) Winter Assessment data. The final version of the NERC Winter Assessment is scheduled to be released November 2, 2020.

The Winter Assessment provides staff's outlook for energy markets and electric reliability, focusing on December 2020, January 2021, and February 2021. The report is divided into four main sections-the first is key findings, the second is notable market events, the third is a spotlight overview of natural gas and electric issues heading into the winter for markets in the Northeast and California, and the fourth is on energy market fundamentals. We conclude with a summary of our main findings.

Key Findings

In this Winter Assessment, staff makes several key findings about the outlook for the natural gas, electric and crude oil markets and assesses the trends in those markets. The key findings for these markets are based on analysis of forward-looking data for the winter. Across the U.S. this winter, the COVID-19 pandemic is expected to continue to impact all of these markets. All NERC Planning Regions expect to have enough generation available to meet their planned reserve margins through the winter. However, fuel availability, particularly natural gas and fuel oil, can affect electric operations and should be monitored. Finally, in the Northeast, electric and natural gas supplies are expected to be constrained, while California is expected to see over-supply conditions in the electric market and a potentially constrained natural gas market this winter.

Trends in natural gas and electric fundamentals heading into the winter are driven - as in all years - by weather and - unique to this year - by the impact of COVID-19. As to weather, the National Oceanic and Atmospheric Administration (NOAA) forecasts a mild winter for most of the country, with a greater probability of above normal temperatures for most of the continental U.S, a greater probability of below normal temperatures in the upper Northwest and an equal chance of above or below normal temperatures for the Upper Midwest, the Rockies and a portion of the Northwest. Natural gas is expected to provide roughly 46% of the net winter electric generation capacity in the continental U.S., followed by coal (19%), wind (10%), and nuclear (9%). Although gas-fired capacity continues to grow in most markets, the share of U.S. electric generation fueled by natural gas in the winter is expected to decrease from 38% in 2019/2020 to 34% in 2020/2021 owing to increased competitiveness of coal resources from expected higher natural gas prices this winter. Natural gas futures prices for the winter are higher at major trading hubs across the U.S. compared to the final settled futures prices of winter 2019/2020. Largely due to COVID-19 impacts and an expected warm winter, demand for natural gas this winter is forecasted to decrease by 3% from last winter. U.S. Liquified Natural Gas (LNG) export volumes are expected to recover this winter from the significant decrease in Summer 2020, which was due to lower international LNG prices and lower demand related to COVID-19. Natural gas storage inventories are expected to begin the winter withdrawal season at 3.98 Trillion cubic feet (Tcf), the third highest inventory level in the past 10 years. As a result, storage inventories should be sufficient to meet demand this winter. Storage inventories are expected to end the withdrawal season at 1.34 Tcf, the third lowest level in the past 10 years.

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Notable Energy Market Events

Effects of COVID-19 on Energy Markets

The COVID-19 pandemic disrupted natural gas markets beginning early this spring. Demand for natural gas from March through June of 2020 averaged 75 billion cubic feet per day (Bcfd). This amount is

1.5 Bcfd lower compared to the same time period in 2019, a roughly 2% decrease, reversing the demand growth trend of the last two years over the same period. Due to decreased international LNG demand and prices in Spring 2020 through Summer 2020, LNG exports declined significantly, with exports averaging 27% less from June through August 2020 compared to the same period in 2019. U.S. LNG exports are expected to rebound this fall moving into Winter 2020/2021 as international demand increases due to colder weather. The Energy Information Administration's (EIA) expects LNG exports to average 9.4 Bcfd between December 2020 and February 2021, 22% higher than the average between December 2019 and February 2020 as new export capacity has come online. However, continued global shutdowns due to the COVID-19 pandemic present downside risk to U.S. LNG exports.

June natural gas production decreased 2.8 Bcfd, or 3%, year-over-year as lower prices, both for natural gas and oil, failed to incent new production. According to the EIA's Short-Term Energy Outlook (STEO), through the end of 2021, natural gas prices are expected to increase from Summer 2020 levels, with the sharpest increases occurring during Winter 2020/2021. Overall, the EIA expects that total U.S. consumption of natural gas will average 82.7 Bcfd in 2020, a decrease of 3% from 2019. The overall outlook for natural gas demand recovery will depend on how the pandemic and subsequent recession continue to develop.

Natural gas prices have also decreased since the beginning of COVID-19 this spring. Generally, the Platts Gas Daily Henry Hub index averaged $1.66/MMBtu April through July 2020, $0.80/MMBtu lower compared to the same period in 2019. However, Winter 2020/2021 futures prices indicate that markets may tighten this winter and prices may increase above Winter 2019/2020 levels.

The crude oil industry was also heavily impacted by the COVID-19 pandemic. In response to lower prices, operating oil and gas rigs in the U.S. decreased 66%, from 790 in mid-March to 242 in mid-August. Likewise, crude oil production decreased and remained low through Summer 2020, averaging 10.4 million barrels (MMbbl)/day in June 2020 compared to 12.1 MMbbl/day in June 2019. Looking forward, the decreased production is expected to rebalance the market but prices are expected to remain lower than 2019 oil prices. The EIA forecasts the West Texas Intermediate (WTI) crude oil to average $41.33/bbl from December 2020 through February 2021 compared to $55.98/bbl from

Figure 1 WTI Crude Oil Price

Source: EIA and NYMEX

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December 2019 through February 2020. Futures prices, as of September 15, indicate oil prices could be lower than EIA forecasts.

COVID-19 also adversely affected the financial health of many energy companies due to lower demand and commodity prices. As of mid-September, 53 energy companies, as defined by S&P Global, filed for bankruptcy in 2020, the third largest sector behind consumer discretionary and industrials according to S&P Global data.1 Oil and gas producers and oilfield services were most directly impacted as a number of notable companies have filed for Chapter 11 bankruptcy since April.

In the electricity sector, ISOs/RTOs reported a drop in electric load of around 3 to 12% from April to June. COVID-19 effects on electricity demand were most pronounced from mid-March through May. The onset of summer and the gradual reopening of the national economy has lessened effects due to COVID-19. In MISO for instance, the load deviation from normal load conditions peaked the final week of April, at 11.5% or 6.8 GW below normal. In May and June, the load deviation became smaller as some retail and manufacturing load returned. By August, load deviation was only 1.3% lower than normal and MISO no longer needed to adjust for COVID-19 impacts in its forecast model. Accurate forecasts are essential in running the markets and dispatching resources efficiently. Overall, according to the EIA, 2020 electric demand in the U.S. is expected to decline by 3.6% compared to 2019, with the largest decline in the commercial sector.

In addition to load reductions, COVID-19 has impacted the shape of the electric demand curve. The morning peak has occurred later in the day and energy usage has moved higher during the afternoon. Prior to the pandemic, weekday loads had early morning peaks and early evening peaks-distinct from weekend loads, which have later morning peaks and late afternoon peaks. With the pandemic, however, weekday loads have been more comparable in shape to weekend loads. For example, analysis by CAISO showed that between March 23 and July 26, the weekday morning peak load was 1.3 GW, or 5%, lower than normal. On weekends these impacts were muted, with weekend morning load roughly 2% lower by comparison. Similarly, evening loads were about 3% lower on the weekdays but only 1% lower on the weekends. Overall load was about 2% lower during the weekdays, showing that the load reductions were not uniform, but they altered the total shape for CAISO. Although RTO/ISO loads have returned close to normal levels, the electric demand curve has not returned to its pre-COVID-19 shape.

Effects of COVID-19 on Maintenance and on Generation and Transmission Availability

Utilities have adopted procedures to meet COVID-19 related safety requirements and recommendations. For example, utilities have adjusted maintenance schedules to provide additional time to procure Personal Protective Equipment (PPE) supplies or for local virus transmission levels to drop.

1 S&P Global's bankruptcy coverage is limited to companies with public debt where either assets or liabilities at the time of bankruptcy filing are greater than or equal to $2 million, or private companies where either assets or liabilities at the time of the bankruptcy filing are greater than or equal to $10 million.

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