Winter Storm Causes Historic Power Outages

As the power industry turns the page on a year marked by record warm and cold temperatures, it entered 2023 with concerns about the frequency of extreme weather events. To deal with this threat the industry focused on opportunities to enhance grid reliability.

Winter Storm Elliott moved across North America in December 2022, bringing blizzards, high winds and extremely cold temperatures to a large portion of the United States. The harsh weather conditions led to unprecedented load curtailments, with the majority of customers experiencing power outages in North Carolina, Tennessee, Maine and Pennsylvania.

One factor contributing to these outages was the inability to accurately forecast electricity demand in some organized energy markets. PJM stated that actual load came in over 10 percent above predictions for the Christmas Eve cold snap. Similarly, the Tennessee Valley Authority (TVA) stated that December 23 marked “the first time in TVA’s 90-year history that we’ve had to direct targeted load curtailments due to extreme power demand.”

“While demand turned higher than planned, outages at fossil fuel power plants left grid operators with a number of units unavailable, driven in part by fuel supply issues—mainly natural gas,” CFC Senior Energy Industry Analyst Roman Siegert said. “In general, those gas-fired generators that do not secure firm supply contracts in advance have been more exposed to extreme weather conditions that fall on a holiday weekend.”

Historically high demand exacerbated the natural gas shortage. From December 21 through December 26, residential and commercial sector natural gas consumption was 55 percent higher than the five-year (2017–2021) average, according to the U.S. Energy Information Administration (EIA). The electric power sector alone consumed 45 percent more natural gas during those days, compared with the five-year average. Higher-than-average natural gas demand during the December storm was met by increasing both withdrawals from storage and pipeline imports from Canada.

In addition to plant operators’ difficulties to procure enough natural gas on short notice to keep their generators running, dry natural gas production in the Lower 48 dropped to a low of 82.5 billion cubic feet (Bcf) on December 24, a 16 percent decrease from December 21, according to data from S&P Global Commodity Insights. Mechanical failures due to extremely low temperatures was the main cause of the production shortfalls. The last time U.S. natural gas production declined by this magnitude was during Winter Storm Uri in February 2021.

“The combination of higher-than-planned demand and reduced natural gas production highlights the threat posed by the high reliance on natural gas during extreme weather conditions,” Siegert explained.

Potential Solutions To Mitigate Power Generation Risks

In response to Winter Storm Uri, the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corp (NERC) asked the North American Energy Standards Board (NAESB), to work with the U.S. electric utility and natural gas industries to identify solutions aimed to increase reliability of the U.S. bulk power system. NAESB has been meeting with industry stakeholders on a monthly basis since August 2022.

On January 25, industry experts speaking at a summit in Washington, D.C., hosted by NERC, highlighted the disconnect between real-time wholesale electricity markets scheduling and natural gas deliveries that rely on pipeline nomination cycles made in advance during the workweek.

“Proposed solutions include investments to expand pipeline capacity, increasing the visibility of pipelines’ operational status to all stakeholders, making advanced exchange agreements for gas-fired generators and reviewing gas nomination cycles,” Siegert said.

Increased Natural Gas Production and Lower Prices Are Expected This Year

In its January “Short-Term Energy Outlook” (STEO), EIA expects natural gas production in both the Permian Basin and Haynesville Shale regions to grow with the completion of pipeline infrastructure expansions in 2023 and 2024.

The STEO anticipates Henry Hub natural gas spot price averages slightly less than $5 per million British thermal units (MMBtu) in 2023, down nearly 25 percent from last year. The decrease is a result of domestic consumption slowing and liquefied natural gas (LNG) exports remaining relatively flat.

“A potentially oversupplied natural gas market should partly drive wholesale electricity price declines this year,” Siegert said.

Incentives Will Drive Declines in the Costs of New Solar, Wind and Storage Resources

Apart from these mitigation measures, the 2021 Infrastructure Investment and Jobs Act provides nearly $15 billion in federal funding for grid improvements, including energy storage. The 2022 Inflation Reduction Act (IRA) also provides more incentives to energy storage projects than ever before, which will help offset resource intermittency. IRA also includes new tax credits for clean hydrogen, which could become a long-duration storage solution in the future.

“Recently defined incentives make these resources more likely to grow where additional capacity is needed and also more competitive in fossil generation regions,” Siegert said. “In other regions with high renewables penetration, new green generation is expected to become more cost effective.”

Although penetration of renewable resources and energy storage will progressively gain more relevance over the next years, the reliability of the power grid will continue to be highly sensitive to natural gas markets for the foreseeable future, especially during extreme weather events.

“In the current environment, grid operators are looking closely at natural gas dynamics while trying to cope with market volatility to keep the lights on when demand peaks,” Siegert concluded.