The cold weather crisis that shut down much of the Texas electrical grid in February had far wider repercussions than have been widely reported. This event resulted in significant financial impacts for both gas and electric utilities throughout much of the Midwest, Upper Midwest and even the Eastern Seaboard.

Frozen Equipment

When Winter Storm Uri swept into Texas, New Mexico and other parts of the Deep South in mid-February 2021, major wellfields throughout the Permian Basin in Texas quickly began experiencing freeze-offs at wellhead pumps, processing equipment and pressure regulating stations. Petroleum and gas produced in this basin contain relatively high volumes of water, and because temperatures in the Permian Basin seldom drop below freezing, very little heating equipment had been installed to protect against freeze-offs at wellheads or at power plants. This was a significant contributing factor. As February temperatures plunged, daily production dropped from an average of 25 billion cubic feet (Bcf) per day to approximately 11 Bcf.

Approximately 85% of the Permian Basin gas is shipped out of Texas, which meant a number of gas and electric utilities in regions far beyond Texas began facing critical shortages. Many electric utilities had to implement rolling curtailments while gas utilities and gas suppliers were forced to turn to the spot market for available gas. Prices quickly spiked by tenfold or more.

As a result, many utilities — both gas and electric — are facing enormous financial hits, ranging up to hundreds of millions of dollars in some cases. Many of these utilities have few options other than attempting cost recovery from customers.

Burns & McDonnell is among the gas customers seeing the impact. Our February bill for natural gas service at our Kansas City headquarters jumped to $93,193, compared with $6,669 charged for the February 2020 billing cycle. This was driven by a jump from $2.55/MMBtu to $622.79/MMBtu and then back down to $2.47/MMBtu, all in about a two-week span.

Three Options to Mitigate Future Risk

This unexpected event is creating momentum for a broad range of actions to create greater system resiliency on both the electric and gas sides of the utility industry. Here are three suggested steps for the gas side that merit consideration.

1. Supply Basin Diversification

With its abundant supply and low costs, it is no surprise that the Permian Basin has become the supply region of choice for many utilities. With highly productive wellfields connected with an excellent interstate pipeline system, many electric utilities are betting big on power generation facilities fueled by Permian Basin gas. Gas transmission and distribution companies also have grown accustomed to relying upon Permian Basin supply.

Natural gas will continue to be a good bet as an energy source for decades to come, but it becomes a risky bet when utilities are locked into supply from a single production region. This risk goes well beyond the heating season. With natural gas-fueled generation now providing approximately 40% of power capacity nationwide, think about what a major hurricane might do to Gulf Coast supply during the cooling season. Other supply basins also face certain risk factors.

That’s why gas transmission and distribution companies should begin exploring diversification of supply sources and negotiating contracts with pipelines interconnected with multiple production basins. For example, Rocky Mountain Shale gas and Marcellus Shale gas were widely available during the recent crisis.

Some utilities are evaluating adding supply from Rocky Mountain and Marcellus production basins, and others are evaluating the enormous reserves available from Canada.

2. Increase Liquefied Natural Gas (LNG) Capacity

Supply diversification is not the only resiliency strategy gas utilities should consider. Adding LNG capacity to the supply portfolio may also make sense for many utilities.

Many gas and electric utilities already utilize LNG for peak shaving at power plants and as a backup supply source on gas distribution systems. Expanding LNG capacity as an additional source of supply will require a broad-based plan to build true resiliency.

Peak shaving with LNG is a proven idea that has worked well for gas utilities for many years in response to peak demand. The gas is liquefied and stored when prices are low during the off-peak months of spring, summer and fall. Then when more gas is needed during peak demand periods, it’s available, reducing the need for spot market supply. This LNG-derived supply is added to the distribution system to meet customer demand at whatever the prevailing market price might be at the time. The use of LNG as a supplemental source of supply can be effective.

The concept could work equally well for electric utilities. Imagine being a power plant in Texas relying on natural gas pipeline supply to fire the plant. Those plants with LNG facilities on-site during the recent cold weather event could have utilized LNG to make up the loss of pipeline supply. The owner would have had power to sell simply by kicking on vaporization and staying online.

LNG options will need to fit the operational profile of each utility. Many may want to consider full-on LNG plants with more centralized liquefaction and vaporization capacity and satellite vaporization only at strategic points to support critical demand. For example, a large-capacity, centrally located LNG facility could be supplemented by a number of satellite vaporization sites located closer to load centers. The LNG would be trucked from the central facility to the satellites and peak shaved into the system during high-demand periods.

For large utilities serving major metros, large LNG liquefaction plants with on-site vaporization may make sense. However, small and midsized utilities might benefit from a dispersed network of LNG liquefaction and vaporization facilities.

3. Underground Storage

Investing in significant underground storage capacity is another important step to build system resiliency. This would be another economical means to diversify supply, either through contracting directly with storage operators or via partnerships to take advantage of underutilized storage.

Of course, this option would be limited mainly to those regions where utilities have proximity to underground storage in salt caverns or more traditional underground storage in depleted production fields or sandstone fields. The salt caverns are being developed after salt mining operations are completed. The traditional underground storage fields, especially in the Midwest, are what remain from depleted reservoirs or sandstone formations and are very good at containing gas. Utilities and other suppliers can pump gas into these facilities for storage when prices are low and pull it out when needed. Historically, these types of underground storage have proved to be feasible. Though these storage fields are generally not available in Texas, they can be found across a broad swath of the U.S. stretching from the Northwest, across the Midwest, into the South and along the Eastern seaboard.

For utilities without access to storage, maybe it’s time to ask: What will it cost? This can be done either in partnership or just a provision in a contract reserving capacity out of an underground storage field.

It’s Time to Act

There is no question this extreme cold weather event has exposed a resiliency problem for many utilities, both gas and electric. Significant investment in hardening infrastructure needs to occur on all sides of the house.

It seems highly likely that extreme weather events will become more common in the years ahead. Commonsense contingency planning can help utilities soften the blow to customers as these future events unfold.

 

LNG facilities already provide critical supply support for many utilities. Learn more about keeping these facilities current.

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Michael D. Falk is a construction project manager at Burns & McDonnell, specializing in operations management and regulatory compliance for interstate natural gas transmission and LNG and LP propane/air mix plants.