Energy Supplies Strained by AI in the U.S. Southeast

While the stock market is cooling off from its AI fervor, energy markets continue their march towards a world of increasing electricity demand brought on by new data centers. As we outlined in our previous Insight, the U.S. East Coast, more specifically the Southeast, will be a focal point of increasing energy demand. However, that region of the country has also lagged in renewables growth, leaving natural gas from the Gulf Coast as the primary means to meet most of the shortfall in supply. In this Energy Market Insight, we will examine the limits of natural gas in the region and what that means for the stability of the power grid.

This is the second in a series of Insights examining AI’s impact on U.S. natural gas and electricity markets and the subsequent effects on U.S. LNG exports and European supply. This piece will discuss the dynamics that will strain U.S. regional energy supplies. See our previous article outlining Europe’s reliance on U.S. natural gas supply and the challenges the U.S. will have in meeting domestic and international demand. Future articles will discuss key metrics to watch as the situation develops, the impacts of potential protectionist U.S. policy, and finally the path forward for European supply.

Transcontinental Pipeline (Transco) serves as the main conduit of natural gas supply into the region. It simultaneously brings supplies from the Gulf Coast northward and supplies from the Northeast southward.

However, a key aspect of the dynamic above is that the capacity moving into the region is essentially fixed due to public opposition to building new natural gas infrastructure, namely pipelines. In other words, the amount of additional gas that can be supplied to the region is limited. The following graphic shows the flows at the two arcs on the map, where gas from the Gulf Coast and Northeast enters the Southeast, using FactSet’s pipeline flow dataset.

Essentially, the flows at the northeast arc are at their maximum, and new supply from that direction cannot be achieved without new infrastructure (an unlikely solution in the near term). There is open capacity coming from the Gulf Coast that ranges from an abundance of 170–200 MMcm/d (6–7 Bcf/d) during spring and fall to 28–110 MMcm/d (1–4 Bcf/d) during the more demanding summers and winters. In fact, a low of just 0.5 Bcf/d was hit during Winter Storm Elliot in December 2022, which maxed out energy supplies and caused power outages in the region.

What does this mean going forward? Regional utilities in the states in question (Alabama, Georgia, Florida, North Carolina, and South Carolina) are calling for growing load growth, as outlined in our previous Insight. This translates to the electricity demand shown in the top half of the graphic below. The bottom half of the graphic takes this demand and shows it incrementally to the five-year average. In addition to the Base case (i.e., utility outlooks), the chart also includes a Low case (Base minus 5%) and a High case (Base plus 5%).

After calculating these scenarios, we reviewed the utilities’ plans to meet expected demand growth. These strategies range from importing additional coal-fired electricity to an aggressive buildout of additional natural gas and solar generation and storage sites. While these strategies all carry heavy risk (to be discussed in a future Insight), for the sake of this analysis, we assumed them all to be successful.

This now leaves us with the expected call on natural gas demand. The following graphic combines historical open capacity with the additional natural gas that would be required to meet demand. The box and whisker graphic below projects forward the distribution of the open capacity that we have seen over the last few years. The red areas at the bottom show the incremental gas that would be needed in the region, with dark red being the Base case and light red being the High case.

At first glance, the graphic above may paint an innocuous picture. There is ample capacity into the Southeast even compared to the High case for most of the year. However, during winters, when gas is needed for home-heating and solar generation is at its weakest, the situation becomes more serious. Certainly, a repeat of Winter Storm Elliot, which is causing the low end of available capacity in Decembers, would be more dire with the additional call on natural gas from data centers. However, even in other winter and summer months, the market tightens significantly, especially in the High case.

The High case above not only represents a scenario in which more power demand emerges but can also come to pass if the aggressive buildout of new power plants does not happen. For example, the region’s utilities are calling for a combined buildout of 21 GW of new solar facilities over the next five years, which would double the region’s current capacity. If the pace of solar buildout lags, however, more gas will need to be imported into the region, moving us closer to the High case and an even tighter market.

In the coming pieces of the series, we will continue to explore this dynamic and its knock-on effects to European natural gas supply and pricing. In the next Insight, we will examine the risks to utilities’ strategies to meet rising demand and highlight key metrics to watch as the situation develops. Then, given the likelihood the U.S. will be unable to keep the lights on, we will explore the explicit and implicit protectionist policies shared by both political parties that would affect the U.S.’ role as a player in global natural gas markets and a key energy partner to Europe.

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