The natural gas landscape has a bullish tone throughout January as Mother Nature delivered cold temperatures across several key demand regions, including the South Central region. Over the past two weeks, temperatures have waned a bit and the wind volatility has picked up within SPP and ERCOT. The heating demand component is one thing while the hourly power demand profile is another as the combination of temperature swings with the renewable megawatt volatility shifts the net load values to which then impacts how we look at power burns in the region.
Figure 1 | South Central Regional Net Load with Power Burns
The graph in Figure 1 displays both the net load hourly profiles starting at the end of January 2025 and forecasting through February 11th, 2025. The South Central power region takes on three ISO sub-regions that include MISO-South, SPP-South and all ERCOT while the natural gas boundary covers a similar footprint. The hourly net power load profile for each is on display in the top horizontal pane while the daily natural gas power burns are on display in the bottom one. The vertical panes have the hourly values on the x-axis and are broken up by day. Over the course of the past 7-10 days, there have been two daily buckets the analysis has fallen into, they are:
- Net Load between 47-50 GWa
- Net Load between 61-65 GWa
The first one displays power burns sitting around the 8.1-8.2 BCF level while the second one carries a value closer to 8.8 BCF. If you look back to January 29th, we have an average net load that is substantially higher (79.6 GWa) given the colder temperatures were in play and the renewable generation output was on the lower end of the range. Such a day pushed the power burns up to 9.9 BCF, which was quite impressive. A couple of days later (January 31st), the grid presented a 9.5 BCF power burn, despite a lower net load average. Looking at the hourly profile on that day, the thing that sticks out the most is the steep ramping values between the midday block and the evening ramp. It is the highest (43.5 GW of ramp) in the window of days and the majority of resided in ERCOT (30 GW) and SPP’s South (10 GW). A steep ramp like this needs to rely on flexible resources such as peaking natural gas plants or battery technology. Since SPP has barely any battery capacity installed and ERCOT typically sees between 2-3 GW dispatched during the evening ramp hours, there is not enough ‘new’ technology thus the grid operations needed to rely on gas-fired peakers to balance. The other six days between January 30th and February 5th fell in either of the two buckets mentioned earlier. February 6th looks to be an outlier of sorts given its flat net load average (61 GWa) falls within the lower end of the second bucket (61-65 GWa) as it displayed a 9.4 BCF power burns number in the initial nomination cycle while the actuals moved down to 9.3 BCF. Once again, the one thing that sticks out for this day is the mid-morning to late-afternoon ramp that falls outside the window of the peak solar generation that continues to be on display within ERCOT.
Sticking to the two buckets, the question within EnergyGPS that we would like to raise is what is the actual power burn floor these days as historical analysis cannot account for new wind/solar capacity in each of the regions? Stated another way, if the net load shifts lower, will the power burn value bottom out at 8 BCF or move lower? The answer to the two similar questions is that they can move lower depending on the supply stack thermal fleet and how many natural gas units are needed to operate at their minimum to provide reg-up or flex-up now that wind quantities are here to stay. We say back in December 2024, the power burn level moved down to 6.6 BCF when net load fell within the first bucket (47-50 GWa).
Figure 2 | South Central Power Burn Breakout by day and Month – 2022 through February 2025
The graph above displays the power burn daily quantity for each day throughout the year going back to January 2022. The orange colored bars indicate the days when the South Central net load average value was above 80 GW while the blue bars are the days below the threshold. The cutoff line threshold of 80 GWa does not carry any significance bit it does distinguish between the heart of summer period and everything else. The month of January has turned into a volatile month as the past two years have several days tied to the orange bars (load growth and reduced renewable output in play).
The February through April floor is much lower in years past but it is worth noting that the first week of February 2025 has displayed the January 2024/2025 level which is not your typical February outcome looking at the prior years in Figure 2. We do have to take into consideration how the natural gas landscape is shaping up when it comes to volume in storage but that is not usually a factor until the middle of April and into May. Take for example, May 2024 saw a minimum power burn level of 9.4 BCF while the previous year stat at 8.9 BCF and the one before that dropped down to 7.5 BCF. In the Spring 2024, there was a glut of molecule floating around as the previous winter did not materialize into big withdrawals and production was healthy. That left the grid vulnerable to lower prices in both the cash and forward market, thus driving up the implied heat rates so that natural gas-fired power plants can beat out the coal fleet and the molecules find a home outside of the storage caverns. Shifting back to December and January, we can see that the former has carried more volatility in the power burn numbers despite the net load days sticking below the 80 GWa threshold. The latter is much more volatile as colder temperatures are in play and the periods of such last much longer.
The figure below shows the daily average power burns (y-axis) and daily average net load (x-axis) by quarter from 2022 to the current period. The shaded area represents the range of daily average net load while the lines display the range of power burns. Last year (2024) saw a pretty clear trend (at least in Q2/Q3) as power burns for a given level of net load were higher than the previous two years. Translating this statement, pink dots are higher than orange or green dots within the same net load daily avg. bins. We also saw the variability of power burns stretch in 2024 during Q2 and reach higher levels in Q3 within the same net load bins. The 2024 Q3 temperatures were not as warm as the previous two years thus the power burn circles (pink) did not move to the far right. If temperatures were warmer, it begs the question of what the South Central power burns would have been? The last observation is in the Q1 vertical frame as the current year (2025) has pushed for higher power burns despite not reaching as far to the right as in 2024 while the floor remains quite high, especially since the start of February (highlighted by the bigger purple dots).
Figure 3 | South Central Net Load Bins vs. Power Burns by Quarter/Year
The takeaways from this discussion are 1) we have seen power burn increases for a given net load bin over the past two years and that looks to be in the works again throughout 2025 despite the additional renewable capacity 2) the floor is raised but the net load top is being shaved off between June and the end of September as the increasing solar profile matches closer to that of the hourly power demand profile 3) the solar capacity increase creates more volatility during the non-summer core months as net load ramping comes into play within ERCOT while SPP continues to deal with the wind generation volatility. The things to watch are 1) how is the renewable buildout impacting the net load hourly shape 2) continue to keep an eye on the ERCOT battery fleet growth 3) how is the natural gas market reacting to more demand in the LNG and power burn sector (for not – seems to be comfortable when it comes to the forward price valuation) 4) the variability around load growth and renewable penetration as the next couple of years will be displaying both across all markets tied to the South Central region.