Given that we are halfway through July, we thought it would be appropriate to provide an update on how major power markets have performed as they relate to each ISO’s coincident peak demand management program.

So far, both weather and demand on the PJM and NYISO grids have been mild compared to recent summers and average summer temperatures. The mean temperature, compared to the average over the last thirty, fourteen, and seven days for the period ending July 13, is shown in Figures 1, 2, and 3 below. These charts show that summer has not really arrived in the middle of the country and that temperatures in the Northeast are only 2º to 3º F above the average.

Early this month, ERCOT released the Seasonal Assessment of Resource Adequacy (SARA) report detailing market conditions as they exist going into the summer of 2023. This report takes into consideration the power output from all current, new, and planned generation that will be available comparing it to the forecasted peak load.

On the same day that ERCOT released the SARA report, the Chairman of the Public Utility Commission of Texas (PUCT), Peter Lake, released the following statement “Data shows, for the first time, that the peak demand for electricity this summer will exceed the amount we can generate from on-demand, dispatchable power." While the initial shock of these words is quite alarming and was quickly picked up by regional news agencies, we believe ERCOT is still better off this summer than last, and that the evolution of the grid to larger and larger percentages of renewable generation is not a new story. And while the statement of the Chairman is not technically false, it is somewhat misleading. Here is more of the whole story.

Figure 1 below is a summary of the report’s findings, demonstrating the load forecast scenarios on the left and a breakdown of the generation by type on the right, rated for this and last year’s summer capacity (the expected generation capacity during peak hours) as well as the current nameplate capacity (theoretical maximum output). Lastly, the reserve margin is a measure of the difference between the summer capacity and the maximum forecasted peak in the summer season. 

On March 17, 2023, the Texas Court of Appeals added significant uncertainty to the state’s electricity market. The Court sided with Luminant in their ruling that the Texas Public Utility Commission’s (PUC) decision on February 15, 2021 and February 16, 2021 (in the middle of Winter Storm Uri) to unilaterally set the market price at the cap ($9,000 per MWh) was invalid. The Court’s decision creates unprecedented uncertainty in the electricity market and could lead to ERCOT resettling Real-time Settlement Point Prices for multiple days during that week because of the PUC’s order. 

This case takes us back to Winter Storm Uri, which devastated Texas in February 2021. The storm caused a significant portion of the generation fleet (both natural gas and renewables) to fail. Without sufficient generation, ERCOT was forced to institute widespread outages to avoid a total grid collapse.  The widespread outages reduced demand for electricity, and as result, the energy market started clearing well below the $9,000 per MWh cap.  

On February 15, 2021, the PUC, after a short hearing, unilaterally determined that the market price must artificially be set at the cap in the event of widespread forced outages. This increased market prices from around $1,200/MWh to $9,000/MWh (see Figure 1). On the next day, the PUC met again, and effectively confirmed its earlier ruling. Those orders on February 15^th and 16^th, dramatically increased electricity market prices until the energy supply shortage ended on February 19^th.

Why did Lubbock vote to deregulate the LP&L service territory?

Lubbock, Texas, the 11th most populous city in the state and birthplace of rock ‘n roll legend Buddy Holly, is becoming a deregulated electric territory. On February 22, 2022, the Lubbock City Council cast a unanimous vote in favor of electric deregulation, the final hurdle to transition Lubbock Power and Light (LP&L) to competitive retail electric service. LP&L hopes to fully transition service by mid to late 2023. Lubbock will now join over 7 million Texas electric consumers with the right to choose their own retail provider.

On behalf of the team at 5, I am pleased to forward our February market letter. This letter discusses: (i) the recent fall in natural gas prices and increasing natural gas price volatility, (ii) the 188th Congress and the potential impact of the election on Federal and State energy policy in 2023, and (iii) how the electricity grid held up during Winter Storm Elliott and the February cold snap.

After Winter Storm Uri in February 2021, the Texas legislatures passed Senate Bill 3, which includes provisions intended to improve the reliability of the grid. One specific portion of this law in Section 18(3) calls for the competitive procurement of additional ancillary services to ensure there is enough electricity supply to keep up with demand during future severe winter weather events.

The Public Utility Commission ordered ERCOT to develop a “firm-fuel” product that would improve grid stability by procuring 3,000 to 4,000 MW of capacity from generation resources that do not depend on natural gas delivered through pipelines. The intent of this provision of the law is to ensure that a certain amount of additional deployable generation capacity can operate even during times of low natural gas pressure in the state’s pipeline system. This new ancillary service is known as Firm Fuel Supply Service (FFSS). The provision required the procurement of this additional reserve capacity to not exceed $54 million and covers the period from November 15 through March 15. In all, 2,941 MW of generation capacity was procured from 19 different generation assets across the state at a total cost of $52.9 million.

Eighteen of the nineteen assets that cleared the auction will use fuel oil (diesel) as the backup fuel source with only one asset relying on onsite natural gas storage capabilities. It is interesting to note that 77% of this capacity is from older, inefficient steam turbine power plants built between 1958 and 1978. These assets use steam, produced from boilers to spin the turbine blades which produce electricity. The remaining 23% of the FFSS capacity was procured from generators that entered service after 1988. These “newer” plants burn fuel in large gas turbine engines, similar to marine turbine generators used in naval and commercial vessels. These engines can run on natural gas, jet fuel, or diesel. A summary of the generating assets procured through this inaugural FFSS auction is shown in Figure 1.