Over the past few years, energy markets have been pushed to the brink, and we’ve seen unprecedented market volatility brought on by the pandemic, supply and demand issues, extreme weather conditions, and more. We recently reported that natural gas prices have significantly fallen over the last several months. And while electricity rates typically follow natural gas prices, customers in Ohio who are on default service with the utility may be surprised to see their rates materially increase in June.

The utility companies in Ohio determine their standard offer service rates by conducting a set of auctions, which establish rates for a planning year from June through May. These auctions are carried out between November and April to procure the supply of electricity. The November auctions have played a significant role in the anticipated surge in prices due to elevated wholesale electricity prices witnessed in the fall of 2022, shown in Figure 1. The current price to compare to supplier rates in Columbus (AEP’s Ohio Power) is 7.4¢/kWh and is only valid for two more months. November’s auction for this utility cleared at 11.9¢/kWh for 45% of their expected load. An additional incremental auction held this month cleared at 8.9¢/kWh for the remaining 55%, softening some of the price increase. Rates for the planning year 2023/2034 are now fixed at a weighted average price of 10.3¢/kWh for energy. After additional cost components are factored in, the forecasted price to compare in AEP starting in June is 12¢/kWh, a 55% increase from current commercial rates. Commercial customers in FirstEnergy utilities (Ohio Edison, Toledo Edison, and The Illuminating Company), Duke, and AES territories can expect similar rate increases in the range of 10 to 13¢/kWh beginning in June 2023.

One might legitimately expect a future TV series to be called, “It’s Always Sunny in New York City.” This is not because there is a spin-off of the acclaimed FX series in the works, but because the economics of solar power in Con Edison’s service territory have never been more attractive. It is worthwhile for clients who may have considered on-site solar in the past to re-examine the options that are available. Highly attractive incentives from the federal government and Con Edison in addition to rising utility rates have created an ideal opportunity to get new or updated on-site solar proposals. There is some degree of time sensitivity, since incentives from the utility will run out once enough solar projects have been approved by Con Edison.

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.

Over a year ago we reported that Con Edison had filed for a one year rate case to increase electric delivery rates by 17.6% and gas delivery rates by 28.1%, resulting in a system-wide cost increase of $1.2 billion and $500 million respectively. Figure 1 compares the proposed cost increases to take effect in 2023 to those filed in previous years.

Earlier this month, the weather sage, Punxsutawney Phil, saw his shadow, retreated into his burrow and proclaimed six more weeks of winter. The problem is that Phil doesn’t seem very plugged into the latest meteorological observations or forecasts. Natural gas markets aren’t listening to Phil either. In fact, just looking at natural gas prices, one might guess that winter either never arrived or ended when the Astros won the World Series in the first week of November. Figure 1 shows how natural gas prices for the calendar year 2023 (blue line), 2024 (black line) and 2025 (green line) have traded since January 2021. This chart clearly shows that prices have dramatically fallen across those three calendar years over the last six months. On September 1, natural gas for 2023 was trading at $6.69/Dth. Today, it has lost 60% of its value and is trading at $2.70/Dth. Prices for 2024 and 2025 have fallen by similar amounts. This natural gas correction is being driven by a very mild winter and warmer than average temperatures.

What a difference three months make in the constantly changing landscape of the natural gas market in the US. Last September, the December delivery contract for NYMEX’s Henry Hub, was trading at approximately $9.50/MMBtu, while natural gas prices in Europe were trading near $90/MMBtu. On November 28, the December contract settled for the last time at a final price of $6.65/MMBtu, a drop of almost $3.00 from the August high, while major European trading hubs are now near $30/MMBtu.

There were several factors that moved future prices for this winter’s gas delivery down from its late-summer highs. However, many of those bearish influences have started to change and reverse direction.

First, inventory levels of US natural gas in storage grew through the months of September through November at a pace that was significantly higher than expected. In late August, the market consensus was that the US would have about 3,400 Bcf of natural gas placed into underground storage facilities. That belief was dramatically changed when more than 100 Bcf of gas went into storage for six of the next seven weeks. The 1,004 Bcf of injections between weeks ending September 2 and November 11 was almost twice as much as in 2020, and the largest of the last decade.

Those injections came to a dramatic reversal on the Wednesday before Thanksgiving when the EIA reported the first withdrawal of the season of 80 Bcf, with an even stronger withdrawal expected for Thursday, December 1. Figure 1 shows that the gap between gas in storage and the five-year average was reduced from 10.5% in late August to 0.4% on November 11. Last week’s 80 Bcf withdrawal was enough to open that gap to 3.3%.