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 May 11, 2023, the U.S. Environmental Protection Agency (EPA) proposed new rules designed to limit emissions from existing and new coal and natural gas fired power plants. This is the EPA’s third swing at regulating CO2 emissions from power plants. Its first at-bat dates back to 2015 when the Obama Administration’s EPA introduced the Clean Power Plan (CPP). The CPP proposed state-by-state emissions limits. These limits were quickly challenged by numerous states, particularly those with significant amounts of coal-fired generation. While these legal challenges were ongoing, President Trump was elected. Trump scrapped the CPP and introduced the Affordable Clean Energy Rule (ACE), which overrode the CPP and gave the states more power to set their own emission limits. The ACE also faced challenges in the courts.

In June 2022, the Supreme Court issued a ruling in West Virginia v. EPA that significantly limited the ability of the EPA to regulate emissions without a clear mandate from Congress. This ruling assures that the EPA’s new proposed rules, if finalized, are likely to face a lengthy legal battle.

The latest EPA plan sets out aggressive emission reductions and is likely to further accelerate the retirement of fossil fuel generation units. By 2030, the EPA plan requires any coal plant that intends to operate past 2040 to use a carbon capture and storage (CCS) system to eliminate 90% of its CO2 emissions. Large natural gas generation units will also be required to install a CCS that captures 90% of their carbon emissions by 2035 or operate on clean hydrogen by 2038. While there are different restrictions for smaller generation units, the EPA’s rules lean heavily on carbon capture, clean hydrogen and in some instances, use of dual-fueled gas plants with both natural gas and green hydrogen. At the same time, the EPA has acknowledged that CCS and clean hydrogen are not yet in widespread commercial use.

As filed last week, the EPA plan is a proposed rule, and the EPA will need another year or so to issue a final version. Once the final version is issued, states will have another two years to submit plans to comply with the regulations. This timetable will be delayed further by the inevitable legal challenges. West Virginia Senator Shelley Moore Capito and Attorney General Patrick Morrisey have already vowed to lead congressional and legal efforts to kill the rule.

A few things are clear. First, if the rules are adopted, the cost of generating electricity from coal and natural gas plants will increase dramatically. Second, even if the prospects for the EPA’s new rule are limited by various challenges, the proposed rules will cast a shadow over new investments in existing and new fossil fuel generation. Testifying before FERC on May 4, 2023, a bipartisan panel of FERC commissioners (2 Democrats and 2 Republicans) raised their shared concern that the reliability of our electricity grid is challenged by the fact that we continue to see fossil plants retire at a rate far faster than they are replaced by new emission-free generation. Of course, we will continue to monitor this important regulation on behalf of our clients.

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.

Here is the good news: in February, PJM posted the results of its latest capacity auction for the planning year June 2024 to May 2025. And for the most part, those prices are similar or lower than those for the 2023/2024 planning year. Historically, PJM holds annual capacity auctions to secure capacity three years in advance. However, recent auctions have been delayed over the last few years due to FERC rulings on the validity of the PJM’s auction design. These auctions are important because the results determine future capacity rates paid to generators, which are a major component of overall electricity rates for all retail customers in PJM states. Without this clarity and price transparency, electricity customers in PJM states risk paying high premiums to fix the price of capacity in future electricity contracts. The results of the latest auction provide price certainty for contracts through May 2025. The good news is that overall, the price of capacity fell again in most parts of PJM.

Figure 1 shows the latest auction clearing prices in dollars per MW per day across different Locational Delivery Areas (LDAs) in PJM. The capacity price for most of PJM cleared at $28.92/MW day (see the light blue area in Figure 1 labeled “RTO”), which is down from $34.13/MW day from last year’s auction for planning year 2023/2024. Capacity in eastern parts of PJM cleared at higher rates because of regional differences in the generation mix (natural gas, nuclear, coal) and the electricity infrastructure across various states and utilities. For example, capacity prices are higher in the BGE and Eastern MAAC LDAs because there is congestion on the electricity grid when power is moved from Ohio to Maryland and New Jersey during periods of peak power demand.

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.