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.

The New Jersey Board of Public Utilities (NJBPU) recently approved nearly $1.1 billion in transmission system upgrades to the state’s electricity grid. These upgrades will enable electricity generated from offshore wind assets to be connected to the power grid and are a part of the state’s plan of creating 7,500 MWs of offshore wind capacity by 2035. The project, the Larrabee Tri-Collector Solution (LTCS), is estimated to cost $504 million and was proposed by JCP&L and Mid-Atlantic Offshore Development, a joint venture of EDF Renewables North America and Shell New Energies US. The NJBPU also awarded additional onshore transmission upgrades to accommodate the additional generating capacity from LTCS and other planned offshore wind projects. These awards went to ACE, BGE, LS Power, PECO, PPL, PSE&G, and Transource at an estimated cost of $568 million. In a press release, the NJBPU stated, “These project selections will establish the first coordinated solution for offshore wind transmission in the U.S., testifying to New Jersey’s status as a national forerunner in clean energy production. This coordinated transmission solution will minimize cost and other impacts while supporting the continued expansion of offshore wind energy in the state.” New Jersey is looking to the Ocean Winds project as the first step in achieving the state’s offshore wind goals.

The Ocean Winds One project will be located approximately 15 miles off the coast of New Jersey (see Figure 1) with a generating capacity of 1,100 MWs through nearly 100 General Electric Haliade-X 12 MW turbines. These massive turbines are 850 feet tall with a blade radius of 750 feet. Ørsted and PSEG are the owners and developers of the Ocean Wind project, which will be New Jersey’s first utility-scale offshore wind farm. Project construction is scheduled to begin in early 2023, with commercial operations expected at the end of 2024. A second and adjacent project, Ocean Winds Two, is expected to add an additional 1,100 MWs of generating capacity. Construction on that project is not expected until 2028. The Oyster Creek Nuclear Station was closed in September 2018 and removed approximately 650 MW of generating capacity from the state’s grid. Ocean Wind One and Two are intended to not only replace that asset but also add an additional 1,550 MWs of carbon-free electricity capacity. Given the difference in availability of offshore wind compared to nuclear energy facilities, the additional capacity will be needed to help offset Oyster Creek production.

Leaves are changing and temperatures are falling, which can only signify one thing: PJM’s coincidental peak season is behind us. In PJM, there are five Coincidental Peaks (5CP) that are determined by the five highest daily peak hourly loads for the summer. Once the 5CP season comes to an end, the utilities begin the process of calculating Peak Load Contributions (PLC) and capacity costs for the upcoming year. Typically, 5CP events occur in PJM when the hourly load forecast approaches 140,000 MWs. The summer of 2022 was no different.

Power prices across the country have been on the rise since the summer of 2021 and PJM is certainly no exception. Anyone with an electricity supply contract expiring in the next 12 months, has seen a significant increase in pricing, upwards of 120% higher than where prices were at the end of 2021. Figure 1 shows the historical trading range for forward wholesale electricity prices for calendar strip 2023 to 2027 at PJM’s largest trading hub, PJM West.

PJM Summer Spot Prices Now Higher Than Winter

Anyone who has entered into a new electricity agreement in the last twelve months knows that prices are between two and three times higher than previous contracts. One year ago, wholesale electricity for calendar year 2023 was trading at $30.77/MWh at the PJM West hub in Western Pennsylvania. In early May 2022, it peaked at $88.35/MWh, a nearly three-fold increase. This rapid rise in electricity futures has created sticker shock for many electricity and natural gas buyers over the last year. And while this may not be news, some buyers may be surprised to learn that spot electricity prices in PJM are at their highest levels in over ten years.

On June 21, 2022, PJM posted the results of its capacity auction, also known as the Reliability Pricing Model (RPM), for the planning year June 2023 to May 2024. The execution of this auction has been postponed multiple times over the last few years due to FERC rulings on the validity of the PJM auction’s design. Differences between FERC and PJM seem to have finally been resolved to the extent to allow the auction to proceed. This is important because these latest auction results give the market some much-needed clarity into future capacity costs, which are a major cost component of next year’s overall electricity costs for all retail customers in PJM states.

An Overview of Coincidental Peak Costs by ISO

Coincidental Peak (CP) is the measurement of an electricity meter’s actual usage at the time of the regional grid’s highest demand and determining that meter's share of the entire grid’s demand. This concept of identifying a facility’s share of the grid’s total maximum demand is often used in determining the allocation of specific cost components. The specific methodology of how that equation works and which cost components it impacts varies from region to region, and often even utility to utility, and even by customer class, but the overall concept is the same. In this post, we explain how this works in each of the major, deregulated electricity regions, and detail which costs are the most impacted by this variable.