Energy Management

Energy Management Fundamentals: Stay Ahead of Price Volatility this Summer

6 min read

As we enter the summer months, commercial and industrial businesses face unique challenges in managing their energy consumption and costs. With rising temperatures and increased demand for cooling, it becomes crucial for organizations to be proactive in their energy management strategies. While some key regions such as PJM, ISONE, NYISO and ERCOT are currently experiencing low energy price environments, the potential for price volatility in the markets still exists. Our regional analysts offered their insights into these regions and the top factors they see influencing summer energy costs.


Market prices in PJM are down significantly year-over-year due to a lack of seasonal demand thus far that is impacting spot natural gas prices.  A return to warmer than normal summer temperatures would lead to higher demand for natural gas and could result in an increase in spot gas prices.  Higher spot natural gas prices, like we experienced last summer, could lead to higher spot and forward power prices over the next couple of peak season months.

According to PJM’s annual summer outlook projections, the peak demand for electricity is expected to reach approximately 156GW; however, PJM has over 186 GW of installed generating capacity available to meet these needs.

Looking ahead at the forward price curve, longer-term power prices in PJM (2026-2028) could be impacted by the timing of PJM capacity auctions and the potential risks associated with the future generation retirements.

Another important factor to consider in the region is the increased growth rate of electricity demand, primarily driven by data center load and electrification.  Additionally, most of the projects in PJM’s interconnection queue are variable resources. The non-dispatchable nature of these resources must be balanced with the need for consistent power supply.


NERC has released its 2023 Regional Summer Assessment which notes that while expected resources in ISONE are forecasted to be lower than in 2022, they are still sufficient to meet operating reserve requirements under “normal” weather and demand scenarios. However, operating procedures may be necessary during periods of high demand or unexpected resource outages, with emergency resources and non-firm supplies from neighboring regional transmission operators potentially being called upon.

Alternative fuel costs play a crucial role in periods of winter fuel constraints. When dry, pipeline-transported natural gas is limited, alternative fuels such as LNG and fuel oil become essential for reliability. Global LNG prices have reached two-year lows due to mild winters in Europe and Asia, and crude oil prices have also decreased due to tempered demand amidst a rebounding Chinese economy, likely impacting energy forward prices.

Renewable and clean energy projects face both progress and obstacles. Massachusetts continues to sign and issue requests for proposals (RFPs) for wind projects in New England. The New England Clean Energy Connect, a 1,200 MW transmission line bringing Canadian hydropower through Maine to southern New England, has won an appeal to resume construction but will likely face additional legal challenges. Vineyard Wind, which has a long-term contract with Massachusetts, has received a favorable decision for one of its regulatory approvals and expects decisions on two other challenges in the coming months. Though renewables will likely lead to lower spot energy prices, the future of not only infrastructure, but power contract prices remains in flux due to siting and local opposition which have and will provide hurdles for renewable projects in the near- and medium-term future.


In New York, the summer season is expected to be mostly near normal, with July potentially experiencing the strongest temperature anomalies depending on drought and precipitation levels.  August could be more variable with cooler risks overall. The New York Independent System Operator (NYISO) has 41,148 MW of resources available to meet demand this summer and has projected a peak demand of 32,048 MW.  Last summer’s peak demand was recorded at 30,505 MW on July 20, 2022, during Hour Ending 18.  Based on existing tariff requirements, the peak demand to establish a customer’s capacity obligation will occur on a non-holiday weekday in July or August.

Looking ahead, it’s crucial to consider the impact of New York State’s Department of Environmental Conservation (DEC) “Peaker Rule” which takes effect this summer.  The rule imposes stricter emissions standards on simple-cycle combustion turbine peaking units during the summer ozone season in NYC. The rules will be implemented in two phases, starting in May 2023, with a second, more restrictive phase in May 2025, reducing available reserves for this summer and potentially increasing prices in New York and more acutely the NYC market for the foreseeable future. Anticipation of this rule appears to have caused an increase in summer capacity prices. NYISO is expected to release an updated reliability study in July, but the most recent Short-Term Assessment of Reliability (STAR) study indicates a concerning lack of reserves in NYC during the summer of 2025.

While the summer margin is expected to improve in 2026 with the anticipated addition of the Champlain Hudson Power Express (CHPE), there are potential challenges to reliability. Delays in the CHPE project, unplanned outages, growing demand, and limited winter capacity all contribute to these concerns. While the Peaker Rule includes a reliability consideration that allows for units to remain operational for up to four years if a reliability need is identified, commercial and industrial energy consumers would be well served to closely monitor these factors and adapt their energy management strategies accordingly to ensure uninterrupted operations and mitigate potential price volatility during the upcoming summer season.


In its Seasonal Assessment of Resource Adequacy (SARA), ERCOT predicts a reserve margin for this summer of 23.2% – up 1% from the November 2022 forecast. There are ~95 GW of installed capacity expected to be available to ERCOT this summer. The SARA report forecasts a net peak load of 82.74 GW and a reserve margin of 23.2%. The concern this summer, as in past summers, is that the level of dispatchable generation available to ERCOT is currently ~72 GW.  The result could be a shortage of dispatchable generation in late afternoon hours when overall load in ERCOT reaches a peak and solar generation is diminishing after 5pm CST. What is making summer risk potentially more volatile is that ERCOT is forecasting a new peak load 2.7 GW higher than last summer’s record load of 80.04 GW.

ERCOT also released its biannual Capacity, Demand and Reserves (CDR) report that forecasts reserve margins for 2024-28. The CDR continues to highlight a very large buildout of solar capacity projects submitted, with 12 GW of new solar capacity to be added in 2024 and 21.5 GW by 2025. However, as we have seen in previous years, these projects continue to get pushed out. Using ERCOT’s most stringent review standard, Quarterly Stability Assessment (QSA) study prerequisites, only 5.9 GW of new solar is expected to be ready to come online post 2024.

This year, the Texas Legislature passed two bills (HB 1550 and SB 2627), which will take several years to fully implement.  HB 1500 is the Public Utility Commission Sunset bill, which is required for the continuation of the agency.  Normally, this legislation simply focuses on whether a government agency should be sunset or renewed. While the PUCT was renewed as expected there were additional policy changes attached to the bill.  HB 1500 includes guardrails for the Performance Credit Mechanism (PCM), firming requirements for generators interconnecting after 1/1/27, requirements for ERCOT to implement a new dispatchable reliability reserve service, a repeal of the state’s mandated renewable portfolio standard, and a requirement for the PUCT to take official action on any market changes that would raise fees or costs to consumers.

The second law that signed, SB 2627, creates the Texas Energy Fund to provide low interest loans for up to 10 GW of newly-built dispatchable generation and completion grants for dispatchable generators coming online before certain deadlines, as well as grants for non-ERCOT utilities and behind the meter back-up power sources.  There is a twist to SB 2627 and that is the legislature only appropriated $5 billion under its current budget.  The legislation allows for up to $10 billion allocated as follows: $7.2 billion for loans and grants for dispatchable generation, $1.8 billion for behind the meter back-up power sources, and $1 billion for non-ERCOT utilities.  This new generation would likely see new combined cycle or simple cycle gas fired generation be constructed in ERCOT but it could contribute to the retirement of older gas or coal generation, so the net change to ERCOT reserve margins might not change overall.

Finally, while the West received major drought relief this winter, the Central states of Kansas, Oklahoma and Texas saw drought conditions worsen over this winter. The drought is significant because dry ground lacks soil moisture to provide a natural cooling effect. As temperatures get warmer, this drives AC cooling demand higher.

The best way to keep your summer strategy aligned with your organization’s goals is to stay abreast of all factors affecting your energy price. Join our Constellation analysts during our monthly Energy Market Intel Webinars, join our subscription center to receive weekly market and natural gas storage updates or contact your Constellation representative today to build your energy strategy.

**The opinions expressed in this blog are those of the Constellation regional analysts who provided input to this post.  They do not necessarily reflect views of the company as a whole or other Constellation employees or officers.  Note that Constellation is a physical energy provider and does not provide and is not providing advice regarding the value or advisability of trading in commodity interests as defined in the Commodity Exchange Act, 7 U.S.C. §§ 1-25, et seq., as amended (the “CEA”), including futures contracts, swaps or any other activity which would cause Constellation or any of its affiliates to be considered a commodity trading advisor under the CEA.

You may also be interested in these related articles: