July was a month of extremes across the PJM footprint — a blistering start gave way to a sharp cooldown, capacity auction results reinforced ongoing affordability and reliability concerns, and PJM took its first concrete steps toward reforming how new power plants connect to the grid.

A heat wave in the first 2 weeks of July pushed PJM prices sharply higher. The single highest print of the month at PJM West Hub came at 7 p.m. on July 2, when prices spiked to $1,222.75/MWh during the earliest and sharpest heat event, pushing that day's full 24-hour average to $336.65/MWh. At the other extreme, prices dipped to a monthly low of $21.53/MWh in the early morning hours of July 19, once the mid-month cooldown had taken hold.

The prompt August 2026 contract at PJM West Hub traced a similar arc. Entering July, On-Peak August was trading around $92/MWh. As the heat wave intensified, it ran up to a year-to-date high of $135/MWh on July 8 — a roughly $43/MWh run-up in just five trading sessions. As actual weather eased and that risk premium unwound, the contract steadily retreated through the rest of the month, settling at $81.95/MWh by July 31.

PJM's 2028/2029 Base Residual Auction (BRA) results, released mid-July, cleared at the FERC-approved price cap of $325 MW/d — the third consecutive auction to hit that ceiling. Without the price collar in place, PJM estimates the auction would have cleared closer to $555 MW/d  system-wide, and as high as $777 MW/d in the ComEd zone.

Despite cleared capacity rising 3.7 GW year over year, PJM still came up 6.8 GW short of its reliability target — the second consecutive auction with a system-wide shortfall (last year's shortfall was 6.5 GW). Natural gas remains the dominant resource at 46% of the mix, followed by nuclear (20%) and coal (18%), with gas capacity growing as coal continues to retire.

The consistent theme: Demand growth, particularly from data centers, continues to outpace new supply.

On August 3, PJM announced results from the first cycle of its newly reformed interconnection process — a major structural change directly aimed at the supply shortfall driving the aforementioned reliability and pricing pressures.

• 715 new generation projects, representing more than 201.5 GW of nameplate capacity, qualified to move into PJM's study process under Cycle 1 — the first group processed under the reformed "first-ready, first-served" approach.

• The mix is diverse: Storage led with 314 projects (60.0 GW), followed by natural gas (147 projects, 99.8 GW — the largest capacity contributor), solar (117 projects, 11.8 GW), wind (61 projects, 3.9 GW), solar-storage hybrids (37 projects, 7.5 GW), nuclear (24 projects, 17.3 GW), and hydro (5 projects).

• The application window closed April 27 with 811 total proposals submitted; the reformed process requires developers to show real viability up front — meaningful financial commitments and proof of site control — before entering the study cycle, which is designed to run 1 to 2 years per project. There is no backlog remaining from prior interconnection queues.

• PJM is using new tools, including an AI-enabled review tool (HyperQ, developed with Google's Tapestry), to process the volume of applications more efficiently.

PJM continues to project demand could grow by up to 70 GW by 2038, driven largely by data centers and other large loads. Importantly, PJM itself cautions that nameplate capacity figures reflect maximum potential output — historically, only a portion of projects that enter an interconnection queue ultimately sign agreements and reach commercial operation. Since 2020, PJM has processed more than 300 GW of interconnection requests, resulting in just over 100 GW of signed agreements. Only 51 GW is currently under signed agreements without further delay from permitting and supply-chain hurdles.

Meanwhile, escalating geopolitical tensions involving Iran and the intermittent closure of the Strait of Hormuz have significantly disrupted global energy markets, contributing to substantially higher international energy prices. LNG prices in both Europe and Asia have doubled from approximately $10/MMBtu to $20/MMBtu, slowing the pace of seasonal storage injections across key consuming regions. Elevated global LNG prices, coupled with below-normal inventory levels, support continued robust demand for U.S. LNG exports, with export facilities expected to operate near capacity for the remainder of the year.

Crude oil markets have also experienced heightened volatility. Prices that were trading near $60 per barrel prior to the war have fluctuated between $70 and $110 per barrel as market participants react to evolving geopolitical developments. Higher oil prices improve drilling economics and are likely to encourage additional Permian Basin development along with an increase in associated natural gas production.

While global energy prices remain elevated, natural gas in the U.S. remains well supplied with prices leaning bearish. The recent decline in domestic natural gas prices may present an attractive opportunity for customers to evaluate forward purchases. Chart 2-4  illustrates pricing for a 1-year natural gas contract beginning January 1, 2027, compared with historical levels dating back to the post-COVID period. Historically, when prices approach the 10th percentile of the observed range — meaning prices have been higher approximately 90% of the time and lower only 10% of the time — the market has offered favorable opportunities to secure a portion of future natural gas requirements.