Energy Market Update

Weekly sustainability insights can now be found by following this link: Sustainability Corner

Weekly Energy Industry Summary

Commodity Fundamentals

Week of August 10, 2026

By the Numbers:

Prompt-month natural gas settled at $2.79/MMbtu, up $.13 on Monday, August 10.
Prompt-month natural gas settled at $2.78/MMbtu, on Monday, August 3.
Prompt-month natural gas settled at $2.77/MMbtu, on Monday, July 27.
Prompt-month crude oil (WTI) settled at $82.13/bbl., up $3.95 on Monday, August 10..
Prompt-month crude oil (WTI) settled at $79.28/bbl., on Monday, August 3.
Prompt-month crude oil (WTI) settled at $82.61/bbl., on Monday, July 27.

Natural Gas Fundamentals - Neutral

A heat wave in the south will drive power-generation demand this week, but will be somewhat offset by a more mild northern tier.
Production continues to rise led by increased output in the Permian Basin resulting from higher oil and NGL prices.
Month-to-date, production averaged 110.9 Bcf/d versus 108 Bcf/d for the same period last year.
Month-to-date power generation demand averaged 49.2 Bcf/d versus 45 Bcf per day for the same period last year reflecting the first week of August 2026 much warmer than last year.
LNG feedgas volumes, month-to-date, averaged 18.4 Bcf/d versus 16.7 Bcf/d for the same period last year.
Cheniere started LNG deliveries from its 7th Train at Corpus Christi on August 10.
2027-2031 strip prices are $3.35, $3.68, $3.70, $3.65, $3.60 per MMbtu respectively, largely unchanged week-over-week.

Crude Oil - Bullish

Point of Clarification: The "Bullish" moniker above will remain in place until further notice as the situation in the Persian Gulf remains highly unstable.
Prompt-month crude (WTI) jumped yesterday, up $3.95 to settle at $82.13/bbl.
Continued uncertainty regarding the war with Iran has crude in a very volatile condition.
The DOE reports inventory of the Strategic Petroleum Reserve declined 6.1 million barrels last week ending with 298.7 million barrels, the lowest level since 1983.
The Trump Administration continues to hint at an imminent deal to fully reopen the Strait of Hormuz.
China's crude oil imports are reportedly rising, signaling less reliance on their strategic reserves and potentially an upward demand signal to an already tight market.

Economy - Neutral

July payrolls reportedly fell by 23,000 despite the unemployment rate declining.
The July CPI report comes out tomorrow followed by PPI on Thursday. Markets are looking for evidence that inflation is moderating or whether higher energy costs are reversing the trend.
GDP growth slowed in the second quarter at 1.5%, down from 2.1% in Q1.
The Fed is holding interest rates steady at 3.5-3.75%.
Inflation has cooled from peaks, but remains above the 2% target.
30-year mortgage rates are at 6.6%, the highest in a year.
Consumer confidence is soft.
Manufacturing/factory construction is healthy, supported by chips, batteries, and defense, and AI.

Weather - Neutral/Bullish

A strong heat wave in the South drives power demand with well above temperatures through the region.
The Northern tier gives way to cooler temperatures by the end of the week, somewhat offsetting the highs in the South.
A warm up in the Northwest is in the forecast.

Weekly Natural Gas Report

Inventories of natural gas in underground storage for the week ending July 31 are 3,117 Bcf; an injection of 33 Bcf was reported for the week ending July 31. Stocks were 12 Bcf lower than this time last year and 195 Bcf above the five-year-average.

Weekly Power Report:

Mid-Atlantic Electric Summary

The Mid-Atlantic Region’s forward power prices were unchanged over the past week with domestic market fundamentals remaining stable, as overall natural gas demand declined, driven by a significant drop in the power burn or demand for gas associated with producing electricity. NYMEX natural gas contract settled lower on Friday as traders looked beyond Thursday's smaller-than-expected EIA storage injection, refocusing on elevated production, softer LNG export demand, and a mixed weather outlook. As we progress through this week, the Bermuda High will build toward the East Coast, boosting temperatures to the lower 90s. If it expands farther inland and cuts off the southeasterly flow, some model guidance supports temperatures reaching the middle 90s across the Mid-Atlantic. The forward electricity prices for the 2027-2031 strips were unchanged over the past week and were 2% higher over the past month. The preliminary, day-ahead final settlement price for July in West Hub is $89.78/MWh which is 59% higher than June’s final settlement price average of $56.56/MWh.
PJM Board Issues Decisional Letter on RBP & IRAS - On 07/27, the PJM Board released a decisional letter and executive summaries of the proposed Reliability Backstop (RBP) and Connect and Manage service for large loads, which was renamed the Interim Reliability Assurance Service (IRAS). The PJM board decision on the RBP is very similar to the proposal that was presented at Stage 4 of the Critical Issue Fast Path. It envisions a parallel path with a facilitated bilateral matching phase and central procurement. The bilateral matchmaking is already underway, and the central procurement proposal filed at FERC on 7/31 for implementation, assuming FERC approval, implemented later this year. Key takeaways for the RBP would be establishing a procurement target which would represent the difference between the reliability requirement that cleared in the 2028/29 BRA (6.831 MW short), decremented by load with signed bilateral contract for supply, new integrated Resource Plan supply, and large loads committed to demand-side participation. Key takeaways for the IRAS would include establishing a Large Load Registry of all applicable Large Loads (both new and existing) with end use sites of at least 50 MW of cumulative peak load not in service by 6/1/27 and including incremental growth subject to IRAS. Electric distributors (EDs) and transmission owners (TOs) must implement IRAS for new Large Loads that do not Bring Your Own New Capacity (BYONC) or have not received credit for RBP UCAP megawatt for the delivery year and cannot be served under the 1-in-10 reliability standard. They would have to coordinate with the state and the individual customer, established procedures that would include load reduction that would trigger prior to Pre-Emergency Load Management actions.

Great Lakes Electric Summary

The Great Lakes Region’s forward power prices were unchanged over the past week with domestic market fundamentals remaining stable, as overall natural gas demand declined driven by a significant drop in the power burn or demand for gas associated with producing electricity. The NYMEX natural gas contract settled lower on Friday as traders looked beyond Thursday's smaller-than-expected EIA storage injection, refocusing on elevated production, softer LNG export demand, and a mixed weather outlook. As we progress through this week the Bermuda High will build toward the East Coast, boosting temperatures to the lower 90s. If it expands farther inland and cuts off the southeasterly flow, some model guidance supports temperatures reaching the middle 90s across the Mid-Atlantic. The forward electricity prices for the 2027-2031 strips were unchanged over the past week and were 2% higher over the past month. The preliminary, day-ahead final settlement price for July in COMED is $67.08/MWh or 91% higher than June’s final price, while the AdHub, preliminary final price averaged 72.31/MWh or 60% higher than June’s final settlement price. In Michigan, the price for July is $75.46/MWh or 73% higher than June’s average index price, while in Ameren the final price would clear at an average of $68.82/MWh or 86% higher than last month’s final settlement price.
PJM Board Issues Decisional Letter on RBP & IRAS - On 07/27, the PJM Board released a decisional letter and executive summaries of the proposed Reliability Backstop (RBP) and Connect and Manage service for large loads, which was renamed the Interim Reliability Assurance Service (IRAS). The PJM board decision on the RBP is very similar to the proposal that was presented at Stage 4 of the Critical Issue Fast Path. It envisions a parallel path with a facilitated bilateral matching phase and central procurement. The bilateral matchmaking is already underway, and the central procurement proposal filed at FERC on 7/31 for implementation, assuming FERC approval, implemented later this year. Key takeaways for the RBP would be establishing a procurement target which would represent the difference between the reliability requirement that cleared in the 2028/29 BRA (6.831 MW short), decremented by load with signed bilateral contract for supply, new integrated Resource Plan supply, and large loads committed to demand-side participation. Key takeaways for the IRAS would include establishing a Large Load Registry of all applicable Large Loads (both new and existing) with end use sites of at least 50 MW of cumulative peak load not in service by 6/1/27 and including incremental growth subject to IRAS. Electric distributors (EDs) and transmission owners (TOs) must implement IRAS for new Large Loads that do not Bring Your Own New Capacity (BYONC) or have not received credit for RBP UCAP megawatt for the delivery year and cannot be served under the 1-in-10 reliability standard. They would have to coordinate with the state and the individual customer, established procedures that would include load reduction that would trigger prior to Pre-Emergency Load Management actions.

Northeast Energy Summary

On March 31, 2025 the ISO New England (ISONE) published the requests for proposals for its first longer-term transmission planning (LTTP) procurement. Specifically, the RFP was to address the following needs by the end of 2035: 1) Increase Surowiec-South interface limit to at least 3,200 MW, 2) Increase Maine-New Hampshire interface limit to at least 3,000 MW; and 3) accommodate the interconnection of at least 1,200 MW of new onshore wind at or near Pittsfield, Maine. ISONE received six proposals from four different sponsors and on July 28 discussed with stakeholders the vigorous vetting and selection process, and identified the joint proposal from Central Maine Power, Public Service of New Hampshire, and NSTAR (Eversource) as the preferred proposal. The total project cost is ~$2.2 billion and has a Benefit-to-Cost ratio > 2 (i.e., financial benefits divided by project costs). Construction would start in Q1 2029 with an estimated Q4 2032 in-service date, and encompasses: 1) New 345 kV lines: Pittsfield-Coopers Mills & Buxton-Deerfield (70 mi total), 2) rebuilding the Larrabee Rd-Surowiec 115 kV line to operate at 345 kV, 3) retiring the ME Yankee 345 kV substation and building a new adjacent substation (Old Ferry Rd 345 kV), and 4) installing eight New STATCOMs (400 MVAR @ 345 k), and four new Phase Angle Regulators (750 MVA @ 345 kV). ISONE will soon finalize the recommendation, and approximately one month later, after the New England States Committee on Electricity’s approval, will officially notify the project’s sponsors to proceed.
NYISO advanced its response to FERC’s order on the DOE’s Advanced Notice of Proposed Rulemaking (ANOPR) on large-load interconnections by submitting an informational report and outlining a preliminary stakeholder proposal that would create new review and service procedures for sizeable and large loads. The proposal would establish Bulk Operating Load Tracking procedures for 10–50 MW transmission-connected commercial and industrial loads and Bulk Electric Large Load procedures for loads of 50 MW or greater, with resource adequacy screening, system impact studies, and potential limits on withdrawal service where new load creates reliability concerns. Loads receiving non-firm service could be subject to automatic curtailment, a $200/MWh bid cap, and a System Reliability Benefit Fee until needed upgrades or capacity are in service. NYISO also proposed enhanced metering, telemetry, remote-disconnect and ramp-rate controls, Distributed Energy Resource modeling changes, gross-demand-based charges, and consolidation of co-located resource participation models. The filing signals a more structured framework for ensuring that rapid large-load growth, including data-center-type demand, does not undermine system reliability or shift unaddressed costs to existing customers.
On July 22, the New York Public Service Commission (PSC) issued an order modifying the Clean Energy Standard Tier 1 eligibility requirements for repowered hydroelectric facilities, adopting the Department of Public Service Staff’s recommendation to reduce the minimum electricity production increase from 15% to 3%. The Commission concluded that the lower threshold better reflects the practical and economic realities of hydro repowering, where meaningful efficiency upgrades can be capital intensive and may not always produce large incremental output gains. The order also provides additional implementation direction to the New York State Energy Research and Development Authority (NYSERDA), including how to evaluate facilities with degraded generation, long-term outages, or units that are at or beyond the end of their useful life and are proactively repowered before retirement. NYSERDA must incorporate the revised requirements into its Clean Energy Standard Tier 1 Implementation Plan and file the updated plan by 9/21, creating a near-term milestone for how the new eligibility framework will be applied.
Higher summer demand and an early July heatwave drove NYISO day-ahead power prices higher in July, while forward markets continue to reflect expectations for significant winter price risk. Forward curves show the’26-27 winter strip in the ~$140 – 150/MWh range for New York City (Zone J) and $105 – 120/MWh in Western New York (Zone A). Recent heat-driven demand pushed July day-ahead power prices up 35-50% % from June across New York, with New York City prices averaging nearly $80/MWh. Meanwhile, the return of the 1,250-MW Champlain Hudson Power Express (CHPE) transmission line should provide additional clean energy imports into New York City after weeks of outage-related disruptions. The line returned to service in late July following repairs to a damaged cable along the U.S. portion of the line.

ERCOT Energy Summary

The new record all time load from 7/22 of 91,089 MW and represents a +6% increase over the 2023 record but temperatures have only been in the low 100F in Dallas and upper 90’s in Houston last week. Solar production last week averaged 13-13.7 GW on a flat average basis. Wind production ranged on a flat average load of 10.4-15.8 GW last week.
At the midpoint in August, the weather outlook for Texas will see a low simmer over the next few days, with highs in the lower 100s in Dallas and the middle to upper 90s in Houston and San Antonio. Temperatures are forecast to rise by a couple of degrees from late this week into early next week. Initially, this warming will coincide with above-normal wind generation, which is then expected to trend toward normal levels early next week, when the operational models become hotter. So far this season, these hotter operational runs have generally been too high, but they introduce some upside temperature risk as wind generation declines. Temperatures may ease slightly during the 11–15-day period but should remain above normal.
Forward prices in ERCOT last week reacted to Gov. Abbott’s order for an audit of all data center interconnections. Cal 2027 North Zone was down ~7.5% week over week, Cal 2028 was lower by ~6% and Cal 2029 was lower by ~3%.

ERCOT Real Time Prices

Source: ERCOT

Wind and Solar Output

Source: ERCOT

Real time prices were in the upper $20’s to low $30’s/MWh last week as strong renewable (wind & solar) helped keep prices in check. The only two hours last week when prices rose above $100/MWh.

Recent Solar, Wind and Battery Milestones:

ERCOT set its 5^th new charging record since June 1^st on August 7^th of 11,245 MW at 9:25 am CT, super seceding the July 4^th charging record set of 10,522 MW. On June 1^st the charging record was set at 7,847 MW, with the 3.3 GW growth representing a growth rate of 43% so far this summer.
The new all-time maximum load record of 91,089 MW from July 22^nd still stands but August has traditionally seen ERCOT set its new peak loads. ERCOT set a new maximum solar output record 35,281 MW on July 30^th and the second new one this week. On July 8^th ERCOT set a new discharge record for batteries of 11,674 MW breaking the record of 10,372 MW set back on March 13^th.
June 25^th saw a new record output for combined renewables of 51,974 MW, the second this week and breaking the previous record of 47,919 MW on May 14^th. ERCOT set a new wind record last week at 28,928 MW on May 17^th at 11:50 PM CT as winds were strong overnight. The previous maximum wind record of 28,715 MW set on 3/14 at 10:55 pm CT. ERCOT also set a maximum renewables output of 47,919 MW on May 14^th at 3:15 pm CT. This was ~900 MW higher than the previous record from last June.

Generator Outages

Thermal generation outages in ERCOT were pretty steady last week at 9 GW amid continued warm temperatures. Wind, solar and batteries again helped provide adequate reserves. While this heat event was short lived its demonstrates how forced outages can rise during an extended heat wave event. August could see a return of above normal temps as that is typically the month ERCOT sets its highest loads.

https://www.gridstatus.io/graph/ercot-outages?iso=ercot&outageType=thermal

Source: ERCOT & Grid Status

TX Legislature, PUCT, & ERCOT News:

ERCOT Prepped to Finalize Batch Zero Categories by August 7^th

While news was breaking last week, we will quickly recap that Governor Greg Abbott directed the Public Utility Commission of Texas (PUCT) and ERCOT to conduct a comprehensive audit and verification of all data center projects currently progressing through ERCOT’s interconnection process. The directive requires the PUCT and ERCOT to collect additional information from each data center project, including: the extent to which projects are receiving state or local financial incentives and whether they are “paying their own way”; planned power supply arrangements, including reliance on ERCOT resources and development of on-site generation; projected water consumption, water sourcing, reuse practices, and cooling technologies; measures to mitigate community impacts such as noise, lighting, traffic, and emergency response concerns; and detailed ownership and control information. Projects that fail to provide this information or that otherwise fail to comply with applicable PUCT, ERCOT or state law requirements will be denied interconnection and access to the Texas power grid.

On 8/6, PUCT Chair Thomas Gleeson requested that implementation of the Governor’s directive be placed on the 8/14 open meeting agenda for discussion. This special meeting is required so the PUCT can map out with ERCOT as to how to proceed with the audit. The memorandum signals the agency’s intent to evaluate the scope of its existing authority and consider next steps for requiring additional disclosures and verification from large-load and data center projects as part of the ERCOT interconnection process. Notably, neither the PUCT nor ERCOT currently appears to have clear authority to deny an interconnection request solely based on a project’s failure to provide information regarding water consumption, community impacts, or related mitigation efforts. As a result, the 8/14 meeting will be important to watch for indications of whether the PUCT intends to pursue rulemaking, additional reporting requirements, or other actions to implement the Governor’s directive within existing statutory authority. A key factor in how much of a delay the audit might make to ERCOT Batch Zero process resuming, is how much of this information do data center applicants have already collected and how long it will take ERCOT to collect that data and submit it to the PUCT as part of its audit process.

Governor Abbott Calls for Municipal Utilities to Open to Competition - Governor Abbott announced a new component of his Keep Texas Affordable agenda focused on lowering electricity costs through expanding retail electric competition by ending the exclusive control that municipally owned utilities in cities such as Austin and San Antonio have over electricity service, allowing customers in those utility footprints to choose their electricity provider. The proposal would impact more than five million Texans currently served by municipally owned utilities. The proposal would need to be passed by both chambers of the legislature during the upcoming spring session. The proposal to date has not been expanded to coops which would likely be faced with heavy opposition from rural Republican voters.

CAISO, Desert Southwest and Pacific Northwest Energy Summary

This persistent summer heat has fundamentally altered the dynamics of California’s two largest natural gas storage systems, which are no longer moving in tandem. Both PG&E and SoCalGas’s systems have experienced summer drawdowns as molecules have been redirected to the state's gas-fired fleet. PG&E saw its inventory touch a 2026 high of 187.1 Bcf in early July before drawing down to its current level of 175 Bcf. Despite this 12 Bcf pullback, PG&E remains well-positioned, tracking ahead of 2025 levels (174.4 Bcf) and comfortably above 2024 benchmarks (156.6 Bcf). In stark contrast, SoCalGas peaked prematurely at 107.7 Bcf back in mid-January. Since then, an 8.5 Bcf pullback has dragged its balance down to 99.2 Bcf, falling behind both 2025 (104.5 Bcf) and 2024 (106.0 Bcf) figures for the same day. As of Monday morning, combined California storage sits at 274.0 Bcf, down slightly from Friday’s 274.6 Bcf, with SoCalGas successfully flipping to net injections over the weekend while PG&E slowed its withdrawals to a much lighter pace.
Grand Canyon: getting bigger. The Colorado River is facing its most severe water shortage in over 60 yrs, with reservoirs at historic lows and the feds preparing drastic cuts to prevent system collapse. At the time we went to press, the combined water level in three of the U.S. biggest reservoirs, Lake Powell, Lake Mohave and Lake Mead is 33% of capacity. The Colorado River supplies water to approximately 40M people across seven states (Arizona, California, Colorado, Nevada, New Mexico, Utah, Wyoming) and Mexico. Since 2000, the region has experienced a megadrought - the worst in over 1,200 years. Researchers predict Lake Mead and Lake Powell will set a new record low for their combined water storage every day from now until next spring, when the runoff from the winter snowpack starts to replenish water levels. After years of stalled negotiations among the states, the federal government released its final environmental impact statement on July 31, laying out how it plans to manage the basin through 2036, including big cuts for Lower Basin states. From an energy perspective, the low reservoir levels are a dramatic signal that the system is at risk of crashing, meaning reservoir levels are so low that water cannot be delivered from them. At the end of July, Lake Mead was at 1,041 feet of elevation, leaving it about 90 feet of cushion before it reaches 950 feet, the level at which the Hoover hydro generators can no longer generate electricity. Lake Powell is much closer to losing hydropower with the lake at 3,521 feet, just 1 foot above its lowest record ever and 31 feet over the 3,490 foot minimum level for power generation from the Glen Canyon dam. Average power at Glen Canyon this summer has dropped to just a couple hundred megawatts, running between 220 and 260 MW since April and sitting as the lowest of the five years. Hoover's output has stayed more consistent, tracking mostly alongside recent years through the spring and peaking near 560 MW in March, but it has seen a sharp drop toward the end of July into August as reservoir levels have fallen to record lows. From a keeping the lights on perspective, Hoover is more critical. The dam spends the overnight and morning hours generating close to nothing, in the range of 6 – 50 MW, then ramps hard into the evening hours with output regularly swinging between 800 – 1,000 megawatts in the summer evenings. That roughly one gigawatt of flex swing into a handful of hours each day is the flexibility grid operators rely on as they deal with disappearing solar resources during the daily phenomenon known as sunset.
California’s 2026 fire season has started quietly. Through the first week of August, roughly 4,400 wildfires have burned just over 228,000 acres – below the five‑year average for this point in the year. But elevated wildfire risk keeps rising to the forefront of conversations. Heatwaves, defined as at least three consecutive days above the 90^th percentile for temperature, account for nearly half of summer wildfire acreage in the West, especially in forested areas. Heat dries fuels, keeps nights unusually warm (closing a key suppression window), and can prime the atmosphere for lightning, which has ignited some of California’s largest fires. In addition to the anguish and loss these events take on the local populace, something we’re actively watching play out now in the Pacific Northwest, the broader region may unexpectedly be brought into the event as transmission lines and other power infrastructure may need to be curtailed to support fire suppression efforts. This can have sudden and dramatic effects on day ahead and real time index prices.

Stay up-to-date on the latest energy news and information:

Coming soon from Constellation Customer Insights: Help us provide you with greater service by completing our online study later this month. For a limited time, eligible customers can choose to accept an incentive for taking the time to provide feedback.

Energy Market Intel Webinar - Register for our next market update webinar on Wednesday, September 16 at 2 p.m. ET when the CMG team will provide insights on market factors currently affecting energy prices, such as weather, gas storage and production, and domestic and global economic conditions.
Fortunato & Friends Webcast - Stay tuned for information regarding our next Fortunato & Friends webinar featuring Constellation's Chief Economist and a special guest
Energy Terms to Know - Learn important power, gas and weather terms.
Sustainability Assessment - We invite you to complete a brief assessment that helps us learn where your company is in building and/or implementing a sustainability plan. Through these insights, Constellation can customize solutions to meet your needs.
Subscription Center - Sign up to receive updates on the latest market trends.

Questions? Please reach out to our Commodities Management Group at CMG@constellation.com.

DISCLAIMER: The information contained herein has been obtained from sources which Constellation believes to be reliable. Constellation does not represent or warrant as to its accuracy or completeness. All representations and estimates included herein constitute Constellation’s judgment as of the date of the presentation and may be subject to change without notice. This material has been prepared solely for informational purposes relating to our business as a physical energy provider. We are 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 us or any of our affiliates to be considered a commodity trading advisor under the CEA. Constellation does not make and expressly disclaims, any express or implied guaranty, representation or warranty regarding any opinions or statements set forth herein. Constellation shall not be responsible for any reliance upon any information, opinions, or statements contained herein or for any omission or error of fact. All prices referenced herein are indicative and informational and do not connote the prices at which Constellation may be willing to transact, and the possible performance results of any product discussed herein are not necessarily indicative of future results. This material shall not be reproduced (in whole or in part) to any other person without the prior written approval of Constellation.

© 2026 Constellation. The offerings described herein are those of either Constellation NewEnergy, Inc., Constellation NewEnergy-Gas Division, LLC or Constellation Navigator, LLC, affiliates of each other. Brand names and product names are trademarks or service marks of their respective holders. All rights reserved.