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Weekly Energy Industry Summary

Commodity Fundamentals

Week of July 27, 2026

By the Numbers:
 
  • Prompt-month natural gas settled at $2.77/MMbtu, down $.11 on Monday, July 27.
  • Prompt-month natural gas settled at $2.86/MMbtu, on Monday, July 20.
  • Prompt-month natural gas settled at $2.90/MMbtu, on Monday, July 13.
  • Prompt-month crude oil (WTI) settled at $82.61/bbl., down $6.70 on Monday, July 27.
  • Prompt-month crude oil (WTI) settled at $84.60/bbl., on Monday, July 20.
  • Prompt-month crude oil (WTI) settled at $78.14/bbl., on Monday, July 13.

Natural Gas Fundamentals - Neutral/Bearish

  • Natural gas production is grinding upward throughout the month of July.  Month-to-date, production averaged 110.3 Bcf per day with three days this week posting over 111 Bcf per day.
  • LNG exports continue to lag modestly, averaging 18.6 Bcf per day in July as ongoing maintenance at Freeport LNG continues to reduce LNG sendout about 1 Bcf per day.
  • Freeport LNG has said that maintenance will continue through August, reducing total U.S. LNG feedgas demand.
  • Natural gas storage inventories are 6.5% above the five-year average and continue to be on track to be full by the end of October.
  • Power generation demand for July averaged 48.4 Bcf per day versus 47.6 Bcf per day for the same period last year.
  • The general condition of the market; Well supplied, surging production, ample storage and lagging LNG send out weigh on the top while summer power-generation demand supports the bottom. 

Crude Oil - Bullish

  • Crude oil prices are falling hard this week.  WTI settled at $82.61/bbl., yesterday, down $6.70 and as of this writing, prompt-month crude is down $3.41 to $79.26 per barrel.
  • The U.S. stopped offensive action in Iran three days ago after a thirteen-day period of bombardment and naval action in and near the Persian Gulf.  
  • The Administration said that offensive action was stopped to give peace talks a chance.
  • The U.S. blockade of Iranian oil shipments continues.
  • The situation remains highly unstable.

Economy - Neutral

  • Thirty year fixed mortgage rates hit 6.58%, the highest level in nearly a year.
  • The Conference Board said its consumer confidence index fell to 90.8 in July from an upwardly revised 92.2 in June.
  • Investors are increasing bets on a Federal Reserve rate rise, The Financial Times reports.
  • President Trump has threatened new EU tariffs in retaliation for fines on U.S. tech groups.
  • This Thursday, Q2 GDP data will be released.
  • Personal Consumption Expenditures (PCE) inflation data will be released this week along with personal income, spending and weekly claims for unemployment.

Weather - Neutral/Bearish

  • A cold front tracking across the Ohio Valley and East today will bring in cooler and less humid air for the balance of the week while notable heat will persist across Texas and much of the West.
  • The main heat ridge is positioned over the Western United States.
  • After the ten day period, above normal temperatures are forecast to move East with variability as well.

 

 

Weekly Natural Gas Report

  • Inventories of natural gas in underground storage for the week ending July 17 are 3,056 Bcf; an injection of 32 Bcf was reported for the week ending July 17. Stocks were 16 Bcf lower than this time last year and 183 Bcf above the five-year-average.
Values reflect week ending July 24, 2026
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Prices reflect week ending July 24, 2026

Weekly Power Report:

Mid-Atlantic Electric Summary

  • The Mid-Atlantic Region’s forward power prices were slightly higher over the past week as domestic market fundamentals were stable amid cooler temperature forecasts and an ample supply of natural gas.  US natural gas futures fell to $2.73 per MMBtu early Tuesday morning, extending losses to their lowest level in nearly twelve weeks.  US gas prices dropped as gas storage inventories remained at 6.4% above the 5-year average, average gas output in the L-48 states rose to 110.4 Bcf/d so far in July, and LNG send-outs continue to be lower due to maintenance.  A cool front will be moving across the eastern United States this week. The northern tier of the nation is closer to normal, with a few below-normal days mixed into the pattern.  Next week features a broadening ridge that begins to bring above-normal temperatures back across the Midwest to the East Coast as we head into the early part of the 11 to 15-day period.  The forward electricity prices for the 2027-2031 strips were 1% higher over the past week, with a 3% increase on the 2027 term, while the entire term was 2% higher over the past month.  The month-to-date, day-ahead settlement price for July in West Hub is $94.67/MWh which is 67% higher than June’s final settlement price average of $56.56/MWh.
  • RGGI Issues September Auction Notice, Intends to Offer Additional Supply to Manage Price Pressure - On 7/14, the states participating in the Regional Greenhouse Gas Initiative (RGGI) issued notice for the next quarterly auction, scheduled to take place on 9/9.  This will be the first auction to include the Virginia allowance allocation since the state formally resumed program participation on 7/1.  A total of 27 million allowances will be offered for sale.  This volume includes more than 9 million allowances above the regularly scheduled offering from the 10 original RGGI participating states: 5.7 million allowances being offered by Virginia and 3.5 million set-aside allowances.  In addition, Virginia will offer 1.15 million cost containment reserve (CCR) allowances, which will be released if the auction interim clearing price exceeds the CCR trigger price of $18.22/ton.  Several participating states expect to offer an additional 2.2 million set-aside allowances in the Q4 auction scheduled for December.  As a result, more than 5.7 million supplemental set-aside allowances are expected to be auctioned during 2026 beyond planned auction volumes.  The participating states currently hold a total of roughly 13 million allowances in set-aside accounts.  These allowances are typically used to support voluntary clean energy purchases, manufacturing and broader industrial programs, combined heat and power, and other programs. 

Great Lakes Electric Summary

  • The Great Lakes Region’s forward power prices were unchanged over the past week as domestic market fundamentals were stable amid cooler temperature forecasts and an ample supply of natural gas.  US natural gas futures fell to $2.73 per MMBtu early Tuesday morning, extending losses to their lowest level in nearly twelve weeks.  US gas prices dropped as gas storage inventories remained at 6.4% above the 5-year average, average gas output in the L-48 states rose to 110.4 Bcf/d so far in July, and LNG send-outs continue to be lower due to maintenance.  A cool front will be moving across the eastern United States this week. The northern tier of the nation is closer to normal, with a few below-normal days mixed into the pattern.  Next week features a broadening ridge that begins to bring above-normal temperatures back across the Midwest to the East Coast as we head into the early part of the 11 to 15-day period.  The forward electricity prices for the 2027-2031 strips, on average, were unchanged over the past week, though 2027 saw a 2% increase.  Over the past month, the entire term saw a 2% increase on average with a 5% increase for 2027.  The month-to-date, day-ahead settlement price in COMED for July is $70.44/MWh or 100% higher than June’s final price, while the AdHub index average is currently $75.60/MWh or 67% higher than June’s final settlement price.  In Michigan, the average settlement price thus far for July is $78.93/MWh or 81% higher than June’s average price, while in Ameren the month-to-date price is averaging $71.48/MWh or 93% higher than last month’s final settlement price.
  • FERC Holds Conference on PJM Governance - On 7/23, FERC held a technical conference to discuss the shortcomings of PJM's governance and stakeholder processes and reforms to improve PJM’s ability to address operational and market needs in a timely and efficient manner.  There was widespread agreement among panelists that PJM needs to act more independently, states need to be more involved at PJM, and PJM, the states, and stakeholders need more alignment on relative priorities along with accountability for timely issue resolution.  Disagreements centered on how independence is defined and measured and how rights are divided between PJM, the states, and stakeholders.  Discussion during the conference was broken into three panels.  The first focused on PJM governance mechanics, including board authority, state roles and responsibilities, and filing rights under Section 205 of the Federal Power Act (which allows tariff changes to be proposed without a threshold demonstration that the existing tariff provisions are flawed).  During the first panel, PJM CEO David Mills argued that PJM itself should be given expanded Section 205 filing rights for energy market and transmission planning changes.  Currently, PJM has Section 205 filing rights over capacity market issues but not energy market issues.  To make a change to the energy market, PJM must obtain stakeholder approval or proceed with the change under Section 206 of the Federal Power Act, which requires PJM to demonstrate that existing rules have become flawed to proceed with the replacement rules.  Mills argued that the lack of Section 205 rights over energy market rules undermines PJM independence and impedes action.  The second and third panels focused on PJM stakeholder-process design, transparency, and decision-making, with many themes carried forward from the first panel.  Other discussion on the afternoon panels addressed PJM stakeholder committee organization, prioritization of workstreams, stakeholder voting rights, and accountability and transparency for PJM’s decisions.

Northeast Energy Summary

  • New England power forwards continue their volatile and upward trajectory as the calendar strips saw gains last week to the tune of nearly 3% for calendar 2027 and 1.5 to 1.75% for calendar 2028-2030. An escalation of military strikes in the Persian Gulf has reaffirmed the Strait of Hormuz's status as (essentially) closed. A widening of the war amongst US allies (Saudi Arabia) against Iran and its allies (Houthis) has put passage in the Rea Sea via the Bab-al Mandab Strait at risk and could further complicate supply chains for Asia demand and keep both global oil and LNG prices further supported. That means elevated New England power contract prices as the link between New England energy and global natural gas and oil prices persist. Back amongst the 6 most Northeastern US states, hot temps on July 14 & 15 yielded only a handful of hours on both days where hourly Day-Ahead index prices ranged from $200 to 260/MWh while peak demand did not approach the YTD unofficial peak from July 2, hour ending 7pm.
  • ISO New England released the 2026 Winter Quarterly Markets Report which focused on the 19-day cold snap from January 23 to February 10 that included Winter Storm Fern.  This was the second longest streak of consecutive cold days since 2010, exceeded only by a 28-day period during the 2015 polar vortex.  Peak load was 20,221 MW, the highest winter peak load since January 2019.  Wholesale electricity costs totaled $6.53 billion ($196/MWh), increasing 45% from Winter 2025 and more than doubling relative to Fall 2025, driven by the highest seasonal energy market costs since the start of Standard Market Design (2003).  Nearly 45% of total energy, ancillary, and uplift costs were incurred during the 19-day cold snap.  New England was a net exporter to other regions for several hours during the height of the cold snap.  In addition, the primary driver behind the large day-ahead and real-time Locational Marginal Pricing deviations observed was due to net interchange differences.  At the New England Clean Energy Connect interface, no import transactions cleared in the day-ahead market until January 28.  By contrast, imports began flowing in the real-time market during most hours starting on the evening of January 26. Higher average loads and reduced net imports compared to previous winters led to increased reliance on natural gas and oil.  During the cold snap, gas and oil prices inverted, and oil generation exceeded gas generation on several days.  Liquefied natural gas (LNG) and oil replenishments were crucial for energy security during the winter.  The New England gas system was reliant on LNG to make pipeline deliveries on roughly 58 days during Winter 2026.  LNG send out reached approximately 45.9 million MMBtu in Winter 2026 (~39% of total gas generation), roughly double the 22.4 million MMBtu of send out in Winter 2025.  Oil was utilized more than in any season since at least Winter 2015.  Many oil generators appeared to respond to opportunity costs associated with burning stored oil by switching to gas or including opportunity costs in their energy market offers. Winter 2026 was the first with the Day-Ahead Ancillary Services (DA A/S) market, which introduced day-ahead procurement and pricing of operating reserves.  DA A/S payments, including both credits and closeout charges, increased substantially between Fall 2025 ($34.1 million) and Winter 2026 ($157.1 million).  However, this increase was largely in line with higher energy costs: net DA A/S payments rose slightly from 2.1% to 2.5% of total E&AS costs. 
  • Recently, the New York State Energy Research and Development Authority (NYSERDA) filed its Offshore Wind Implementation Plan in the Public Service Commission’s (PSC’s) Clean Energy Standard Case 15-E-0302, establishing voluntary sale options for Offshore Wind Renewable Energy Credits (ORECs) at no less than NYSERDA’s net-levelized procurement cost, including any PSC-approved administrative adder.  According to the filed plan, NYSERDA will enter voluntary long-term OREC contracts with creditworthy buyers, with each agreement specifying term, quantity, price, and payment terms.  Separately, NYSERDA will offer an annual 14-day voluntary pre-sale for one-year OREC purchases, announcing available quantities, price, and process by 7/15 each year.  It may also conduct a voluntary OREC re-sale at the end of each compliance year, depending on demand and available supply.  NYSERDA, Long Island Power Authority (LIPA), and the Department of Public Service continue to evaluate LIPA’s participation in the program.  If LIPA participates, NYSERDA would purchase ORECs from LIPA to determine the total OREC obligation for all load serving entities.
  • The New York State Energy Research and Development Authority (NYSERDA) also recently released its updated Strategic Outlook detailing the agency’s near-term implementation priorities as New York continues to pursue its clean energy and reliability objectives amid project delays, federal policy uncertainty, and rising load expectations.  The outlook emphasizes continued Tier 1 renewable energy solicitations, with a focus on advancing contracted projects that can reach commercial operation by 2030 and preserve eligibility for existing federal tax credits.  It also identifies continued development of its Nuclear Master Plan as a key workstream to support New York’s 8.4 GW Nuclear Reliability Backbone.  On storage, NYSERDA plans to procure 3 GW of new bulk energy storage through Index Storage Credit contracts by 2028 as part of the broader goal of deploying 6 GW of total storage by 2030.  The outlook also highlights continued monitoring of annual and seasonal clean energy deliveries from the Champlain Hudson Power Express project into New York City.

ERCOT Energy Summary

CAISO, Desert Southwest and Pacific Northwest Energy Summary

  • California is entering a high-risk stretch marked by the hottest weather the state has seen in two years. As August approaches, according to the National Weather Service (NWS), a major heat wave is expected to build late this week, with triple-digit temperatures spreading across much of the state and the hottest inland locations potentially reaching above 110o. At the same time, the Dove Fire near Sonora has prompted evacuations and underscores how quickly fire conditions can intensify in hot, dry weather. NWS forecasts call for peak heat from August 1-4, with much of the Central Valley likely to see highs from 105 – 113o and the interior Bay Area pushing into the triple digits. NWS is also flagging elevated to high risk for extreme heat in the Central Valley and Sierra Nevadas. Given the warnings, it looks like California is about to experience the first classic summer stress test: hotter weather that drives up electricity demand for cooling, especially during the late afternoon and evening hours, while wildfire conditions increase the risk of service interruptions public safety power shutoff (PSPS) events.
  • NOAA's Climate Prediction Center recently issued an El Niño Advisory, confirming the event "continues and will strengthen through the end of the year, with a 97% chance it will persist through early spring 2027." The NOAA puts the odds of a "very strong" El Niño during October–December at 81% — one it says, "would rank among the largest El Niño events in the historical record going back to 1950.” El Niño does not guarantee a wet winter for California. Since 1950, 13 of 27 El Niño winters brought above-average Bay Area rainfall; SoCal was wetter than normal in 2017. The cautionary tale is 2015–16, the strongest event on record at +2.75°C, billed as a "Godzilla El Niño" yet largely a bust for rain in the state. The wet signal is most reliable across the southern half of the state; NorCal is a transition zone — though for very strong events the relationship extends north to include the Bay Area, Sacramento, and most of the Sierra. A wet winter carries a delayed cost. Abundant rain fuels explosive vegetation growth; once summer heat returns, it becomes fuel. Since January 1, 2026, 3,838 fires have burned 195,439 acres. Fires currently burning: Northern California (14) Southern California (1) as of 7/27@9pm.
  • Heat across California and the interior west this week may cause a repeat of grid conditions seen last week as far as the Desert Southwest is concerned. The overarching story was that the CAISO served as the balancing hub for the Western Interconnection during a series of heat-driven regional stress events. Early last week, extreme heat in the Pacific Northwest pushed Mid-C prices near $100/MWh and caused the region to import power from California, reversing normal transmission flows. Later in the week, heat, reduced solar output, and coal-gen outages in the Desert Southwest forced Arizona/Nevada-area systems to draw power from CAISO rather than export to it. Within California, rising temperatures in both NorCal and SoCal California increased reliance on gas-fired generators and batteries during the evening ramp, while the state's battery fleet repeatedly delivered around 11-12 GW of output, helping contain price volatility and maintain reliability.

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