Category: Energy

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New York imports more electricity from Canada after high-voltage transmission line opens

Source: US Energy Information Administration

In-brief analysis

July 20, 2026

On July 3, 2026, the New York Independent System Operator (NYISO) imported 52 gigawatthours (GWh) of electricity from Canada, the most traded between the two areas since January 2025. Some of the imported electricity flowed along the new Champlain Hudson Power Express (CHPE) transmission line between Québec, Canada, and New York City, which officially reached commercial operations in May after three years of construction.

A strong heat wave drove electricity demand in NYISO up during the first week of July with a maximum hourly load (peak load) of 31,097 megawatts (MW) on July 2 at 7:00 PM. The hourly peak load last summer (June through August) was 31,857 MW on June 24, 2025, at 7:00 PM (the all-time record load of 33,956 MW occurred in July 2013). Canadian imports fulfilled 9% of electricity demand in NYISO on July 3, with a daily average of 1,400 megawatts (MW) per hour coming from Hydro-Québec and 800 MW per hour from the Independent Electric System Operator in Ontario. The new CHPE transmission line connecting Hydro-Québec’s grid and the NYISO grid has a capacity of 1,250 MW, which was fully utilized on July 3.

According to the New York State Energy Research and Development Authority, CHPE is expected to meet up to 20% of New York City’s power demand. Although the transmission line supplied power to New York during the heat wave in July, an outage occurred in June, and the transmission line was taken offline again on July 4 for further repairs.

In recent years, both ISO-New England and NYISO have relied less on electricity imports from Canada as drought conditions have limited hydroelectric generation. However, both regional grids have built high voltage transmission lines connecting hydropower from Québec to their respective regions, which could reverse the trend if hydroelectric generation increases.

Principal contributors: Tyler Hodge, Kimberly Peterson

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Federal Energy Leaders Will Join National Coal Council to Discuss Coal Fleet, Exports, and Future Studies

Source: US Department of Energy

On Tuesday, July 21, U.S. Department of Energy (DOE) leaders including Secretary of Energy Chris Wright, DOE Under Secretary Kyle Haustveit, and DOE Acting Assistant Secretary for the Hydrocarbons and Geothermal Energy Office Curt Coccodrilli will join the National Coal Council (NCC) for its second meeting of 2026. Other federal leaders expected to participate include Secretary of the Interior Doug Burgum, Acting Secretary of Labor Keith Sonderling, EPA Administrator Lee Zeldin, and Deputy Executive Director of the National Energy Dominance Council Blake Deeley.

Originally established in 1984 and recently rechartered by the Department of Energy, the NCC provides advice and recommendations to the Secretary of Energy on general policy matters relating to coal and the coal industry. The advisory process helps provide greater certainty for the industry by supporting stability, optimization, and long-term growth.

A key part of the day’s agenda will be the presentation, discussion, and possible approval of two subcommittee reports: Considerations for Maintaining and Growing the U.S. Coal Fleet and Opportunities to Expand U.S. Coal Export Options. Committee members are also expected to discuss new studies to undertake in the future. 

A Brief History of the National Coal Council

Several developments led to the creation of the NCC in 1984. At the time, there was growing recognition that coal needed a stronger voice in shaping national energy policy. For decades coal was widely viewed as the nation’s most abundant domestic fossil fuel and a critical source of reliable, affordable energy. The Reagan Administration also concluded that the coal industry should have an advisory body comparable to the one that had long served the petroleum industry.

The NCC was intentionally organized to complement the National Petroleum Council, which had long advised the Secretary of Energy on petroleum-related technical issues. The Council was established as a federally chartered advisory committee consistent with the Federal Advisory Committee Act, ensuring that its work would be transparent and conducted in the public interest.

Throughout its history, the Council has positioned itself as providing evidence-based recommendations intended to support national energy security, affordable electricity, and the responsible use of America’s domestic coal resources. Its membership spans the entire coal value chain, including producers, electric utilities, engineers, academics, regulators, and transportation experts.

Continuing to Support the Future of Coal

As the NCC reconvenes on July 21, its members will continue the organization’s longstanding role of providing independent advice and recommendations to the U.S. Secretary of Energy. With its renewed focus on strengthening the domestic coal fleet, expanding export opportunities, and identifying future priorities, the meeting underscores the Council’s ongoing support for the Department of Energy and the Trump administration’s goal of ensuring that coal remains a cornerstone of the nation’s energy mix. Through its recommendations, the Council will help DOE continue to advance policies that promote energy reliability, affordability, economic growth, and the responsible use of America’s abundant coal resources.

The July 21 meeting will be held in person at The Willard Hotel in Washington, D.C. and will also be accessible to the public via livestream. Register here. The Council’s first meeting of the year, held at the White House on January 15, is available to watch on YouTube.

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What are tank bottoms?

Source: US Energy Information Administration

In-brief analysis

July 16, 2026

Data source: Weekly Petroleum Status Report, and Thomson Reuters
Note: WTI=West Texas Intermediate

Crude oil inventories held at storage facilities in Cushing, Oklahoma, fell below 20 million barrels during the week ending June 19 until the week ending July 10, according to our Weekly Petroleum Status Report.

Storage facilities for crude oil and petroleum products require a minimum volume of product in their tanks and pipe infrastructure to remain operational, which can vary between different storage facilities or tank systems. If storage levels fall below their minimum volume, pump suction can become ineffective and storage facilities cannot function. These minimum volumes are sometimes called tank bottoms.

Tank bottoms are a part of what distinguishes working storage capacity from shell capacity. Shell capacity, in general, refers to the total volume of material that might be held in a given storage facility by design. Working storage capacity, on the other hand, refers to the maximum safe fill volume of storage available, minus the tank bottom capacity. EIA is currently reviewing the results of a pilot study to better understand the minimum working inventory levels at select petroleum inventory facilities.

In mid-June when storage at Cushing fell below 20 million barrels, the spot price differential between international benchmark Brent crude oil and U.S. benchmark West Texas Intermediate (WTI) priced at Cushing fell just below $0 dollars per barrel. The five-day rolling average differential became negative from June 18 to June 24, and again from July 2 through July 8. The negative differential occurred as the WTI-Cushing price increased above the Brent spot market price, putting the spread at its lowest point since January 2022. The relatively high WTI-Cushing price suggests that recent low inventory levels may be near tank bottom levels, contributing to extreme tightness for Cushing storage operators and the mid-Continent crude oil market.

Storage facilities must generally operate within their working storage capacity limitations, which prevents inventories of crude oil and other products from truly falling to zero under normal conditions. This means that not every barrel of crude oil or petroleum in inventories is necessarily accessible. In extreme cases, an inventory facility may be unable to provide a product even though it is not technically empty, because it is effectively at the bottom of its working storage capacity.

Principal contributor: Kevin Hack

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Petroleum markets responded to disruptions in the Middle East in the second quarter

Source: US Energy Information Administration

In-brief analysis

July 15, 2026

Data source: Bloomberg L.P.
Note: 2Q26=second quarter of 2026

Petroleum markets in the second quarter of 2026 (2Q26) were characterized by continued disruptions to international crude oil and petroleum product flows through the Strait of Hormuz, contributing to higher and more volatile crude oil prices through most of the quarter. The disruptions also resulted in international buyers seeking alternative supply sources for petroleum products, driving up U.S. refinery margins, production, and exports.

Crude oil prices and inventories

The front-month futures price of Brent crude oil traded in a wide range in 2Q26, reaching a high of $118 per barrel (b) on April 29 and falling to a low of $72/b on June 26.

The price of Brent crude oil began the quarter above $100/b, as disruptions to international crude oil flows through the Strait of Hormuz reduced access to crude oil for much of the world and led many countries in the Middle East to shut in crude oil production. Uncertainty around reopening the Strait of Hormuz to shipping traffic contributed to highly volatile prices in April and May, with an average daily price swing of $4/b in the Brent crude oil price, compared with $1/b in the same months in 2025. From May 18 to June 17, negotiated ceasefires and growing market anticipation for the resumption of shipping traffic through the Strait of Hormuz led the Brent crude oil price to decline by an average of more than $1/b per day (d). On June 17, the United States and Iran signed a Memorandum of Understanding (MOU) that, among other things, sought to resume traffic through the Strait of Hormuz. Following the signing of the MOU and an increase in crude oil tanker movements through the strait, Brent crude oil prices generally declined in the remainder of the quarter. In the first two weeks of the third quarter, prices increased following renewed military strikes and uncertainty over the agreement.

Crude oil prices declined in the second half of the quarter despite large global crude oil inventory draws. In our July Short-Term Energy Outlook, we estimated 2Q26 average global crude oil inventory declines of 5.1 million b/d. Crude oil inventories also declined in the United States, where commercial stocks declined from above the seasonal five-year (2021–2025) average at the beginning of the quarter, to its lowest seasonal level since 2014 at the end of the quarter. Record crude oil exports and high refinery runs were key drivers behind U.S. inventory drawdowns.

Refinery margins

U.S. refineries ran at unseasonally high levels in 2Q26, processing the most crude oil for the quarter since 2019, when refining capacity was 4% higher. High refinery inputs reflected strong margins for transportation fuels. Motor gasoline, distillate, and jet fuel crack spreads—measures of the refinery margins for these fuels—were all elevated, with the quarterly average gasoline crack spread up 60% from the year-ago level, and the distillate and jet fuel crack spreads more than double their year-ago levels as a result of tight international supply.

Data source: Bloomberg L.P.
Note: The crack spreads reflect the New York Harbor spot prices for RBOB, ultra-low sulfur diesel, and jet fuel minus the Dated Brent Spot price.

Petroleum product exports

U.S. distillate and jet fuel exports reached record highs in the second quarter as disruptions to supplies through the Strait of Hormuz also tightened global refined product markets. We estimate 2Q26 distillate exports averaged 1.56 million b/d, 30% higher than the five-year average, and jet fuel exports averaged 356,000 b/d, more than double the five-year average. Compared with 1Q26, U.S. distillate shipments increased to all major export markets, according to data from Vortexa. Jet fuel exports increased substantially to Europe, while remaining about the same to most other destinations.

Higher global demand to replace lost jet fuel volumes led some refiners to shift their refinery yield to maximize jet fuel output for exports. Refiners can adjust product yields in response to changing market conditions by varying refinery processes and the types of crude oil they refine. In the United States, refineries typically optimize production for motor gasoline to meet domestic demand. In 2Q26, we estimate jet fuel production was 24% higher than the five-year average because of higher refinery runs and higher jet fuel yields. Distillate production was 5% higher and motor gasoline production was only 1% higher over the same period.

Principal contributors: Jimmy Troderman, Alexander de Keyserling

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Global liquefied natural gas trade volumes reached record high in 2025

Source: US Energy Information Administration

In-brief analysis

July 14, 2026

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

Global liquefied natural gas (LNG) trade volumes increased 5.4% to a record 56.3 billion cubic feet per day last year (Bcf/d), driven largely by U.S. LNG export capacity expanding to meet growing demand, according to a recent report from the International Group of Liquefied Natural Gas Importers (GIIGNL). Global LNG trade has slowed this year following the closure of the key export route for Qatar, the world’s second-largest LNG exporter.

LNG exports from the United States increased by 26% to 15.1 Bcf/d in 2025, a larger increase than from any other country, according to our Natural Gas Monthly. We forecast U.S. LNG exports will increase further, to 17.4 Bcf/d of LNG in 2026 and 18.6 Bcf/d in 2027 in our Short-Term Energy Outlook.

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

U.S. exports amounted to 26% of the global total in 2025, up from 21% in 2024. The United States, Qatar, and Australia, the three largest LNG exporters globally, made up a combined 63% of global exports, up from 60% in 2024. Canada exported 0.3 Bcf/d of LNG in 2025 after LNG Canada began operations in June.

Qatar reported the second-largest increase in LNG exports, rising 3% to 10.6 Bcf/d in 2025. However, Qatari exports have fallen in 2026 due to the closure of the Strait of Hormuz since February 28, which has cut off approximately 20% of global LNG supplies. Until LNG flows through the strait return to historical norms, Asian buyers, who in 2025 imported over 80% of Qatari volumes, are competing on the global spot market with European buyers seeking to refill storage inventories, which are currently at a deficit to the five-year average.

Some exporters, including Malaysia, Australia, and Norway, reported decreases compared with 2024 due to facility maintenance. Russian LNG exports fell 8% (0.4 Bcf/d) in 2025, the largest volumetric decrease of any exporter, on the impact of EU sanctions stemming from the invasion of Ukraine.

European countries increased imports by 29% (3.8 Bcf/d) in 2025, leading all regions worldwide.

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

Europe’s seven largest importers added between 0.4 Bcf/d and 0.6 Bcf/d of LNG imports each. The expiration of the Ukraine-Russia gas transit agreement at the end of 2024 reduced pipeline gas supplies into Europe and increased LNG import requirements. Imports into Asian countries fell 4% compared with 2024 to 35.7 Bcf/d, largely driven by a 15% (1.5 Bcf/d) reduction in imports to China, which expanded its pipeline gas imports and local production to capture a greater share of its domestic natural gas market.

Elsewhere, Egypt increased imports to 1.2 Bcf/d in 2025 from 0.3 Bcf/d in 2024 as a domestic supply shortage led to an increase in LNG imports. Bahrain and Senegal imported their first LNG cargoes in 2025, each importing less than 0.1 Bcf/d. Outside of these three countries, LNG imports into the Middle East and Africa were essentially unchanged in 2025, while LNG imports in the Americas fell by 0.3 Bcf/d.

Principal contributor: Jordan Young

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Stewardship in Action: Cultural Repatriation and Environmental Cleanup at Elk Hills

Source: US Department of Energy

More than 25 years after the privatization of the Elk Hills Oil Field in California, the U.S. Department of Energy is advancing two important stewardship efforts: cleaning up contamination associated with a historic energy site and returning culturally significant Native American items to Tribal communities.

These efforts reflect DOE’s commitment to responsible stewardship, addressing environmental obligations associated with decades of energy production while ensuring cultural resources are treated with care and respect.

Returning Cultural Items to Tribal Communities

As part of its work at the former Naval Petroleum Reserve No. 1 (NPR-1), DOE is moving forward with the repatriation of Native American cultural items recovered during archaeological investigations conducted around the time the site was privatized in 1998.

The collection, currently curated at California State University, Bakersfield, includes archaeological materials such as stone tools, shell beads, and faunal remains. The items represent an important connection to the history and cultural heritage of Indigenous peoples who lived in and traveled through the region for generations.

In accordance with the Native American Graves Protection and Repatriation Act (NAGPRA), DOE consulted with Tribal governments, including the Tejon Indian Tribe, Tule River Indian Tribe, and the Santa Rosa Rancheria Tachi Yokut Tribe, to determine the appropriate disposition of the materials.

Following consultation and a completed Federal Register notice process, DOE is preparing to return culturally affiliated items to the Tejon Indian Tribe in accordance with federal law.

Cleaning Up a Historic Energy Site

The repatriation effort is part of DOE’s broader remediation work at Elk Hills.

Since the site’s privatization in 1998, the Department has remained responsible for addressing contamination associated with decades of federally managed oil and gas development. Working with the California Department of Toxic Substances Control, DOE is remediating 131 Areas of Concern across the former reserve, including former well pads, waste areas, and tank complexes.

Cleanup progress has been substantial. As of May 2026, DOE has completed cleanup and achieved “No Further Action” determinations at 123 of the 131 sites–more than 90 percent of the identified Areas of Concern.

Cleanup efforts include removing contaminated soils, using soil vapor extraction technology to address subsurface contamination, monitoring soil gas to protect workers and nearby structures, and implementing land-use protections where needed.

DOE is also using more sustainable cleanup approaches. At one location, innovative remediation methods are projected to save more than $8 million while reducing truck traffic and minimizing impacts to surrounding areas.

Advancing Toward Site Closure

DOE continues to coordinate closely with regulators, Tribal Nations, wildlife agencies, and local stakeholders throughout the cleanup process. Public meetings, technical briefings, and ongoing consultation help ensure transparency and collaboration.

The Department is also working to protect taxpayer resources by pursuing cost recovery efforts to help ensure that cleanup responsibilities are shared appropriately. In 2025, DOE secured $29 million from Chevron U.S.A. to cover a proportional share of remediation costs incurred between 2011 and 2024, with additional cost-recovery efforts anticipated as remediation activities continue.

As DOE works toward completing its remediation responsibilities by 2031, the Department remains focused on achieving protective cleanup outcomes, fulfilling its environmental obligations, and working collaboratively with Tribal Nations and regulatory agencies.  Together, these efforts are helping prepare Elk Hills for successful closure while ensuring important environmental and cultural responsibilities are met.

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Secretary of Energy Chris Wright Announces Newly Appointed Members of the Secretary of Energy Advisory Board

Source: US Department of Energy

WASHINGTON—The U.S. Department of Energy (DOE) today announced the newly appointed members of the Secretary of Energy Advisory Board (SEAB), an important component of DOE’s strategy to unleash American energy dominance and ensure continued U.S. leadership in scientific and technological innovation.

SEAB members are appointed for a two-year term and include leaders from research and education, exploration and production, energy financing, artificial intelligence, cybersecurity, and more. The board meets quarterly to advise the Secretary on emerging issues related to DOE’s activities and to provide recommendations for improving the Department’s operations.

“It’s an honor to welcome these exceptional leaders to the Secretary of Energy Advisory Board,” U.S. Secretary of Energy Chris Wright said. “Their diverse backgrounds and expertise will be invaluable as we work together to expand access to affordable, reliable, and secure American energy.”

The appointed members of the SEAB, whose terms expire in May 2028, are listed alphabetically below:

  • John Addison, Former Executive, Vitol 
  • Eimear P. Bonner, CFO, Chevron 
  • Cody Campbell, Co-CEO, Double Eagle Holdings 
  • Joseph W. Craft III, CEO, Alliance Resources Partners 
  • Alex Cranberg, Chairman, Aspect Energy 
  • Bill Fehrman, Chairman of the Board of Directors, President and CEO, American Electric Power 
  • Jack Fusco, Chairman, President and CEO, Cheniere 
  • Tag Greason, Co-CEO, QTS Data Centers 
  • Fisk Johnson, Chairman and CEO, SC Johnson 
  • Doug Kimmelman, Founder and Executive Chairman, Energy Capital Partners 
  • Steve Koonin, Edward Teller Senior Fellow, Stanford University’s Hoover Institution 
  • Maryann Mannen, Chairman, President and CEO, Marathon 
  • Lucian Niemeyer, CEO, Building Cyber Security 
  • Michael Polsky, Founder and Executive Chairman, Invenergy 
  • Mike Rowe, CEO, mikeroweWORKS Foundation 
  • J. Clay Sell, CEO, X-energy 
  • George Solich, President and CEO, FourPoint Energy 
  • Scott Strazik, President and CEO, GE Vernova 
  • Vladimir Troy, VP of AI Infrastructure, NVIDIA 
  • Wil VanLoh, Founder and CEO, Quantum Capital Group 
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The United States produced more crude oil than any other country in 2025

Source: US Energy Information Administration

In-brief analysis

July 9, 2026

The United States remained the world’s largest crude oil producer in 2025, according to our International Energy Statistics database, extending a streak that began in 2018 when the United States overtook Russia to become the world’s leading producer.

Crude oil production in the United States, including lease condensate, averaged a record-high 13.6 million barrels per day (b/d) in 2025, breaking the previous U.S. and global production record of 13.2 million b/d set in 2024. U.S. crude oil production was about 40% higher on average in 2025 than that from the next two largest global crude oil producers, Russia and Saudi Arabia.

U.S. crude oil production has been buoyed by continued gains in drilling productivity and operational efficiency across key shale basins, which allow operators to extract more oil per well. The growth in output continued in 2025 despite lower oil prices; West Texas Intermediate (WTI) prices dropped from an average of $77/b in 2024 to $65/b in 2025 amid global oversupply. Production growth was particularly strong in the Permian Basin of Texas and New Mexico, which had a 4% increase in crude oil production, from 6.3 million b/d in 2024 to 6.6 million b/d in 2025. The Permian accounted for approximately 48% of U.S. production in 2025.

Shale oil and gas development in the United States became notable when in 2008 it reversed a multi-decade decline in U.S. crude oil production. U.S. crude oil production powered by shale development has turned the United States into not just the world’s largest producer, but the largest producer of crude oil ever.

The difference between the United States and other major producers widened in 2025, with Russian output largely unchanged and Saudi Arabia recording modest growth as a result of OPEC+ unwinding voluntary production cuts. Crude oil production including lease condensate in Saudi Arabia increased from 9.2 million b/d in 2024 to 9.6 million b/d in 2025. Russia’s crude oil production averaged 9.9 million b/d in 2024 and remained largely unchanged in 2025 as a combination of voluntary production cuts and effects of the conflict with Ukraine limited crude oil output growth.

Looking ahead, we forecast U.S. crude oil production will remain near 13.7 million b/d in 2026, before increasing to 14.2 million b/d in 2027 based on our latest Short-Term Energy Outlook. Production growth comes amid rising prices as WTI prices increase by $22/b to $88/b in 2026. In addition to the WTI price increase, continued shale well productivity improvements will also drive growth.

Parallel to the growth in crude oil production, U.S. associated natural gas production has also surged, driven by activity in oil-dominant plays like the Permian. This abundance of associated gas has continued to support domestic natural gas-fired electricity generation and growing natural gas exports. In 2024, the most recent year data are available, the United States was the world’s largest natural gas producer. We will release 2025 natural gas production data in our International Energy Statistics database later this year.

Principal contributors: Naser Ameen, Troy Cook

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Energy Department Closes Loan to AEP Texas, Delivering Millions in Electricity Cost Savings for Texans

Source: US Department of Energy

WASHINGTON—The U.S. Department of Energy’s (DOE) Office of Energy Dominance Financing (EDF) today announced it has closed a loan up to $3.26 billion to AEP Texas to lower electricity costs and strengthen and modernize the Texas grid. Thanks to President Trump’s Working Families Tax Cuts Act, the investment will save more than one million Texas households and businesses approximately $685 million in electricity costs over the next 30 years, improve grid reliability, create thousands of jobs, and help ensure Americans have access to affordable, reliable, and secure energy.

“President Trump’s Working Families Tax Cuts Act is driving investments that strengthen America’s energy infrastructure while lowering costs for hardworking families,” said U.S. Energy Secretary Chris Wright. “This investment will modernize Texas’ electric grid, support the energy needed for AI, advanced manufacturing, the Permian Basin, and help keep electricity costs down for Texans.” 

In accordance with President Trump’s Executive Order, Unleashing American Energy, the loan will finance approximately 100 transmission projects across Texas, including rebuilding or reconductoring existing transmission lines, and constructing new transmission infrastructure spanning roughly 2,800 miles. 

These projects will double the power-carrying capacity of upgraded transmission infrastructure, reduce power interruptions, and connect new sources of reliable baseload generation to the grid. By expanding transmission capacity, the projects will help meet rapidly growing electricity demand from data centers, advanced manufacturing, and oil and natural gas development in the Permian Basin. 

This loan marks the Trump Administration’s third concurrent conditional commitment and financial close, and the third utility financing completed through the Energy Dominance Financing Program.  

Under President Trump’s leadership, EDF is committed to financing American energy and manufacturing projects that meaningfully contribute to U.S. energy security, grid reliability, and lowering costs for all Americans. EDF empowers the private sector to invest in the future, win the AI race, strengthen American industry, and restore American Energy Dominance.  

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U.S. exports of crude oil and petroleum products reached record in April

Source: US Energy Information Administration

In-brief analysis

July 8, 2026

U.S. petroleum exports reached a record in April as disruptions to international crude oil and refined product flows through the Strait of Hormuz increased global demand for U.S. exports. Exports increased to 13.6 million barrels per day (b/d) in April, 15% more than the previous record set in March.

Crude oil exports made up the largest share of total petroleum exports, averaging 5.6 million b/d in April, 21% more than the previous record set in December 2023. Propane made up the second-largest share, with exports exceeding the 2.0 million b/d mark for the first time in monthly data, and distillate fuel oil made up the third-largest share, increasing to 1.6 million b/d, the most since July 2017.

U.S. exports of finished petroleum products—which is mostly made up of distillate fuel oil, motor gasoline, jet fuel, and petroleum coke—were the highest since December 2024, despite relatively average exports of motor gasoline.

Exports for other products including jet fuel, unfinished oils, and naphtha reached record highs in March and remained high in April but slightly below their record levels.

Our more recent weekly estimates suggest crude oil, distillate fuel, jet fuel, and propane exports remained above five-year (2021–2025) seasonal highs in May and June.

Principal contributor: Jimmy Troderman