Category: US Energy Information Administration

Source: US Energy Information Administration

A publication of recent and historical U.S. energy statistics. This publication includes total energy production, consumption, stocks, and trade; energy prices; overviews of petroleum, natural gas, coal, electricity, nuclear energy, renewable energy, and carbon dioxide emissions; and data unit conversions values.

Data categories

Expand all Collapse all

Source: US Energy Information Administration

September 26, 2023

Data source: Kpler tanker tracking data (accessed August 2023)

Kuwait’s oil exports are shifting from crude oil to refined petroleum products following the addition of new refining capacity, according to data in our recently updated Country Analysis Brief: Kuwait. In June and July 2023, Kuwait exported more than 1 million barrels per day (b/d) of petroleum products and liquified petroleum gas, the highest volume of products the country has exported. By contrast, crude oil exports averaged about 1.6 million b/d in June and July, down from an average of 1.8 million b/d in the same period of 2022.

As of July 2023, refineries in Kuwait had the capacity to process 1.4 million b/d of crude oil, more than double the refinery capacity in January 2021 of 600,000 b/d. The increase in capacity comes from the new Al Zour refinery and an expansion project at existing refineries over the past two years. Kuwait’s new Al Zour refinery is the Middle East’s largest with a capacity of 615,000 b/d among three units. The plant’s first crude oil distillation unit came on line in November 2022, followed by the second in March 2023 and the third in July 2023. The Al Zour refinery can produce significant amounts of low-sulfur fuel oil, around 220,000 b/d at full capacity.

In late 2021, national refining company Kuwait National Petroleum Corp. (KNPC) completed its Clean Fuels Project (CFP). The CFP upgraded and integrated the company’s Mina Al-Ahmadi and Mina Abdullah refineries to be able to process petroleum products with low levels of sulfur and nitrogen oxide. The upgrade allowed production of fuels that meet the Euro 4 and 5 standards for products with lower emissions. The CFP increased Kuwait’s crude oil refining capacity by around 60,000 b/d.

Kuwait’s crude oil exports fell from an average of 1.9 million b/d in 2022 to less than 1.8 million b/d for the first 7 months of 2023. By July 2023, crude oil exports dipped to 1.5 million b/d, according to Kpler tanker tracking service.

Data source: Kpler tanker tracking data (accessed August 2023)

In July 2023, Asia remained the top destination for Kuwait’s petroleum product exports, receiving 46%. However, Europe received 29% in July 2023, up significantly from 2021. In July 2021, Europe received 11% of Kuwait’s petroleum product exports. Increased exports to Europe resulted from Europe’s ban on imports from Russia as EU countries look to replace diesel and other products that they used to receive from Russia.

Principal contributors: Candace Dunn, Kimberly Peterson

Source: US Energy Information Administration

September 25, 2023

Data source: Bloomberg L.P.
Note: The figure is based on the five-day moving average of the price spread between Dated Brent and Dubai Fateh.

Crude oil production cuts among OPEC+ members are limiting the global supply of medium, sour and heavy, sour grades of crude oil. These cuts are increasing prices for these grades compared with sweet crude oils, reversing typical price relationships.

Crude oil is classified into categories based on the oil’s density (light, medium, or heavy) and sulfur content (sweet or sour). Light, sweet crude oils typically trade at a premium compared with any sour crude oil because sweet crude oils cost less to refine and produce higher yields of more valuable products.

Medium, sour Dubai Fateh (an Asia-Middle East benchmark), however, recently traded at a premium to light, sweet Dated Brent (a global benchmark). Dated Brent traded at an average premium of $2.56 per barrel (b) compared with Dubai Fateh between January 4, 2021, and June 20, 2023. However, between June 21 and September 19, the roles reversed, and Dubai Fateh traded at an average premium of $0.48/b compared with Dated Brent. Trade press reports similar movement in the price of Norway’s Johan Sverdrup—a medium, sour crude oil—as refiners offer increased prices to attract constrained supply.

In North America, the spread between the price of medium, sour Mars crude oil and the light, sweet Magellan East Houston (MEH) has declined since late 2022, and Mars sold at a small premium briefly in July 2023. The price of MEH reflects the price of light, sweet crude oil at the Enterprise ECHO terminal in Houston, Texas. The spread between Mars and MEH has increased over the past few weeks, although it is still lower than earlier this year.

In June 2023, OPEC+ members announced they would extend crude oil production cuts through 2024, limiting global crude oil supplies, particularly sour crude oils. On top of the OPEC+ production cuts, Saudi Arabia announced it would reduce crude oil production by an additional 1 million barrels per day (b/d) for July. These additional voluntary production cuts were extended several times, and Saudi Arabia announced on September 5 that it would extend them through the end of 2023. In our September Short-Term Energy Outlook, we estimate that OPEC crude oil production averaged 27.0 million b/d in August, the lowest since August 2021, and crude oil production in Saudi Arabia averaged 8.7 million b/d, the lowest since May 2021.

Most of Saudi Arabia’s crude oil contains more than 1% sulfur, our threshold for classifying crude oil as sour, and production cuts have put more upward price pressure on sour barrels than sweet. Saudi Arabia also increased the official selling price (OSP) of Arab Light (a medium, sour crude oil) to Asia and Europe, further pushing up sour crude oil prices. As a result, sweet and sour crude oil price spreads have narrowed in most major trading hubs, including those in North America, Europe, and the Middle East.

The extent and duration of the current market dynamics, with sour crude oil prices trading unusually high, remain uncertain against a backdrop of production cuts, higher OSPs, and heightened demand for sour crude oil as several new Middle East refineries come online.

Principal contributor: Matthew French

Source: US Energy Information Administration

September 21, 2023

Hydropower has played a key and growing role in Ecuador’s electricity mix by displacing fossil fuels and helping meet higher domestic electricity demand. In 2011, hydroelectric power accounted for 55% of the country’s electricity mix, and electricity from fossil fuels accounted for 43%. In 2021, hydropower produced 79% of Ecuador’s electricity, and fossil fuels produced less than 20%.

Ecuador’s mountainous terrain and numerous rivers are conducive for hydropower. The Coca Codo Sinclair Hydroelectric Plant, located on the Coca River, is Ecuador’s largest hydroelectric facility with 1,500 megawatts (MW) of capacity. The plant went into full operation in 2016 and is critical to meeting the country’s electricity demand. Since its commissioning, the hydroelectric plant has been undergoing repairs because of erosion from the Coca River, and it has run into complications that prevent it from operating at full capacity.

Because of its reliance on hydropower, Ecuador’s electricity sector is vulnerable to droughts and low water levels during the dry season from October to March. To supplement hydropower, Ecuador relies on oil-fired power plants for generation. The government is committed to converting old oil-fired power plants to natural gas. Although natural gas-fired generation has the potential to become a stable complement to drought- and erosion-prone hydropower, Ecuador’s lack of domestic natural gas supplies prevents natural gas capacity expansion in the short term. In 2022, Ecuador imported 2 million cubic feet of liquefied natural gas (LNG). The cargo from Panama was Ecuador’s first import of LNG in its history. The imported volume was used to replace 14,000 gallons of diesel for industrial processes, according to Ecuador’s government.

Aside from hydropower and fossil fuel-fired generation, Ecuador’s remaining electricity in 2021 was generated by non-hydro renewables, including wind, solar, and biomass. The use of wind, solar, and biomass for electric power generation in Ecuador is still in the early stages. In 2021, wind farms accounted for 0.2% of total electricity generation, solar accounted for 0.1%, and biomass accounted for 1.3%. In Ecuador, biomass is primarily produced from sugar cane, African palm, and rice husks.

Ecuador’s government released the Electricity Master Plan 2019, which outlines a series of planned projects to meet the country’s electricity demand and encourage private investment. In 2021, Ecuador had 5.3 gigawatts (GW) of renewable energy capacity. The plan’s goals include adding approximately 1.4 GW of new renewable energy capacity to the national grid by 2031.

To help realize that goal, the government is offering a 100% income tax exemption for certain new investments in renewable energy. Planned projects include two new wind farms (Villonaco II & III) with a combined capacity of 165 MW in Loja, Ecuador. In southern Ecuador, the planned 200 MW El Aromo solar farm will be Ecuador’s largest solar project once completed.

The country’s largest-capacity operating wind farm, Huascachaca Wind Farm, came online in 2023. The 50 MW onshore wind farm is expected to generate about 130 gigawatthours of electricity per year.

You can find more information about Ecuador’s energy sector in our recently updated Country Analysis Brief: Ecuador.

Principal contributor: Matias Arnal

Source: US Energy Information Administration



U.S. petroleum products exports set new record in the first half of 2023

U.S. exports of petroleum products grew 2% to nearly 6.0 million barrels per day (b/d) in the first half of 2023 (1H2023) compared to the same period in 2022, the most first-half-of-the-year exports in our Petroleum Supply Monthly data, which date back to 1981 (Figure 1). Exports of propane and other hydrocarbon gas liquids (HGLs) drove the increase, as exports of other major petroleum products such as motor gasoline, distillate fuel oil, and jet fuel all decreased compared with 1H22. Export growth in the first half of 2023 was lower than growth in the first half of 2022, when exports quickly rose to meet increased demand in Europe after the region took measures to reduce imports from Russia. U.S. exports of crude oil also continued to increase in 1H23, rising to 4.0 million b/d, 19% higher than 1H22.

U.S. propane exports averaged 1.5 million b/d in the first half of 2023, an 8% increase (119,000 b/d) from 1H22 (Figure 2). Propane was the most-exported U.S. petroleum product in 1H23, continuing a trend that began in 2020, making propane the primary driver of overall higher U.S. petroleum product exports so far this year. U.S. exports of propane and other HGLs to Asia, where they are primarily consumed as feedstock in the petrochemical industry, have grown rapidly in recent years. These increased exports to Asian markets distinguish propane from other major U.S. refined product exports such as distillate and gasoline, which mostly flow to destinations in the Americas. About 59% of U.S. propane exports went to Asia in 1H23, mostly to Japan, China, and South Korea, matching the historical trend of previous years. Propane exports to destinations in Europe decreased compared with 1H22, as did propane exports to destinations in Central and South America. Other HGL exports were also a significant driver of export growth in 1H23, increasing by 9% (85,000 b/d) compared with 1H22.

The United States exported 1.1 million b/d of distillate fuel oil in 1H23, a 5% (51,000 b/d) decrease from the same time last year, led by lower exports to destinations in Central and South America (Figure 3). Despite the decrease, Central and South America combined remains the largest destination for U.S. distillate, accounting for 57% of all U.S. distillate exports. The United States also exported less distillate to Canada and the Asia and Oceania region compared with 1H22.

Despite lower total distillate exports, distillate exports to Europe increased in 1H23 compared with 1H22, following the EU’s complete import ban on Russia’s petroleum products from the beginning of 2023. U.S. distillate fuel oil exports to destinations in Europe averaged 138,000 b/d in 1H23 compared to 56,000 b/d in the 1H22. Distillate exports to Mexico also increased, and among individual countries, the largest recipients of U.S. distillate exports were Mexico, Chile, Ecuador, Panama, and Peru. The UK and the Netherlands were the largest destination countries for U.S. distillate exports into Europe.

The increase in distillate exports to Europe even as exports to other destinations declined partially reflects rerouted trade flows in response to sanctions on petroleum product imports from Russia. Exports to Europe from the United States are replacing distillate supplies that previously came from Russia, which now lack market access in Europe and therefore are being exported to destinations further abroad. In particular, Brazil has reportedly been a significant destination for distillate from Russia, while the country’s distillate imports from the United States are lower compared with last year.

U.S. exports of gasoline in 1H23 were 4% (32,000 b/d) lower than in 1H22. Gasoline exports to Mexico, which accounted for 56% of total gasoline exports in the first half of the year, also fell by 4%. After Mexico, the largest destinations for U.S. gasoline exports so far this year include Guatemala, Canada, Chile, and Peru. Gasoline exports to Central and South America increased in 1H23 compared with 1H22, while exports to Canada and Europe were both lower than in 1H22. At 859,000 b/d, 1H23 exports of gasoline are lower than exports of distillate fuel oil, propane, or other HGLs.

Although our Short-Term Energy Outlook (STEO) does not forecast gross U.S. petroleum product exports, our forecast of net petroleum product exports—equal to total exports minus total imports—from our September 2023 STEO expects lower annual average net exports of distillate and gasoline in 2023, but higher net exports of HGLs (Figure 4). We currently estimate 2023 net exports of distillate to decline by 41,000 b/d compared with 2022, and we expect net exports of gasoline to decrease by 112,000 b/d. We estimate total HGL net exports—including propane—will increase on an annual average basis this year by 227,000 b/d as historical trends of increasing production and export capacity continue to underpin growth in HGL exports. In 2024, we expect net exports of all three products to increase, with HGLs up 128,000 b/d, distillate up 77,000 b/d, and total gasoline up 75,000 b/d.

For questions about This Week in Petroleum, contact the Petroleum and Liquid Fuels Markets Team at 202-586-5840.

Source: US Energy Information Administration

U.S. ENERGY INFORMATION ADMINISTRATION
WASHINGTON DC 20585

FOR IMMEDIATE RELEASE
September 20, 2023

Source: US Energy Information Administration

Source: US Energy Information Administration

The survey Form EIA-860 collects generator-level specific information about existing and planned generators and associated environmental equipment at electric power plants with 1 megawatt or greater of combined nameplate capacity. Summary level data can be found in the Electric Power Annual.

Starting with 2013 data, the EIA-860 began collecting construction cost data for new electric generators. Aggregated average construction cost information can be found on the Construction cost data for electric generators page.

Detailed data are compressed (zip) and contain the following files:

• LayoutYyyyy– Provides a directory of all (published) data elements collected on the Form EIA-860 together with the related description, specific file location(s), and, where appropriate, an explanation of codes.
• 1___UtilityYyyyy – Contains utility-level data for the plants and generators surveyed in the reporting year.
• 2___PlantYyyyy – Contains plant-level data for the generators surveyed in all available years.
• 3_1_GeneratorYyyyy – Contains generator-level data for the surveyed generators, split into three tabs.
  • The Operable tab includes those generators which are currently operating, out of service or on standby;
  • The Proposed tab includes those generators which are planned and not yet in operation; and
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
  • The retired tab only includes those retired generators which were reported in the most current data cycle. This is not a comprehensive list. Starting with March 2017 data, Preliminary Monthly Electric Generator Inventory includes a comprehensive list of generators which retired since 2002. The list can be found on the Retired tab of the data file.
• 3_2_WindYyyyy – Contains additional details for surveyed generators that use wind as an energy source, split into two tabs:
• The Operable tab includes those generators which are currently operating, out of service or on standby; and
• The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_3_SolarYyyyy – Contains additional details for surveyed generators that use solar as an energy source, split into two tabs:
• The Operable tab includes those generators which are currently operating, out of service or on standby;
• The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_4_Energy_StorageYyyyy – Contains additional details of surveyed generators for the energy storage technology, split into two tabs:
• The Operable tab includes those generators which are currently operating, out of service or on standby;
• The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_5_MultiFuelYyyyy – Contains data on fuel-switching and the use of multiple fuels by surveyed generators, split into three tabs:
• The Operable tab includes those generators which are currently operating, out of service or on standby; and
• The Proposed tab includes those generators which are planned and not yet in operation; and
• The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 4___OwnerYyyyy – Contains owner and/or operator data for generators with shared ownership and generators that are wholly-owned by an entity other than the operator (generators not appearing in the file are wholly-owned by their operator).
• 6_1_EnviroAssocYyyyy – Contains boiler association data for the environmental equipment data collected on the Form EIA-860.
  • The Boiler Generator identifies which boilers are associated with each generator;
  • The Boiler Cooling tab shows which cooling systems are associated with each boiler;
  • The Boiler Particulate Matter tab shows which flue gas particulate (FGP) collectors are associated with each boiler;
  • The Boiler SO2 tab shows which flue gas desulfurization (FGD) systems are associated with each boiler
  • The Boiler NOx tab shows which nitrogen oxide control equipment is associated with each boiler;
  • The Boiler Mercury tab shows which mercury control equipment is associated with each boiler
  • The Boiler Stack Flue tab shows which stacks and flues are associated with each boiler; and
  • The Emissions Control Equipment tab shows the operational status, in-service date, and installation costs of all the environmental equipment.
• 6_2_EnviroEquipYyyyy – Contains environmental equipment data for the surveyed generators.
  • The Emission Standards & Strategies tab shows boiler data as collected on Schedule 6, Part B of the Form EIA-860;
  • The Boiler Info & Design Parameters tab shows boiler data as collected on Schedule 6, Part C;
  • The Cooling tab shows cooling system data as collected on Schedule 6, Part D;
  • The FGP tab shows FGP data as collected on Schedule 6, Part E;
  • The FGD tab shows FGD data as collected on Schedule 6, Part F; and
  • The StackFlue tab shows stack and flue data as collected on Schedule 6, Part G.

Superseded Form EIA-860A (Utility) & B (Non-Utility) — Retired Annual Electric Generator Report

Electric utility generator level data includes information for company, facility, unit type, prime mover, in-service date, energy source, heat content, nameplate capacity, summer and winter capability, etc.

860-A (Utility)
Data are compressed into a zip file that expands into xls data files and a txt layout file:

• PLANTYyy – plant-level data
• UTILYyy – utility-level data
• TYPE3Yyy & TYPE4Yyy – 2 generator files for 1990-1997
  or GeneratorOwnershipyyyy, ProposedGeneratorsyyyy, ExistingGeneratorsyyyy – 3 generator files for 1998-2000
• LAYOUT – ASCII layout file

860-B (Non-Utility)
Data are compressed into a zip file that expands into xls data files and a txt layout file:

• qfdocket – qualifying data
• xdocket – plant-level data
• cogen – cogeneration data
• nuppfac – non-utility power producer data
• fuelquant – fuel quantities
• genergy – 2 generator files
• generator
• noxequip – nox removal data
• LAYOUT – ASCII layout file

Superseded forms (for data prior to 2001)
    EIA-860 A (utility) and B (nonutility)

Source: US Energy Information Administration

September 19, 2023

Monthly average natural gas wholesale spot prices at the U.S. benchmark Henry Hub have been generally declining so far in 2023, but these relatively low prices do not immediately translate into lower retail prices for residential consumers. Changes in retail natural gas prices lag changes in wholesale natural gas prices, largely due to the nature of utility regulation. Over longer periods, changes in natural gas wholesale and retail prices are more closely correlated.

Residential consumer prices for natural gas have two major components: costs incurred to buy wholesale natural gas and the related transportation and distribution charges. Because the fixed costs are spread over the smaller volumes used by customers in warm weather, residential natural gas prices are usually highest in the summer and lowest in the winter on a per unit basis when all charges are combined.

Local distribution companies (LDCs). LDCs are the utility companies that serve residential, commercial, industrial, and electric power customers. They purchase natural gas from the wholesale market to deliver to those customers. LDCs often buy natural gas months ahead of when customers need it to limit exposure to near-term price volatility and ensure adequate supplies. As a result, the natural gas price an LDC pays can reflect the price for natural gas purchased in previous periods. LDCs also work to secure guaranteed transportation on pipelines and reserve storage capacity to help limit price risk and ensure supply.

Public utility commission (PUC). The state PUC regulates residential natural gas prices. Rate changes may lag changes in the LDC’s costs of purchasing natural gas due to the requirements set by state PUCs. Because companies regulated by PUCs as utilities—including most residential natural gas sales in the United States—are generally not allowed to earn or lose money from natural gas commodity sales, PUCs require LDCs to adjust these rates at some regular interval through purchased gas adjustment (PGA) charges included in utility bills.

How often LDCs are required to calculate their PGAs can vary from state to state and from company to company. In general, in times of stable prices, the frequency of these calculations can range from annually to as often as monthly. In periods of high spot price volatility, such as the record volatility in 2022, many PUCs allow LDCs to file motions to make more frequent adjustments. This flexibility allows utility natural gas cost changes to be reflected in smaller increments rather than all at once.

Additional charges. In some cases, such as during an extreme weather event, LDCs will request the ability to add additional charges to utility bills. For example, natural gas spot prices approached record highs following Winter Storm Uri in February 2021, especially in the Midwest. Many LDCs in states affected by the storm filed motions with their states’ PUCs detailing plans to recover the extremely high natural gas costs they had incurred following the winter storm. The goal of these plans was to spread the high natural gas costs to consumers over several years.

Principal contributor: Corrina Ricker

Source: US Energy Information Administration

September 2021 Supplement: Gas-to-oil ratios in U.S. primary oil-producing regions.
January 2021 Supplement: Base production in North Dakota has fully recovered after a significant reduction.
September 2020 Supplement: With low rig counts, the inventory of drilled but uncompleted (DUC) wells provides short-term reserve for completions of new wells.
August 2020 Supplement: Rig counts fall but new-well production per rig rise as new-well production persists.
March 2020 Supplement: Base production accounts for a material share of total U.S. tight oil production.