Category: US Energy Information Administration

Source: US Energy Information Administration

+ Administrator’s Foreword

The global energy system is governed by complex dynamics that play out over time across regions and sectors of the economy. Projected increases in population and incomes drive our expectation of rising energy demand through 2050.

• The global energy system is governed by complex dynamics that play out over time across regions and sectors of the economy. Projected increases in population and incomes drive our expectation of rising energy demand through 2050. However, we expect the increased energy demand to be moderated by reduced energy intensity: less energy will be required for each unit of economic activity. In addition, we expect reduced carbon intensity—largely driven by the wide-scale deployment of renewables for electricity generation—which will help limit global CO2 emissions associated with what will be record -high energy demand. Our International Energy Outlook 2023 (IEO2023) explains our findings and showcases key regional and sectoral variations. We use EIA’s detailed World Energy Projection System to produce IEO2023, giving our readers a unique view into future global energy systems.

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+ Executive Summary

Since our last IEO two years ago, IEO2021, the global energy system has evolved against a backdrop of new energy policies, the transition to zero-carbon technologies, energy security concerns, and economic and population growth.

• The International Energy Outlook 2023 (IEO2023) explores long-term energy trends across the world through 2050. Since our last IEO two years ago, IEO2021, the global energy system has evolved against a backdrop of new energy policies, the transition to zero-carbon technologies, energy security concerns, and economic and population growth. While IEO2023 includes several cases to capture important drivers of change, the modeled cases represent a set of policy neutral baselines that place emphasis on the current trajectory of the global energy system.

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+ Introduction

The International Energy Outlook 2023 (IEO2023) explores long-term energy trends across the world through 2050. We explore three key findings in separate sections of this report, each containing a series of in-depth explanations that include region- and sector-specific insights across modeled cases.

• The International Energy Outlook 2023 (IEO2023) explores long-term energy trends across the world through 2050. We explore three key findings in separate sections of this report, each containing a series of in-depth explanations that include region- and sector-specific insights across modeled cases. IEO2023 includes a series of cases that reflect different assumptions related to macroeconomic growth, technology costs, and fuel prices, although the future remains significantly uncertain.

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Source: US Energy Information Administration

October 11, 2023

Data source: U.S. Energy Information Administration, International Energy Outlook 2023 (IEO2023)

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In our International Energy Outlook 2023 (IEO2023), we project that global energy-related CO₂ emissions will increase by 2050 in a number of IEO2023 cases as global population growth and higher living standards push growth in energy consumption beyond advances in energy efficiency.

In all IEO2023 cases, we expect global primary energy consumption to increase through 2050. Our expectations of global population growth, increased regional manufacturing, and higher living standards indicate that global energy consumption will grow faster than advances in energy efficiency. Non-fossil fuel-based resources, including nuclear and renewables, produce more energy through 2050, but in most of the IEO2023 cases we examined, that growth is not sufficient to reduce global energy-related CO₂ emissions under current laws and regulations.

In our IEO2023, we explore long-term world energy trends and present an outlook for energy markets through 2050. We use different scenarios, called cases, to understand how varying assumptions about technological advancement and economic growth affect energy trends. The IEO2023 Reference case—which serves as a baseline, or benchmark—and six side cases consider only the laws and regulations adopted through March 2023. The six side cases in IEO2023 explore differing assumptions of economic growth, crude oil prices, and technology costs.

U.S. projections in IEO2023 are the published projections in the Annual Energy Outlook 2023 (AEO2023), which assumed that U.S. laws and regulations as of November 2022 remain unchanged.

Some key takeaways from our IEO2023 include:

Increasing population and income offset the effects of declining energy and carbon intensity on emissions.
In all IEO2023 cases, global energy consumption increases, with the fastest growth in the residential and industrial sectors. Global consumption of liquid fuels increases through 2050, and industrial applications, such as chemical production, account for the fastest growth in liquid fuels consumption. Economic growth and increased disposable income increase demand for transportation in all IEO2023 cases. Although electric vehicles gain a larger share of the global transportation fleet, reducing transportation sector petroleum consumption, the industrial sector offsets those declines as its share of petroleum and other liquid fuels consumption rises.

The shift to renewables to meet growing electricity demand is driven by regional resources, technology costs, and policy.
Across IEO2023 cases, global electric-power generating capacity increases by a range of 50% to 100%, and electricity generation increases by 30% to 76% by 2050, depending on the IEO2023 case. Zero-carbon technologies account for most of the growth in both global capacity and generation. Electricity generation from renewables and nuclear could provide as much as two-thirds of global electricity generation by 2050, according to the projections. Battery storage capacity grows significantly in all IEO2023 cases, increasing from less than 1% of global power capacity in 2022 to a range of 4% to 9% of global power capacity by 2050, depending on the case.

Energy security concerns hasten a transition from fossil fuels in some countries, although they drive increased fossil fuel consumption in others.
Energy trade of fossil fuels will continue to evolve as emerging economies demand more energy and the world continues to adapt to current geopolitical events. In nearly all IEO2023 cases, energy production from zero-carbon technologies grows faster than from fossil fuels, but that dynamic varies from region to region. The Middle East and North America increase natural gas production and exports to meet growing demand, and Western Europe and Asia remain natural gas importers in all IEO2023 cases. Energy demand from China, India, Southeast Asia, and Africa will motivate major crude oil and natural gas producers to keep producing.

Principal contributor: Michelle Bowman

Source: US Energy Information Administration

U.S. ENERGY INFORMATION ADMINISTRATION
WASHINGTON DC 20585

FOR IMMEDIATE RELEASE
October 11, 2023

The U.S. Energy Information Administration (EIA) projects that global energy consumption and associated CO₂ emissions will increase through 2050 (assuming the global energy system remains on its current trajectory and absent new policy). Global population growth, increased regional manufacturing, and higher living standards push growth in energy consumption beyond advances in energy efficiency, according to EIA’s projections in its International Energy Outlook 2023 (IEO2023).

In IEO2023, EIA projects that global energy-related CO₂ emissions will increase through 2050 in most of the cases modeled. Although EIA expects zero-carbon technology—renewables and nuclear—will meet the bulk of new energy demand through 2050, that growth is not sufficient to decrease global energy-related CO₂ emissions in most cases under current laws and regulations, according to EIA’s projections.

“IEO2023 fills an important niche among global outlooks by focusing on a plausible but sober assessment of global energy trends through the first half of the century,” said EIA Administrator Joe DeCarolis. “There is considerable uncertainty in the energy landscape over the next 30 years, and the IEO provides a set of policy neutral baselines that will help guide sound decision-making.”

EIA’s projections assume no new laws and regulations, although they include side cases that account for varying levels of economic growth, oil prices, and zero-carbon technology costs.

Below are three main takeaways from EIA’s IEO2023 projections, followed by key sector-specific highlights.

Increasing population and income offset the effects of declining energy and carbon intensity on emissions.
Across all cases explored in IEO2023, global energy consumption increases, with the fastest growth in the residential and industrial sectors. Global consumption of liquid fuels increases through 2050, with the fastest growth occurring in industrial applications such as chemical production.

Economic growth and increased disposable income also increase demand for transportation in all cases.

“The transportation and industrial sectors are major consumers of liquid fuels throughout our projection period, but as electric vehicles grow to become a larger part of the global transportation fleet, the industrial sector accounts for an increasing share of petroleum and other liquid fuels consumption,” DeCarolis said.

The shift to renewables to meet growing electricity demand is driven by regional resources, technology costs, and policy.
Compared with 2022, global electric power generating capacity increases by somewhere between 55% and 108% by 2050, depending on the case. Electricity generation increases between 30% to 76% over that period. Renewables, nuclear, and battery storage account for most of the growth in both global capacity and generation.

Electricity generation from renewables and nuclear could increase by between 54% and 67%, according to EIA’s projections.

“Renewables become an increasingly cost-competitive source of electricity and grow the fastest in cases that assume high economic growth and greater electricity demand,” DeCarolis said.

Global battery storage capacity grows significantly in all IEO2023 cases. In 2022, battery storage accounted for less than 1% of global power capacity. EIA projects that battery storage capacity will grow to make up between 4% and 9% of global power capacity by 2050.

Energy security concerns hasten a transition from fossil fuels in some countries, although they drive increased fossil fuel consumption in others.
In nearly all IEO2023 cases, growth in energy production from non-fossil fuel sources outpaces growth in fossil fuels, but that dynamic varies from region to region. In Western Europe and China, policy, rapid demand growth, and energy security considerations favor locally available resources such as wind, solar, and battery storage, prompting more of these types of installations early in the projection period. Regions with access to relatively affordable coal, such as the Other Asia-Pacific region, consume more coal.

Natural gas and crude oil supply, consumption, and trade patterns evolve in our projections to meet growing demand against the backdrop of Russia’s full-scale invasion of Ukraine, which we assume will continue to limit Russia’s exports to Western markets. The Middle East and North America increase natural gas production and exports to meet growing demand, particularly in China, India, Southeast Asia, and Africa.

“Across the cases we modeled, energy demand from China, India, Southeast Asia, and Africa will continue to support growth in global natural gas production,” DeCarolis said.

Projections for the United States in IEO2023 are consistent with those released in the Annual Energy Outlook 2023. EIA does not develop the IEO2023 Reference case as the most probable prediction of the future but rather as a baseline for estimating the effects of policy or technology changes. The side cases show the effects of changing key model assumptions about economic growth, capital costs for zero-carbon technologies, and world oil price.

The product described in this press release was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy. By law, EIA’s data, analysis, and forecasts are independent of approval by any other officer or employee of the U.S. government. The views in the product and this press release therefore should not be construed as representing those of the U.S. Department of Energy or other federal agencies.

EIA Press Contact: Chris Higginbotham, EIAMedia@eia.gov

Source: US Energy Information Administration

October 10, 2023

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U.S. crude oil exports in the first half of 2023 averaged 3.99 million barrels per day (b/d), which is a record high for the first half of a year since 2015, when the U.S. ban on most crude oil exports from the United States was repealed. In the first half of 2023, crude oil exports were up 650,000 b/d (19%) compared with the first half of 2022.

Europe was the largest regional destination for U.S. crude oil exports by volume, at 1.75 million b/d, led by exports to the Netherlands and UK. Asia was the regional destination with the next-highest volume, at 1.68 million b/d, led by exports to China and South Korea. The United States also exported significantly smaller volumes of crude oil to Canada, Africa, and Central America and South America.

Although exports increased in the first half of 2023, the United States still imports more crude oil than it exports, meaning it remains a net crude oil importer. The United States continues to import crude oil despite rising domestic crude oil production in part because many U.S. refineries are configured to process heavy, sour crude oil (with a low API gravity and high sulfur content) rather than the light, sweet crude oil (with a high API gravity and low sulfur content) typically produced in the United States.

U.S. crude oil imports come primarily from historical trading partners such as Mexico and Canada. Heavy, sour grades of crude oil are often discounted compared with light, sweet grades of crude oil because they require more complex refinery units to produce profitable yields of refined products such as motor gasoline, diesel, and jet fuel. Most U.S. crude oil imports take place when it is more profitable for U.S. refiners to process discounted heavier grades because those refineries have already invested in the additional complexity required to refine them.

The rapid increase in U.S. domestic production in the early 2010s increased domestic light, sweet crude oil production. Light, sweet grades of crude oil traditionally benefit from a price premium in the global crude oil market because they yield high amounts of profitable petroleum products from less complex refining processes.

Some U.S. refiners on the Gulf Coast have invested in expanding their light, sweet crude oil processing capacity. However, for many refiners, particularly in the Midwest and along the Gulf Coast, refining discounted heavy, sour crude oil grades remains more profitable.

Principal contributor: Kevin Hack

Source: US Energy Information Administration

U.S. ENERGY INFORMATION ADMINISTRATION
WASHINGTON DC 20585

FOR IMMEDIATE RELEASE
October 5, 2023

The U.S. Energy Information Administration (EIA) will release its International Energy Outlook 2023 (IEO2023) at a virtual and in-person public event hosted by the Center for Strategic and International Studies (CSIS). The IEO2023 presents long-term projections of world energy supply and demand. The IEO2023 models projections of energy markets through 2050 and explores a variety of different assumptions about economic growth, world oil prices, and technological innovation. The event will feature a presentation of the IEO2023 projections by EIA Administrator Joe DeCarolis and EIA Assistant Administrator for Energy Analysis Angelina LaRose. Following these presentations, Director of the CSIS Energy Security and Climate Change Program Joseph Majkut will sit down with Dr. DeCarolis for an armchair discussion on IEO2023’s highlights and key assumptions and how the IEO can be helpful in informing policymakers. Members of the press and general public can register to attend the event through the CSIS website. You can also join the conversation on social media using #IEO2023. More information about the International Energy Outlook is available at EIA.gov.
What:	International Energy Outlook 2023 discussion of projections
When:	Wednesday, October 11, 2023, at 9:30 a.m. eastern time
Where:	Virtual and in-person event hosted by the Center for Strategic and International Studies
Who:	Joe DeCarolis, Administrator, EIA Joseph Majkut, Director of the Energy Security and Climate Change Program, CSIS Angelina LaRose, Assistant Administrator for Energy Analysis, EIA
Register:	https://www.csis.org/events/us-eias-international-energy-outlook-2023
EIA Press Contact: Chris Higginbotham, Chris.Higginbotham@eia.gov

Source: US Energy Information Administration

Form EIA-861, Annual Electric Power Industry Report, and Form EIA-861S (the shortform) collect data from distribution utilities and power marketers of electricity. This survey is a census of all United States electric utilities. The short form is intended for smaller bundled-service utilities and has less detailed responses. This survey collects more data than the monthly counterpart, Form EIA-861M. Data are the individual surveys responses and are included in the files described below.

Our survey page contains the current survey form, instructions, respondent portal, and frequently asked questions. Data from these files can be found throughout our publications, usually in aggregated form in our Electric Power Annual (EPA) report; State Electricity Profiles (SEP); Electric Sales, Revenue, and Average Price (ESR) report; Electricity Data Browser; and in some Today in Energy articles.

Please refer to our Guide to EIA Electric Power Data and send any questions to InfoElectric@eia.gov.

In 2012, we created Form EIA-861S to reduce respondent burden and to increase our processing efficiency; that year, about 1,100 utilities initially reported on this form instead of Form EIA-861. In 2020, the number of utilities increased to about 1,700 utilities. We reformatted the files for the years 1990–2011, but we didn’t change or update any data files. We reformatted the files to make them easier to understand and to match the format and titles of the current files.

Frame

Surveys: Form EIA-861 and Form EIA-861S

Time frame: 2016 to present

Description: The data contain a complete list of all respondents from both forms and which files they have data in.

Advanced Metering

Surveys: Form EIA-861 and Form EIA-861S

Time frame: 2007 to present

Description: The data contain number of meters from automated meter readings (AMR) and advanced metering infrastructure (AMI) by state, sector, and balancing authority. The energy served (in megawatthours) for AMI systems is provided. Form EIA-861 respondents also report the number of standard meters (non AMR/AMI) in their system.

Historical Changes: We started collecting the number of standard meters in 2013. The monthly survey collected these data from January 2011 to January 2017.

Balancing Authority

Surveys: Form EIA-861 and Form EIA-861

Time frame: 2012 to present

Description: The data contain the list of balancing authorities and the states they operate in.

Delivery Companies

Survey: Form EIA-861

Time frame: 2020 to present

Description: The data contain revenue, sales, and customer count by sector from utilities that deliver energy in Texas.

Demand Response

Survey: Form EIA-861

Time frame: 2013 to present

Description: The data contain energy demand response programs by state, sector, and balancing authority. We collect data for the number of customers enrolled, energy savings, potential and actual peak savings, and associated costs.

Distribution Systems

Survey: Form EIA-861

Time frame: 2013 to present

Description: The data contain the number of distribution circuits and circuits with voltage optimization by state.

Dynamic Pricing

Survey: Form EIA-861

Time frame: 2013 to present

Description: The data contain the number of customers enrolled in dynamic pricing programs by state, sector, and balancing authority. Respondents check if one or more customers are enrolled in time-of-use pricing, real time pricing, variable peak pricing, critical peak pricing, and critical peak rebates.

Energy Efficiency

Survey: Form EIA-861

Time frame: 2013 to present

Description: The data contain incremental energy savings, peak demand savings, weighted average life cycle, and associated costs for the reporting year and life cycle of energy efficiency programs.

Mergers

Survey: Form EIA-861

Time frame: 2007 to present

Description: The data contain information on mergers and acquisitions.

Net Metering

Survey: Form EIA-861

Time frame: 2001 to present

Description: The data contain cumulative installation count and capacity of generators that are net metered by technology, state, sector, and balancing authority. If available, the energy sold back to the grid is also reported. Technology types include photovoltaic (standard, virtual less than 1 megawatt, and virtual 1 megawatt or greater), wind, and other. Storage systems that are paired with net-metered photovoltaic (PV) are also captured. We make a state-level adjustment for missing PV capacity and to convert state total capacity to AC units for those respondents who report data in DC units; we use 0.8256 as a conversion factor to change DC to AC. For other energy sources, we have not established imputation procedures.

Historical Changes: Initially, data contained only the customer count. In 2007, energy displaced was added (later renamed to energy sold back). We added capacity of systems in 2010, and we divided this category by technology type: PV, wind, and other. In 2016, we added a question to the survey about whether the megawatts reported for the PV systems were in AC or DC units). Also in 2016, the survey divided PV to include virtual systems and storage systems paired with PV. Starting in 2020, Form EIA-861S respondents were imputed.

Non-Net Metering Distributed

Survey: Form EIA-861

Time frame: 2010 to present

Description: The data contain cumulative values of generators that are not net metered and are under 1 megawatt in size (and not reported on Form EIA-860). Installations, total capacity, capacity owned, and capacity backup are reported in aggregate by state, sector, and balancing authority. Capacity is also reported by technology, state, sector, and balancing authority. Technology types include combustion turbine, internal combustion engine, fuel cells, hydroelectric, photovoltaic (PV), steam turbine, storage, wind, and other.

Form EIA-861S respondents do not provide non-net-metering distributed data. A state-level adjustment is made for missing PV capacity and to convert state total capacity to AC units for those respondents who report data in DC units; we use 0.8256 as a conversion factor to change DC to AC, which uses the responses from the net-metering schedule. For other energy sources, we have not established imputation procedures.

Historical Changes: This schedule was referred to as distributed generation, and we renamed it to prevent double counting from net-metered systems (2016). Data on dispersed systems (systems not connected to the grid) were collected up to 2015. In 2016, we added data on fuel cells. Starting in 2016, these data were broken out by sector, and an adjustment to convert state total capacity to AC units for those respondents who report data in DC units; we use 0.8256 as a conversion factor to change DC to AC. Starting in 2020, Form EIA-861S respondents were estimated.

Operational Data

Survey: Form EIA-861

Time frame: 1990 to present

Description: The data contain aggregate operational data for the source and disposition of energy and revenue information from each electric utility.

Reliability

Survey: Form EIA-861

Time frame: 2013 to present

Description:The data contain information on non-momentary electrical interruptions. If collected, utilities report the system average interruption duration index (SAIDI), the system average interruption frequency index (SAIFI), and the conditions under which these metrics are collected. We allow respondents to use IEEE standards or any other method. We created a short video to describe what is collected.

Sales to Ultimate Customers

Surveys: Form EIA-861 and Form EIA-861S

Time frame: 1990 to present

Description: The data contain revenue, sales (in megawatthours), and customer count of electricity delivered to end-use customers by state, sector, and balancing authority.

A state, service type, and balancing authority-level adjustment is made for non-respondents and for customer-sited respondents.

Historical Changes: In 2003, we created the transportation sector and removed the other sector. We made this change to separate the transportation sales and reassign the other activities to the commercial and industrial sectors as appropriate. Non-transportation customers previously reported under other, including street and highway lighting, are now included in the commercial sector. Previously, we referred to this file as retail sales.

Sales to Ultimate Customers, Customer-Sited

Survey: Form EIA-923

Time frame: 2002 to present

Description: The data contain revenue, sales (in megawatthours), and customer count of electricity delivered to end-use customers by state, sector, and balancing authority. These data aren’t collected on Form EIA-861; however, they are included in the state adjustments totals in the sales to ultimate customers file.

Service Territory

Surveys: Form EIA-861 and Form EIA-861S

Time frame: 2001 to present

Description: The data contain names of counties and states in which the utility has equipment to distribute electricity to ultimate customers.

Short Form

Surveys: Form EIA-861 and Form EIA-861S

Time frame: 2001 to present

Description: The data contain revenue, sales (in megawatthours), and customer count of electricity delivered to end-use customers, by state and balancing authority. Respondents answer whether they have net metering, demand side management, and time-based programs.

Utility Data

Survey: Form EIA-861

Time frame: 1990 to present

Description:The data contain information on a utility’s North American Electric Reliability (NERC) regions of operation. The data also indicate a utility’s independent system operator (ISO) or regional transmission organization (RTO) and whether that utility is engaged in any of the following activities: generation, transmission, buying transmission, distribution, buying distribution, wholesale marketing, retail marketing, bundled service, or operating alternative-fueled vehicles.

Historical Changes: In 2010, we added the independent system operator (ISO) and regional transmission organization (RTO) regions.

Demand-Side Management (DSM)

Survey: Form EIA-861

Time frame: 2001 to 2012

Description: The data contain energy efficiency incremental data, energy efficiency annual data, load management incremental data, load management annual data, annual costs, and the customer counts of price response and time response programs by sector.

Historical Changes: In 2007, we added the customer counts of price response and time response programs.

Green Pricing

Survey: Form EIA-861

Time frame: 2001 to 2012

Description: The data contain revenue, sales, and customer count by sector and state.
Historical Changes: Initially, data contained only the customer count. In 2007, revenue and sales were added.

Contact: Electricity data experts

Source: US Energy Information Administration

October 5, 2023

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On July 27, 2023, peak hourly electricity demand in the continental United States reached 741,815 megawatthours (MWh). This peak was the second highest since we began collecting this data in 2016, just under the all-time high of 742,704 MWh recorded on July 20, 2022.

Weather is a large driver of electricity demand, especially in summer months when homes and businesses use electricity for air conditioning. Peak hourly electricity demand in the United States typically occurs in either July or August when demand for space cooling is the highest.

National peak hourly demand can mask regional grid strains because the continental U.S. electric grid operates as three separate electric interconnections with little connectivity to each other: the Eastern, Western, and Texas Interconnections. These systems can be affected by individual weather patterns or resource availability that both create differences in the timing and intensity of when demand is the highest.

For example, last summer, temperature differences among the three regions led to differences in the timing and intensity of peak demand as well the ability of grid operators within each region to meet demand. Because hot weather was concentrated in Texas and the western United States, the electric systems in those areas of the country strained to meet higher demand.

Texas. The Electric Reliability Council of Texas (ERCOT), the grid operator for most of the state, broke all-time peak hourly demand records over the summer as extreme heat settled in the region for most of July and August. The extreme heat led to hourly wholesale electricity prices in excess of $4,000/MWh and to ERCOT issuing appeals for consumer electricity conservation for several days in August.

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A combination of continued high temperatures into September and lower wind and solar output in the evening led ERCOT to declare an Energy Emergency Alert (EEA) Stage 2 on September 6, 2023. An EEA Stage 2 is the last step before a grid operator is forced to enter rotating outages to ensure grid stability.

Western Interconnection. Grid strain can occur at times when system demand is high but not necessarily the highest hour of the year. In the western United States, widespread heat in late July caused the California Independent System Operator (CAISO), the grid operator for most of the state, to call an Energy Emergency Alert Stage 1 on July 20, 2023. CAISO, unlike ERCOT, relies heavily on imported electricity from neighboring regions. However, widespread heat can limit the ability of neighboring systems to share resources when capacity is needed to meet load within their own systems.

An EEA Stage 1 is called when real-time forecasts expect energy deficiencies. Forecasts for high temperatures on July 20 across the Western Interconnection elevated demand in the California, Southwest, and Northwest regions (the three regions that make up the U.S. portion of the Western Interconnection). However sufficient resources were available to meet demand within California on that day without declaring additional staged emergencies or shedding load.

The actual peak hour of this year in the Western Interconnection occurred on August 17, 2023, when demand across the three regions reached 137,370 MWh. Grid operators were able to meet demand without entering into emergency conditions.

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Eastern Interconnection. In the Eastern Interconnection, the largest of the three interconnection regions, hourly demand peaked on July 27, 2023, at 529,147 MWh, the same day that demand peaked for the continental United States. Peak demand was also high for a few days in August when hot weather moved through the Central United States and into the East Coast. PJM and MISO, the two largest system operators in the Eastern Interconnection, declared hot weather alerts in August but did not need to enter emergency conditions. High temperatures in early September also increased peak demand in New York and New England, but again, the system operators did not need to enter emergency conditions.

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Principal contributor: M. Tyson Brown

Source: US Energy Information Administration



Publicly traded U.S. oil companies increase investing activities and crude oil production

Publicly-trade U.S. oil companies increased spending on capital expenditures and mergers and acquisitions in the second quarter of 2023 (2Q23), according to financial results from 40 publicly traded exploration and production (E&P) companies, at a time when cash from operations fell. Because cash from operations declined, the E&P companies supported investing activities in 2Q23 by reducing shareholder returns by 39% compared with the 2022 quarterly average and increasing net debt by $5.6 billion. Crude oil and natural gas liquids (NGL) production by these E&P companies increased to an average of 6.3 million barrels per day (b/d), nearly equal to the pre-pandemic high in 1Q20.

We base our analysis on the published financial reports of 40 publicly traded oil companies that produce most of their crude oil in the United States. As a result, our observations do not represent the entire sector because we exclude private companies, which do not publish financial reports. These 40 publicly traded companies collectively accounted for 33% of all crude oil and NGL produced in the United States in 2Q23.

Although crude oil prices and cash from operations declined in 2Q23, E&P company capital expenditure and crude oil production both increased to their highest levels in the past three years. The West Texas Intermediate (WTI) crude oil price averaged $73.49 per barrel (b) in 2Q23, 33% ($35.44/b) less than the same quarter last year. Lower crude oil prices contributed to cash from operations declining 38% ($14.1 billion) from 2Q22 to $23.1 billion in 2Q23 (Figure 1). Capital expenditure, which historically decreases with falling crude oil prices, has been less sensitive to WTI price changes over this period: capital expenditure of $17.6 billion in 2Q23 was 37% ($4.8 billion) higher than in 2Q22. Higher capital expenditure supported crude oil production increasing 11% (421,000 b/d) from 2Q22 to 4.1 million b/d in 2Q23.

Reduced investment spending in 2021 and increased cash from operations in 2022 contributed to increased cash reserves and debt repayments that brought total debt below pre-pandemic levels. In recent quarters, E&P companies have allocated more resources toward investing activities. In 2Q23, the ratio of investing activities to cash from operations increased to 95%, higher than the 2000–23 median value of 83% (Figure 2). Some of the increased investing activity has been directed toward asset acquisitions, including:

These and other M&A deals, such as those by ExxonMobil and Chevron, reflect a trend toward fewer publicly traded E&P companies operating in the United States, resulting in larger companies that own more producing assets.

One result of increased capital expenditure is more drilled and completed wells, which U.S. producers have been keeping mostly balanced. Responding to the 2020 global oil demand contraction, E&P companies kept their costs low by drilling fewer new wells and relying more on drilled but uncompleted wells (DUCs) to maintain production levels (Figure 3). According to our Drilling Productivity Report (DPR), between August 2020 and December 2021, the net decline in DUCs averaged 214 per month, which raised a concern a low DUC count could limit crude oil production growth if the number of drilled wells per month remained low. However, increased capital expenditure has supported increased drilling activity enough to slow the net decline in DUCs, which averaged 44 in the last 18 months. The continuing decline in DUCs suggests E&P companies are still sensitive to higher-than-normal production costs and are adjusting their operations to mitigate those higher production costs, although companies have reduced the likelihood that they will run into operational constraints by improving the balance between drilled and completed wells.

Increased production by the E&P companies underlies a broader trend of publicly traded companies increasing their share of total U.S. crude oil and NGL production. As liquid fuels markets started to recover in 2020, production from private companies grew more quickly than from publicly traded companies, resulting in private companies producing a larger share of crude oil and NGL. In recent quarters, publicly traded companies have reduced the gap and maintained production at a level effectively equal to private companies since 3Q22 (Figure 4). We totaled U.S. field production of crude oil and NGL from our Petroleum Supply Monthly and compared it with the U.S. production from all publicly traded companies—88 companies as of 2Q23, including those that have much of their production outside the United States—to estimate private company production for the past five years. In 2Q23, U.S. crude oil and NGL production from publicly traded companies was 3% higher than their collective 2019 quarterly average, and production from private companies was 22% above their 2019 quarterly average.

Higher forecast U.S. crude oil production and the drivers behind the forecast suggest capital expenditure by E&P companies will increase in the coming quarters. In our September Short-Term Energy Outlook, we forecast U.S. crude oil production will average 12.8 million b/d in 2023 and 13.2 million b/d in 2024 (Figure 5). If realized, these totals would be record highs for U.S. production. Following production cuts by Saudi Arabia and other OPEC+ members, we expect WTI crude oil prices to remain above $80/b through the end of 2024 and for the United States to be a major driver of global crude oil production growth. These factors support continued production growth for E&P companies.

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

Source: US Energy Information Administration

October 4, 2023

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The United States exported more natural gas in the first half of 2023 (1H23) than it did in the same period of any previous year. Natural gas exports averaged 20.4 billion cubic feet per day (Bcf/d), 4% (0.8 Bcf/d) more than in 1H22, according to our Natural Gas Monthly.

Liquefied natural gas (LNG) exports largely drove the continued growth in total natural gas exports, although natural gas exports by pipeline also increased. The United States began exporting LNG from the Lower 48 states in 2016 when Sabine Pass LNG—the first LNG export terminal in the Lower 48 states—came online.

The United States became a net natural gas exporter (natural gas exports exceeded natural gas imports) in 2017 for the first time since 1957. In May 2023, U.S. net natural gas exports as LNG and by pipeline averaged a monthly record of 13.6 Bcf/d.

LNG exports. In 1H23, U.S. LNG exports averaged 11.6 Bcf/d, making the United States the world’s top LNG exporting country. U.S. LNG exports in 1H23 increased 4% (0.5 Bcf/d) compared with the same period in 2022, despite declining in May and June.

Exports by pipeline. In 1H23, U.S. natural gas pipeline exports to Canada and Mexico increased 4% (0.3 Bcf/d) compared with 1H22, averaging 8.8 Bcf/d. Net natural gas exports by pipeline, particularly to Mexico, contributed to record-high natural gas exports. U.S. natural gas exports by pipeline to Mexico reached a monthly high of 6.8 Bcf/d in June and accounted for about 66% of total U.S. pipeline exports from January through June.

Mexico increased natural gas imports from the United States in 1H23 to meet electric power sector demand, which has been increasing since 2018. Since 2019, natural gas pipeline exports from West Texas to Mexico have grown steadily as more connecting pipelines in Central and Southwest Mexico have been placed in service.

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Although the United States is a net natural gas exporter, it still imports natural gas, largely by pipeline.

Imports by pipeline. U.S. natural gas imports by pipeline, which are primarily from Canada, declined by 5% (0.4 Bcf/d) in 1H23 compared with 1H22, to 7.9 Bcf/d. Imports from Canada help support seasonal fluctuations in natural gas consumption in the United States and generally peak in January or February, with a smaller peak in the summer months. A mild winter, combined with wildfires in Western Canada that disrupted natural gas deliveries to the United States this spring, contributed to lower natural gas imports in 1H23 compared with 1H22.

LNG imports. U.S. LNG imports averaged less than 0.1 Bcf/d in 1H23. Almost all LNG imports are delivered to the New England market, where imports can be a key marginal source of natural gas supply during periods of high demand, particularly in the winter months. Warmer-than-average temperatures in the Northeast in the first quarter of 2023 contributed to lower LNG imports compared with the same time in 2022.

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Principal contributor: Katy Fleury

Source: US Energy Information Administration

The Annual Coal Report (ACR) provides annual data on U.S. coal production, number of mines, productive capacity, recoverable reserves, employment, productivity, consumption, stocks, and prices. All data for 2022 and previous years are final.

Highlights for 2022

• U.S. coal production increased 2.9% year over year to 594.2 million short tons (MMst).
• The total productive capacity of U.S. coal mines was 872 MMst, an increase of 0.1% from 2021.
• The average number of employees at U.S. coal mines increased by 4,064 from 2021 to 43,582 employees.
• U.S. coal mining productivity, as measured by average production per employee hour, decreased 8.9% from 2021 to 6.11 short tons per employee hour.
• U.S. coal consumption decreased 5.5% from 2021 to 515.5 MMst. The electric power sector accounted for about 91.7% of the total U.S. coal consumed in 2022.
• The average sales price of bituminous coal was $97.96 per short ton, a 58.8% increase from 2021. The average sales price of subbituminous coal was $16.55 per short ton, a 16.7% increase from 2021. The average sales price of thermal coal increased by 33.7% from 2021 to $34.57 per short ton. The average sales price of metallurgical coal increased 72.9% from 2021 to $262.72 per short ton.
• Total U.S. coal stocks in 2022 ended the year at 114.3 MMst, 1.2% lower than at the same time in 2021. Electric power coal stocks decreased by 3.1 MMst to 89.2 MMst at the end of 2022.