This report is a product of the staff of the Federal Energy Regulatory Commission (Commission or FERC). 

The opinions and views expressed in this report represent the analysis of the Commission staff. 

This report does not necessarily reflect the views of the Commission, its Chairman, or individual Commissioners, 

and is not binding on the Commission.

March 21, 2024

Staff Report

State of the Markets

2023

FEDERAL ENERGY REGULATORY COMMISSION

Office of Energy Policy and Innovation

DEPARTMENT OF ENERGY

F E D E R A L E N E R G Y R E G U L AT O RY C O M M I S S I O N
2023 STATE OF THE MARKET n 1

PREFACE

The Federal Energy Regulatory Commission Staff in the Office of Energy Policy and Innovation annually publishes 

the State of the Markets report to update the Commission, industry, and the public on recent market conditions 

and emerging issues in natural gas and electricity markets within the Commission’s jurisdiction. This year’s report 

is structured differently than previous reports, with significant market trends and fundamentals for the year 2023 

presented first and underlying data presented in an Energy Fundamentals Almanac at the end of the report. This year’s 

report also describes emerging issues in electricity and natural gas markets, including transforming market structures 

and transforming electricity and natural gas infrastructure. 
2 n 2023 STATE OF THE MARKET 

KEY MARKET FUNDAMENTALS

1. EIA, U.S. Henry Hub natural gas prices in 2023 were the lowest since mid-2020 (Jan. 4, 2024), https://www.eia.gov/todayinenergy/detail.php?id=61183.

2. Higher crude oil prices can incent increased oil production, which can increase natural gas production from wells that produce both oil and natural gas.

Executive Summary. This report finds that U.S. energy markets in 2023 remained responsive to fundamentals of 

supply and demand, with market forces driving infrastructure investment and commodity prices. 

Although natural gas demand increased, primarily for purposes of power generation and exports, record natural 

gas production caused prices to decline from 2022 levels at all major U.S. hubs. Wholesale electricity prices also 

declined at most hubs over the year, partly due to lower natural gas prices. Hot summer temperatures contributed 

to higher electricity consumption in the Electric Reliability Council of Texas (ERCOT), Midcontinent Independent 

System Operator (MISO), and Southwest Power Pool (SPP) compared to the ten-year average electricity consumption 

in each region. Also in 2023, more electric generating capacity was added than was retired, with most retirements 

coming from coal resources and most new capacity coming from solar resources. At the same time, the number of 

active generator interconnection requests in queues across the country grew, extending a multi-year trend. Electric 

transmission developers responded to the need for new capacity, completing work on over 500 projects and nearly 

4,500 circuit miles that entered service in 2023. 

Natural Gas Market Fundamentals. Prices at major natural gas hubs declined year-over-year in 2023, in contrast with the 

year-over-year price increases seen at most hubs in 2022 as shown in Figure 1. According to the U.S. Energy Information 

Administration (EIA),1

 record-high natural gas production outpacing growth in natural gas consumption was the primary 

driver of lower prices in 2023. Growing oil production, most significantly in the Permian region, driven by improved welllevel productivity and higher crude oil prices in 2023, resulted in increased natural gas production.2

 Mild temperatures in 

the U.S. Midwest and Northeast in January and February 2023 — the peak of heating season — led to reduced natural gas 

consumption in the residential and commercial sectors and, in turn, to lower withdrawals of natural gas from storage. 

Natural gas storage in 2023 remained at levels above the previous year and previous five-year average, despite lower 

injections. Increased exports and a slight increase in natural gas consumed for electricity generation (power burn) offset 

lower residential and commercial sector consumption and contributed to a net increase in natural gas demand.

As shown in Figure 1, the benchmark price at Henry Hub averaged $2.53 per million British thermal units (MMBtu) in 

2023, a significant decline (60%) from an average of $6.38/MMBtu in 2022. Regionally, prices spiked at several major 

natural gas trading hubs. Two California hubs, SoCal Gas Citygate outside Los Angeles and PG&E Citygate near the Bay 

Area, saw relatively high prices in January 2023 due to a confluence of events that began in late 2022 – gas pipeline 

outages, elevated heating demand, widespread cold weather, and low storage levels in western states. Both hubs 

traded as high as $26/MMBtu in the first two weeks of the year. In New England, the combination of a cold snap on 

February 3 and 4, 2023, which increased residential and commercial space heating demand, and pipeline constraints 

caused prices to reach $66.37/MMBtu at Algonquin Citygates, a trading hub located in the Boston metropolitan area. 

Prices at trading hubs in New England and California leveled off later in the year, eventually settling at averages for 

2023 that were lower than in 2022.
2023 STATE OF THE MARKET n 3

Figure 1: Average Natural Gas Spot Prices at Major Trading Hubs

–

$2

$4

$6

$8

$10

$12

$/MMBtu

Algonquin 

c.g.

Transco 

Z6 N.Y.

Eastern 

Gas-S

Chicago 

c.g.

NGPL Waha Henry Hub

Midcon

NWP

Rockies

PG&E 

c.g.

SoCal 

Gas c.g.

2021 2022 2023

Source: S&P Global Commodity Insights.

3. The total liquefaction capacity excludes the Kenai LNG export terminal in Alaska because it has not exported LNG since 2015 and received Commission authorization to build an 

import facility. See Reuters, Marathon Gets More Time to Build LNG Import Project in Alaska (Aug. 16, 2022), https://www.reuters.com/business/energy/marathon-gets-more-timebuild-lng-import-project-alaska-2022-08-16/. By the end of 2023, the available FERC-authorized export liquefaction capacity was 14.2 Bcfd; however available FERC-authorized 

export liquefaction capacity varied in 2023 with the 2.4 Bcfd Freeport export terminal coming fully back online on Mar. 8, 2023, and the addition of Venture Global’s Calcasieu Pass 

0.6 Bcfd Units 7-9 in Oct. 2023. See FERC, North American LNG Export Terminals – Existing, Approved not Yet Built, and Proposed (Dec. 31, 2023),

In 2023, demand for natural gas in the United States exceeded 100 billion cubic feet per day (Bcfd) on average for 

the first time, while domestic consumption of natural gas grew for the second straight year. Power burn – the largest 

component of U.S. natural gas demand – reached a new annual average high of 35.4 Bcfd, representing a 7% yearover-year increase as lower natural gas prices and coal power plant retirements drove higher levels of electricity 

generation from natural gas resources. Net exports of natural gas increased 21% from 2022 and represented 12.7% of 

total U.S. natural gas demand in 2023. Gross liquefied natural gas (LNG) exports and gross pipeline exports to Mexico 

and Canada grew in 2023, contributing to the growth in natural gas net exports. The United States remained a major 

net importer of natural gas from Canada. Daily average U.S. LNG exports increased by 1.3 Bcfd to 11.9 Bcfd in 2023 

according to EIA monthly data. This increase was in part because additional FERC-authorized export liquefaction 

capacity increased from 11.2 Bcfd to 14.2 Bcfd during the year.3

 The seven jurisdictional export facilities primarily 

supplied markets in Europe, followed by Asia. 

Regarding natural gas infrastructure, the growth of LNG exports has supported pipeline construction in recent years 

in the South-Central region, which spans from Kansas to Texas and Mississippi. More than 43% of the pipeline 

capacity additions in the last five years are located in or connected to the South-Central region, and are largely 

designed to provide feedstock to LNG export terminals. In 2023, 0.98 Bcfd of interstate pipeline capacity went into 

service according to EIA’s pipeline project database, the lowest amount of annual capacity additions on record. The 

Commission certificated for construction and operation new projects totaling 11.5 Bcfd of additional pipeline capacity 

in 2023.
4 n 2023 STATE OF THE MARKET 

4. Net additions equal installed capacity entering service less installed capacity exiting service. Net capacity is based on installed capacity, not accredited capacity, available capacity, 

or energy production.

Figure 2: Nameplate Capacity Net Additions and Retirements from 2013 to 2023 by Resource Type 

Nameplate Capacity, GW

(NYISO & ISO-NE Only)

0

10

20

30

40

50

Entries Exits Entries Exits Entries Exits Entries Exits Entries Exits Entries Exits Entries Exits

0

1

2

3

4

5

Entries Exits Entries Exits

Nuclear Coal Natural Gas Hydro Solar Wind Oil Batteries Other

Nameplate Capacity, GW

CAISO WECC* ERCOT SPP MISO PJM SERC NYISO ISO-NE

Source: EIA Form 860M, February 2024 Release. Data exclude Alaska and Hawaii. WECC* refers to WECC without CAISO.

Electricity Market Fundamentals. The nation’s generation resource mix continued to change in 2023 consistent 

with longer-term industry trends shown in Figure 2, in which most nameplate capacity additions came from solar, 

wind, and natural gas resources and most retirements came from coal resources. Installed nameplate capacity is 

growing overall in the United States with 26 gigawatts (GW) of net additions since 2022 and 110 GW since 2013.4

 Solar 

was the primary resource type added in 2023. At 18 GW, solar capacity additions were more than double the amount 

of capacity added by wind, natural gas, or battery resources, which each ranged between 6 and 9 GW for the year. 

Nevertheless, in terms of installed capacity, natural gas remained the primary resource type at the end of the year 

at 45% of the capacity mix, followed by coal at 15%, wind at 12%, nuclear at 8%, hydro at 8%, solar at 7%, oil at 2%, 

other at 2%, and batteries at 1%. Figure 2 shows that since 2013, natural gas-fired capacity has declined only in the 

California Independent System Operator (CAISO) and SPP regions.

Newer technologies such as battery storage and offshore wind reached new milestones in 2023 and nuclear capacity 

increased for the first time in seven years. Battery storage capacity additions rose to 6.1 GW in 2023, nearly 50% more 

than the amount added in 2022 and 10 times the amount added in 2020. The deployment of battery storage has been 

geographically uneven, with most additions in the ERCOT and the Western Electricity Coordinating Council (WECC) 

area (including CAISO). The nation’s first commercial large-scale offshore wind facility also began operation with one 
2023 STATE OF THE MARKET n 5

of its twelve turbines going online in 2023.5 Located offshore of Rhode Island, the 130 megawatt (MW) South Fork Wind 

facility began delivering electricity to Long Island on December 6, 2023, and is expected to be fully operational in early 

2024. Nuclear capacity also increased when the new 1,114 MW Vogtle Unit 3 in Georgia came online on July 31, 2023; 

Unit 3 is the second nuclear reactor completed in the United States since 1996.6

Resource additions, retirements, and fuel prices were among the factors that altered the nation’s generation resource 

mix in 2023.7

 Coal generation declined most significantly, by 18.8% in 2023, due to coal resource retirements and 

lower natural gas prices making natural gas resources more economic compared to coal resources. Correspondingly, 

the share of natural gas generation grew last year. Natural gas resources accounted for 42.1% of electricity generation 

from utilities and independent power producers in 2023, a 7% increase from the prior year. Solar generation increased 

by 14%, while wind generation declined by 2%. Combined, solar and wind generation accounted for 14.7% of 

electricity generation from utilities and electric power producers in 2023. Much of the wind and solar generation was 

concentrated in certain regions within the United States; 72% of all wind energy was generated in ERCOT, MISO, and 

SPP, and 89% of all solar energy was generated in ERCOT, the WECC area (including CAISO), and the SERC Reliability 

Corporation (SERC) area in the Southeast.

Total annual electricity consumption decreased slightly in most regions in 2023 compared to 2022. Of the regional 

transmission operator and independent system operator (RTO/ISO) markets, the decrease was most significant in 

the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO). 

Compared to the past ten years, total annual electricity consumption in 2023 was lower in the East and CAISO, higher 

in the central United States, and relatively flat in the non-CAISO West. ERCOT was the exception, where total electricity 

consumption grew more than 3% for the second year in a row. Hot weather during the summer contributed to new 

records for peak electricity demand in ERCOT and SPP, while peak demand approached but did not surpass the record 

peak demand in MISO that was set in 2011. Maximum daily electricity consumption, which is the most electricity 

consumed during a single day of the year (adding the hourly average demand for all hours of the day), reached a new 

high in ERCOT, SPP, and MISO in 2023 compared to the prior ten years with data available. 

Wholesale electricity prices declined significantly at most representative pricing hubs in 2023 compared to the high 

prices in 2022 as shown in Figure 3. Lower natural gas prices contributed to lower wholesale electricity prices because 

natural gas resources were often the marginal resource, and therefore set the wholesale electricity price in the 

RTO/ISO markets.8

 On-peak average prices at trading hubs in the eastern United States declined most significantly, 

including by as much as 59% at NYISO Zone J in New York City. Compared to the five-year average prior to 2022, prices 

were up across most of the representative trading hubs with the highest increase in the West, a smaller increase in the 

East, and price declines only in SPP and MISO South. In RTOs/ISOs, load-weighted electricity prices were up 10% in 

2023 compared to the five-year average prior to 2022.9

 Average wholesale electricity prices in 2023 varied considerably 

across the United States with the lowest prices occurring in SPP ($31.67/MWh), the Southeast ($32.28/MWh), and 

MISO South ($33.73/MWh), and the highest prices occurring in the Northwest ($80.99/MWh), ERCOT ($79.27/MWh) and 

CAISO ($63.92/¬MWh).

5. South Fork Wind, Press Release, Governor Hochul Announces South Fork Wind Delivers First Offshore Wind Power To Long Island (December 6, 2023), https://southforkwind.com/

news/2023/12/south-fork-wind-delivers-first-offshore-wind-power-to-long-island. Earlier and smaller scale offshore wind projects include the 30 MW Block Island offshore facility 

offshore of Rhode Island (2016) and the 12 MW Coastal Virginia Offshore Wind Pilot Project facility offshore of Virginia (2020). 

6. The Tennessee Valley Authority in 2016 completed construction of the Watts Bar Unit 2 reactor, a project that was mothballed in 1988 and revived in 2007. Watts Bar Unit 1 was 

completed in 1996. 

7. The nation’s generation resource mix is measured as the percent of all electricity (in MWh) generated by each resource type for the year.

8. For more information on price formation in RTO/ISO markets, see the Wholesale Electricity Markets chapter in FERC’s Energy Primer: A Handbook for Energy Market Basics, https://

www.ferc.gov/media/energy-primer-handbook-energy-market-basics.

9. The load-weighted average electricity price is calculated by weighting the annual average electricity price at representative hubs in each RTO/ISO by the total annual electricity 

consumption in that RTO/ISO. As a result, larger RTOs/ISOs contribute more to the value of the load-weighted average compared to smaller RTOs/ISOs
6 n 2023 STATE OF THE MARKET 

Figure 3: Percent Change in Average Day-Ahead On-Peak Wholesale Electricity Price

10. On-peak means pre-defined hours of the day when electricity demand is relatively high. The exact period varies by region but is generally between morning and evening during the week. 

11. The C Three Group, L.L.C., North American Electric Transmission and Distribution Project Database, (accessed Jan. 16, 2024), https://cthree.net/databases. 

12. Improvements to Generator Interconnection Procedures and Agreements, Order No. 2023, 184 FERC ¶ 61,054 (2023).

-60 -40 -20 0

NYISO Zone J

ISO-NE Internal Hub

Into Southern*

PJM Western Hub

MISO Louisiana Hub

MISO Indiana Hub

SPP North

Palo Verde*

CAISO SP15

CAISO NP15

Mid-Columbia*

ERCOT North Hub

Percent Change from 2022

Median

Mean

Source: S&P Global Capital IQ denotes bilateral hubs. 10

Transmission and Interconnection Fundamentals. Over 500 new electric transmission projects entered service in 

2023 across the United States according to data from C3 Group LLC.11 These projects produced over 4,000 miles of new 

transmission lines and upgrades, mostly at the 138 kilovolt (kV) level. ERCOT led all regions with over 200 transmission 

projects, mostly at the 138 kV level. Outside of ERCOT, the largest number of transmission projects entered service 

in MISO and PJM. Transmission providers identified new transmission needs in 2023, as discussed in the Evolving 

Electricity Transmission Needs section below. In addition, in October 2023, the U.S. Department of Energy announced 

it will enter into contract negotiations to purchase a percentage of the capacity of three proposed large transmission 

lines across six states through the Transmission Facilitation Program, which is a $2.5 billion revolving fund authorized 

by the Infrastructure Investment and Jobs Act. 

While transmission providers made progress in processing requests from resource owners to interconnect to the 

transmission system, backlogs persisted nationwide in 2023. Renewable generation and storage made up most of the 

new projects seeking interconnection in 2023, continuing the general trend of resource capacity additions witnessed 

in prior years. At the end of 2023, the remaining volume of active interconnection requests was more than quadruple 

the amount at the end of 2019. In July 2023, the Commission issued Order No. 2023 to address interconnection 

queue backlogs, improve certainty for generation project developers and transmission providers, and protect new 

technologies from undue discrimination.12
2023 STATE OF THE MARKET n 7

TRANSFORMING MARKETS 

13. FERC, Modernizing Electricity Market Design Order Directing Reports, Docket No. AD21-10-000, at 3, 6-7, 8-9 (April 21, 2022), https://www.ferc.gov/media/ad21-10-000-0; FERC, 

Energy and Ancillary Services Market Reforms to Address Changing System Needs, Docket No. AD21-10-000, at 3, 7-16 (Sept. 2021), https://www.ferc.gov/sites/default/

files/2021-09/20210907-4002_Energy%20and%20Ancillary%20Services%20Markets_2021_0.pdf.

14. For more on ancillary services markets and products, see the section on Ancillary Services at PP 57-58 in FERC’s Energy Primer: A Handbook for Energy Market Basics, https://www.

ferc.gov/media/energy-primer-handbook-energy-market-basics.

15. Southwest Power Pool, Inc., 180 FERC ¶ 61,088 (Aug. 16, 2022).

16. The Market Monitoring Unit explains that the Uncertainty Reserve product prices are also driven down because offline but, “soon-to-start” resources are counted towards meeting 

the uncertainty requirement but are not paid for the service because SPP deems the opportunity cost of providing the product to be zero. SPP Market Monitoring Unit, State of the 

Market Fall 2023 at 63-64 (February 12, 2024), https://www.spp.org/documents/71103/spp%20mmu%20qsom%20fall%202023.pdf .

17. PJM, Synchronized Reserve Performance at 3 (Feb. 8, 2023), https://www.pjm.com/-/media/committees-groups/committees/mic/2023/20230208/20230208-item-10---

synchronized-reserve-performance.ashx.

18. PJM, Synchronized Reserve Requirement Reliability Update (May 18, 2023), https://www.pjm.com/-/media/markets-ops/ancillary/reserves-procedure-memo.ashx.

The changing resource mix, technological advancements, extreme weather events, and shifting demand patterns 

continue to push organized markets to adapt to evolving conditions. This section discusses evolving electricity market 

needs and the response of RTOs/ISOs in 2023 to those evolving needs, including market rule changes, significant 

developments, and instances where wholesale electricity market arrangements have expanded. 

Evolving Electricity Market Needs

ENERGY AND ANCILLARY SERVICES MARKET REFORMS

The resource mix changing to more weather-dependent, variable energy resources requires system operators to ensure 

that the resources available provide sufficient operational flexibility to reliably serve loads.13 System operators have a 

variety of tools to meet this system need for greater operational flexibility, and several RTOs/ISOs proposed reforms in 

recent years to increase operational flexibility. In RTO/ISO markets, the approaches largely consist of enacting reforms 

to increase the price of energy during shortage events, procure additional amounts of existing ancillary services such 

as operating reserves, and create new ancillary services such as ramp or uncertainty products. This section discusses 

some of the steps RTOs/ISOs and their stakeholders have taken to address this need for greater operational flexibility 

and how those reforms have affected markets in recent years.14

In 2023, SPP implemented a new ancillary service, Uncertainty Reserve, to compensate resources for helping SPP 

manage uncertainty that results when output from wind resources deviates from SPP’s forecasts.15 The Uncertainty 

Reserve product is intended to complement SPP’s existing Ramp Capability product by expanding the availability 

of flexible capacity over a longer time horizon. In its first six months of operations, according to the SPP Market 

Monitoring Unit, the Uncertainty Reserve product has cleared at or near a price of $0/MWh in the vast majority of 

intervals in both the day-ahead and real-time markets in part because the uncertainty requirement is frequently zero 

MW because the need is met by other ancillary services.16

Also in 2023, PJM increased the quantity of synchronized reserves it procures for all hours in the Day-Ahead and 

Real-Time Energy markets. Following changes to the PJM reserve markets, which are intended to provide energy 

to system operators within ten minutes if deployed, PJM observed a notable decline in resources assigned to 

provide Synchronized Reserves.17 In response, on May 19, 2023, PJM implemented a temporary static adder to the 

Synchronized Reserve Reliability requirement, which increased the reserve requirement by 30% to 130% of the most 

severe single contingency. 18 This increase ensured PJM operators had sufficient Synchronized Reserves available for 

reliability, but also increased the cost to serve load. According to the PJM market monitor, the total cost paid 
8 n 2023 STATE OF THE MARKET 

for Synchronized Reserves for the period of May-September 2023 was $6.1 million per month compared to $1.8 million 

per month for January-April 2023.19

The Commission last year approved tariff revisions by CAISO and ISO-NE, which will be implemented in 2025, to 

address the need for operational flexibility by changing their day-ahead energy and ancillary services market.20 Both 

reforms include new ancillary service products designed to address increasing supply and load forecast differences 

between the day-ahead and real-time markets related to rapid growth in variable energy resource capacity and 

uncertainty from extreme weather.21 CAISO’s Day-Ahead Market Enhancement reforms will add two new ancillary 

service products—the Imbalance Reserves and Reliability Capacity products—to CAISO’s day-ahead market.22 ISONE’s reforms will create a new Day-Ahead Ancillary Services market that includes four new reserve products that are 

structured as call-options on real-time energy.23 One product, the Day-Ahead Energy Imbalance Reserve, is designed 

to procure reserves to meet the load forecast should the Day-Ahead Market clear insufficient resources. CAISO states 

that its proposal will improve reliability and decrease costs to ratepayers; ISO-NE claims its reform will provide 

targeted compensation and clear financial obligations and incentives for the flexible resources the region relies upon, 

while solving for the most cost-effective solution that will satisfy demand and reserve requirements.24

Implementation and Refinement of Ramp Products. As the resource mix changes with the addition of variable 

energy resources, system operators have increasingly focused on the need to reliably serve net load, which is system 

load minus the concurrent generation of solar and wind resources. Figure 4 shows the average annual net load curves 

in each RTO/ISO in each 5-minute interval over the 2019-2023 period. It suggests that the increased penetration of 

variable energy resources is changing the net load profile in RTOs/ISOs and increasing the need for ramp-capable 

resources to manage net load variability and uncertainty. Most notably, this change is seen through the increasing 

difference between net load at midday and the evening peak, a trend observed in almost every RTO/ISO. Across RTOs/

ISOs, the average net load curve has generally declined in recent years.

Ramp products are a major energy and ancillary service market innovation created in response to the increasing 

net load variability (i.e., net load ramps) and uncertainty (e.g., net load forecasting errors).25 Ramp products are 

currently implemented in the three FERC-jurisdictional RTOs/ISOs with the most significant amount of variable energy 

resources (CAISO, SPP, MISO). A ramp product entails the procurement of resources with the ability to ramp up or 

down within a certain timeframe (e.g., ten or 15 minutes), and operators need this ramp capability to manage net load 

variability and uncertainty. While the mechanics of each RTO/ISO’s ramp products are different, their purposes are 

similar: reserving fast-ramping and/or fast-starting resources able to quickly respond to operator instructions to either 

increase or decrease output to ensure the system can reliably serve net load.

19. Monitoring Analytics, State of the Market Report for PJM: January through September at 604 (Nov. 9, 2023), https://www.monitoringanalytics.com/reports/PJM_State_of_the_

Market/2023/2023q3-som-pjm.pdf.

20. CAISO, Day-Ahead Market Enhancements and Extended Day-Ahead Market, Docket No. ER23-2686 (Aug. 22, 2023), https://www.caiso.com/Documents/Aug22-2023-DAME-EDAMTariff-Amendment-ER23-2686.pdf (CAISO DAME and EDAM Filing); ISO-NE, Revisions to ISO New England Transmission, Markets and Services Tariff to Establish a Jointly Optimized DayAhead Market for Energy and Ancillary Services, Docket No. ER24-275-000 (Oct. 31, 2023), https://www.iso-ne.com/static-assets/documents/100004/rev_to_est_jointly_optimized_

day-ahead_mkt_for_energy_and_ancillary_services.pdf (ISO-NE DASI Filing).

21. Cal. Indep. Sys. Operator Corp., 185 FERC ¶ 61,210, (Dec. 20, 2023); ISO New England Inc., 186 FERC ¶ 61,076, (Jan. 29, 2024). 

22. CAISO DAME and EDAM Filing at 6-7. 

23. ISO-NE DASI Filing at 12-23 (discussing the call-option design of the Day-Ahead Ancillary Services products). 

24. CAISO DAME and EDAM Filing at 1; ISO-NE DASI Filing at 4-6. 

25. FERC, Energy and Ancillary Services Market Reforms to Address Changing System Needs, Docket No. AD21-10-000, at 20 (Sept. 2021), https://www.ferc.gov/sites/default/

files/2021-09/20210907-4002_Energy%20and%20Ancillary%20Services%20Markets_2021_0.pdf.
2023 STATE OF THE MARKET n 9

Figure 4: Annual Average Net Load Curves for RTOs/ISOs

Source: Staff analysis of RTO/ISO data from Yes Energy. NOTE: The 2019 net load data from MISO is omitted from this figure due to data limitations.
10 n 2023 STATE OF THE MARKET 

As with many innovative products, RTOs/ISOs and their stakeholders have worked to improve the performance of their 

ramp products in recent years. Most notably, proposals seek to change market rules to ensure ramp deliverability, 

that is, to ensure that the ramp capability procured through the ramp product can be deployed and is not behind a 

binding transmission constraint. For example, the Commission accepted CAISO’s tariff revisions26 after CAISO found 

that a “meaningful share” of its flexible ramping product awards were undeliverable because of transfer limitations 

or other transmission constraints that were not accounted for in CAISO’s market software.27 CAISO revised its software 

in February 2023 to ensure flexible ramp awards were deliverable and the CAISO market monitor reported that the 

frequency of economically dispatchable (i.e., deliverable) ramp in the 15-minute and 5-minute intervals improved.28

MISO noted a similar deliverability issue in 2022, finding that nearly all of its upward ramp awards to dispatchable 

intermittent resources were economically undeliverable due to transmission constraints, and 31% of upward ramp 

procured from other resources were economically undeliverable.29 In response, MISO proposed, and the Commission 

approved, revisions to MISO’s tariff that made dispatchable intermittent resources ineligible to provide ramp 

capability.30 MISO believes these changes will improve reliability, price signals and unit commitment.31 To address 

similar concerns, SPP has recently discussed potential methods to improve ramp deliverability.32 Following the 

first year of the deployment of SPP’s ramp product, SPP’s market monitor noted in its 2022 annual report that “a 

large percentage” of SPP’s upward ramp capability product was awarded to resources behind binding or breached 

transmission constraints, and was thus not deliverable to the market.33

RESOURCE ADEQUACY REFORMS 

Resource adequacy is a growing concern across the United States for several reasons, including increasingly frequent 

extreme weather events, resource additions and retirements, and changing load profiles. This section discusses 

developments related to resource adequacy and some of the changes planning authorities have made to their 

processes in 2023 and recent years. 

The need for more accurate ways to both measure reliability risks and accredit resources has prompted several 

RTOs/ISOs to file tariff changes with the Commission. For example, in October 2023, responding to studies indicating 

that loss of load risk in the PJM system occurs mostly in winter, PJM submitted proposed reforms to its capacity 

market (the Reliability Pricing Model or RPM) and its Reliability Assurance Agreement. These reforms are intended 

to enhance PJM’s resource adequacy risk modeling and capacity accreditation processes and enhance testing 

requirements of capacity resources.34 Among other things, the reforms will require PJM to model resource adequacy 

risk in all hours of the year and using an expected unserved energy metric while also maintaining the one event in 

ten year loss of load expectation (1-in-10 LOLE) standard.35 This expected unserved energy metric captures 

information on the duration and magnitude of loss of load events, whereas the 1-in-10 LOLE measures solely 

26. Cal. Indep. Sys. Operator Corp., 181 FERC ¶ 61,034, (Oct. 18, 2022). 

27. CAISO, Tariff Amendment to Refine Flexible Ramping Product (Aug. 15, 2022), https://www.caiso.com/Documents/Aug15-2022-TariffAmendment-FlexibleRampingProductRefinemen

ts-ER22-2661.pdf. The amendments to address undeliverability went into effect on February 1, 2023. See CAISO, Informational Filing of the Effective Date of Flexible Ramping Product

(Feb. 2, 2023), https://www.caiso.com/Documents/Feb2-2023-InformationalFiling-EffectiveDate-FlexibleRampingProduct-ER22-2661.pdf.

28. CAISO Department of Market Monitoring, Q2 2023 Report on Market Issues and Performance, at 47 (Nov. 16, 2023), https://www.caiso.com/Documents/2023-Second-Quarter-Reporton-Market-Issues-and-Performance-Nov-16-2023.pdf. Economically dispatchable ramp is defined as up and down ramp capacity that does not violate transmission or transfer 

constraints, and thus can be called by the market operator to meet ramp or uncertainty needs of a given interval.

29. MISO, Response to Deficiency Letter – Dispatchable Intermittent Resources vis-à-vis Ramp Capability Products, Docket No. ER23-1195 at 2-3 (June 5, 2023), https://cdn.misoenergy.

org/2023-06-05%20Docket%20No.%20ER23-1195-001629179.pdf. MISO defines the capacity from a resource as being economically undeliverable if the marginal congestion 

component of the LMP for the resource is less than zero in a five-minute real-time interval.

30. Midcontinent ISO, 184 FERC ¶ 61,134, (Aug. 31, 2023).

31. MISO, Dispatchable Intermittent Resources vis-à-vis Ramp Capability Product, Docket No. ER23-1195, at 6-9 (Feb. 28, 2023).

32. SPP, Ramp Product Deliverability Analysis (Sept. 2023), https://www.spp.org/spp-documents-filings/?id=18437. 

33. SPP Market Monitoring Unit, State of the Market 2022 at 112 (May 15, 2023), https://www.spp.org/documents/69330/2022%20annual%20state%20of%20the%20market%20report.pdf.

34. PJM Interconnection L.L.C., Transmittal, Docket No. ER24-99-000, at 6 (Oct. 13, 2023), https://www.pjm.com/-/media/documents/ferc/filings/2023/20231013-er24-99-000.ashx. The 

Commission subsequently accepted PJM’s proposed tariff revisions subject to condition. PJM, 186 FERC ¶ 61,080 (January 30, 2024). 

35. PJM Interconnection L.L.C., Transmittal, Docket No. ER24-99-000, at 17 (filed Oct. 13, 2023) https://www.pjm.com/-/media/documents/ferc/filings/2023/20231013-er24-99-00 0.ashx. 
2023 STATE OF THE MARKET n 11

the number of days that are expected to have some level of resource adequacy insufficiency. The Commission 

subsequently accepted PJM’s proposed tariff revisions subject to condition.36

MISO recently implemented a seasonal resource adequacy construct, which recognizes that resources perform 

differently at different times of year and that resource adequacy risks vary during the year. In August 2022, the 

Commission issued an order accepting, subject to condition, MISO’s proposed seasonal resource adequacy construct, 

which also included a new availability-based resource accreditation methodology for thermal and demand response 

resources.37 Following the order, MISO held the first seasonal Planning Resource Auction (PRA) in April 2023. MISO’s 

new seasonal PRA conducts four auctions, one for each season. Each resource’s accredited capacity can vary by 

season. For example, under the annual construct MISO calculated a class average wind capacity credit for the 2022-

2023 Planning Year of 15.5%, while under the seasonal construct for the 2023-2024 Planning Year the class average 

wind capacity credit ranged from 18.1% for Summer 2023 to 40.3% for Winter 2023-2024.38

In February 2023, the Commission accepted the Northwest Power Pool’s proposed resource adequacy program 

called Western Resource Adequacy Program (WRAP) in the Western Interconnection.39 WRAP is a voluntary 

resource adequacy planning and compliance framework designed to improve resource adequacy in the Western 

Interconnection. WRAP participants are obligated to comply with resource adequacy requirements or face penalties 

for non-compliance.40 Northwest Power Pool started WRAP with a non-binding phase in 2022/2023 Winter Season and 

the first binding season is scheduled for summer 2025.41

Finally, planning authorities and market operators implemented changes to increase their regions’ planning reserve 

margins. The planning reserve margin is the amount of capacity secured relative to peak electricity demand and is an 

essential variable used to set the demand for capacity, including in the centralized capacity markets of PJM, ISO-NE, 

NYISO, and MISO. The changes to the planning reserve margins addressed resource adequacy risks related to extreme 

weather and the changing resource mix.42 For example, in July 2022, SPP’s Regional State Committee increased its 

planning reserve margin from 12% to 15%, a change that went into effect starting in summer 2023.43 SPP supported 

its change by noting that the previous 12% planning reserve margin requirement would not satisfy the 1-in-10 LOLE 

metric for summer 2023.44 In June 2023 the California Public Utilities Commission (CPUC) issued a decision adopting 

local capacity requirements for 2024 through 2026, flexible capacity requirements for 2024, and refinements to its 

resource adequacy program, which includes modifying the 2024 and 2025 planning reserve margin for load-serving 

entities.45 The CPUC adopted a 17% planning reserve margin for 2024 and 2025, an increase from the 16% planning 

reserve margin in 2023.46 The planning reserve margins for the centralized capacity markets of PJM, ISO-NE, NYISO, 

and MISO are shown in Figure 5. 

36. PJM, 186 FERC ¶ 61,080 (January 30, 2024).

37. Midcontinent Independent System Operator, Inc., 180 FERC ¶ 61,141 (Aug. 31, 2022).

38. Comparing MISO, Planning Year 2022-2023 Wind and Solar Capacity Credit (Jan. 2022), https://cdn.misoenergy.org/2022%20Wind%20and%20Solar%20Capacity%20Credit%20

Report618340.pdf and MISO, Planning Year 2023-2024 Wind and Solar Capacity Credit (Mar. 2023), https://cdn.misoenergy.org/2023 Wind and Solar Capacity Credit Report628118.

pdf.

39. Northwest Power Pool, 182 FERC ¶ 61,063 (Feb. 10, 2023).

40. Id. at P. 2, 5.

41. Id. at P. 13.

42. The terminology and method used to calculate the planning reserve margin varies across regions. The planning reserve margin is used for planning purposes and is distinct from 

the actual or expected reserve margin. See FERC, 2023 Common Metrics Staff Report, at 8-9 (Jan. 31, 2024), https://www.ferc.gov/sites/default/files/2024-01/2023_Common_

Metrics_Report.pdf. (summarizing actual and expected reserve margins for RTOs/ISOs). 

43. SPP, RSC’s July 2022 Summary of Motions and Action Items, at 1 (July 25, 2022), https://www.spp.org/documents/67602/rsc%20minutes%20july%2025,%202022%20v2.pdf. 

44. SPP, 22-07-11 MOPC agenda & materials, 03b – STAFF Planning Reserve Margin recommendation report at 1, (July 7, 2022), https://www.spp.org/spp-documents-filings/?id=299889. 

45. Decision Adopting Local Capacity Obligations for 2024 – 2026, Flexible Capacity Obligations for 2024, and Program Refinements, Docket No. R.21-10-002, at 2 ([CPUC] June 29, 2023), 

https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M513/K132/513132432.PDF. 

46. Id. at 14, 137.
12 n 2023 STATE OF THE MARKET 

47. PJM, 2022 PJM Reserve Requirement Study at 8, (Oct. 4, 2022), https://www.pjm.com/-/media/planning/res-adeq/2022-pjm-reserve-requirement-study.ashx (providing PJM 

planning reserve margin for 2023/2024). ISO-NE, Summary of Historical Installed Capacity Requirements and Related Values (Dec. 19, 2023), https://www.iso-ne.com/static-assets/

documents/2016/12/summary_of_historical_icr_values.xlsx (providing data used to calculate ISO-NE planning reserve margin based on the formula found in Appendix F of 2011 

Report to Congress on Performance Metrics for Independent System Operators and Regional Transmission Organizations at 91, (April, 2011), https://www.ferc.gov/sites/default/

files/2020-05/iso-ne-rto-metrics.pdf). New York State Reliability Council, L.L.C., Docket No.ER23-821-000, (Feb. 14, 2023) (delegated order), https://www.nysrc.org/wp-content/

uploads/2023/03/FERC-Letter-Order-2-14-2023.pdf. MISO, Planning Year 2023-2024 Loss of Load Expectation Study Report at 57 (May 3, 2023), https://cdn.misoenergy.org/PY%20

2023-2024%20LOLE%20Study%20Report626798.pdf. 

Figure 5: Planning Reserve Margin Values by Region.

Region Planning Reserve Margin for [Capability/Delivery/Planning] Year or 

Capacity Commitment Period 2023/2024

PJM 14.9%

ISO-NE* 12.7%

NYISO 20.0%

MISO* 15.9%

SPP 15.0%

CAISO 16.0%

Source: Various RTO/ISO Reports and Filings.47 NOTE: *ISO-NE PRM is calculated using values from Forward Capacity Auction, not 

values related to Annual Reconfiguration Auctions. MISO PRM value reports MISO’s Summer PRM. 

GAS-ELECTRIC MARKET INTERDEPENDENCE 

In 2023, natural gas consumed for electricity generation, or power burn, accounted for 41% of total U.S. natural gas 

demand. As the share of natural gas used for power burn has increased in the past five years, so has the share of 

electricity generated by natural gas as shown in Figure 6. With both shares slightly above 40% in 2023, the electricity 

and natural gas sectors are tightly linked. For example, natural gas-fired generators play a critical role in electricity 

markets because their typically short start times and ability to quickly ramp up and down allow them to provide 

some of the flexibility that system operators need. The growing share of natural gas generation resources in the 

resource mix increases the need to improve and integrate the operations, communications, contractual arrangements 

transparency, and reliability concerns between the natural gas and electric markets. 

Figure 6: Electric Generation Sourced from Natural Gas and Natural Gas Used for Electricity Generation

Year Share of Electric Generation (MWh) 

from Natural Gas

Share of Natural Gas Consumption (Bcf) 

for Power Burn

2018 35% 35%

2023 43% 40%

Source: EIA Electric Power Monthly. Electric generation includes commercial, industrial, and residential sectors.
2023 STATE OF THE MARKET n 13

Natural gas-fired generators purchase fuel and transportation services under a variety of arrangements. They may 

purchase natural gas from a marketer or asset manager, both of which typically procure the natural gas commodity 

and pipeline transportation on behalf of the generator. In these instances, the markets for gas transportation and the 

commodity are bundled together in a manner that is not transparent and often involves short-term arrangements with 

different levels of delivery risk and expense. Alternatively, generators may purchase separately the natural gas supply 

and pipeline transportation components. This involves a purchase between a generator and a natural gas supplier and 

a separate transportation agreement with a natural gas pipeline or an existing pipeline capacity holder to transport 

the fuel from the natural gas supplier to the generator.

Data from EIA’s Form 923 provides a view of the contractual choices that natural gas-fired generators have made 

in recent years to procure fuel, in terms of duration and types of service. In 2019, U.S. natural gas-fired generators 

reported increased use of long-term contracts, from 18% to 28%, reducing spot market purchases compared to past 

years. The generators’ reported usage of long-term contracts has remained roughly steady since that time. Similarly, 

natural gas-fired generators reported more frequently using firm transportation contracts than interruptible service to 

deliver natural gas.

Natural gas-fired generators can fulfill their natural gas supply requirements through long-term contracts, spot market 

transactions, or tolling agreements. Spot markets allow generators to tailor fuel purchases to their monthly or daily 

needs. However, if spot prices increase, for example due to an extreme weather event, natural gas-fired generators 

relying on the spot market must pay significantly higher fuel prices to meet their dispatch obligations or choose not to 

generate at all. In contrast, long-term supply contracts have gained traction in recent years as they provide generators 

with more fuel price stability and minimize their exposure to swings in the spot price. As shown in Figure 7, data from 

EIA Form 923 show that spot market purchases remain the dominant form of natural gas procurement for U.S. natural 

gas-fired generators.48 In 2019, natural gas-fired generators reported increased use of long-term (more than a year) 

contracts, from 18% to 29%, reducing spot market purchases compared to past years. The generators’ reported usage 

of long-term contracts has remained roughly steady since that time.

48. In EIA Form 923, spot market purchases are defined as fuel received under a purchase order or contract with a duration of less than one year, including month-ahead purchases. 

Long-term contracts are defined as fuel received under a purchase order or contract with a term of one year or longer. Under tolling agreements, a different company is responsible 

for the procurement and delivery of the fuel to the generating unit, placing the fuel price volatility risk with the other company instead of the generator. Natural gas-fired generators 

cannot report use of mixed transportation contracts or a financially hedged portfolio strategy. As of January 2024, EIA form 923 data for 2023 includes approximately a quarter of 

survey respondents (power plants) and the complete data for 2023 will be released in fall 2024. The survey is limited to large power plants (larger than 200 MW).
14 n 2023 STATE OF THE MARKET 

Figure 7: Shares of Natural Gas-Fired Generators Reporting Long-Term, Spot, or Tolling Procurement Arrangements

0

20%

40%

60%

80%

100% 5%

77%

18%

4%

68%

28%

4%

67%

29%

5%

64%

31%

5%

66%

30%

6%

65%

29%

Tolling Agreement Spot Market Long-Term Contract

2018 2019 2020 2021 2022 2023

Source: EIA Form 923 Schedule 5.

Figure 8: Shares of Natural Gas-Fired Generators Reporting Firm or Interruptible Transportation Contracts

0

20%

40%

60%

80%

100%

34%

66%

29%

71%

27%

73%

25%

75%

26%

74%

26%

74%

2018 2019 2020 2021 2022 2023

Interruptible Firm

Source: EIA Form 923 Schedule 5.
2023 STATE OF THE MARKET n 15

As shown in Figure 8, natural gas-fired generators can fulfill their natural gas transportation needs via firm or 

interruptible pipeline service. Interruptible transportation service allows customers to nominate natural gas along 

a pipeline when capacity is available, but interruptible service is not guaranteed, and interruptible transportation 

customers are lower in priority than firm transportation customers. Interruptible contracts are less expensive than 

firm contracts and generally short in duration, often for next-day delivery. Under a firm transportation contract, 

customers reserve a specified amount of capacity on the pipeline to ensure high-priority service by paying a 

reservation charge. The charge is based on the amount of pipeline capacity reserved by the shipper, regardless of 

how much of that capacity that shipper uses. Firm transportation cannot be curtailed except due to unforeseeable 

circumstances, such as force majeure. Since 2019, natural gas-fired generators reported more frequently using firm 

transportation contracts than interruptible service to deliver natural gas. 

Figure 9 shows geographic variation in natural gas-fired generators’ reported transportation and procurement 

arrangements. In the Midwest, natural gas-fired generators report procuring natural gas on the spot market 

more than the national average. Long-term contracts appear to be a more widely used procurement option 

in the South. For transportation services, firm contracts were reported as more prevalent in the West 

and South regions of the United States and below the national average in the Midwest and Northeast.49

49. For more information on natural gas markets and trading, see the Natural Gas Markets and Trading chapter in FERC’s Energy Primer: A Handbook for Energy Market Basics, https://

www.ferc.gov/media/energy-primer-handbook-energy-market-basics.

Figure 9: Regional Comparison of Natural Gas-Fired Generators’ Transportation and Procurement 

Arrangements in 2023

0

20%

40%

60%

80%

100%

West Midwest South Northeast

20%

80%

13%

63%

24%

44%

56%

0%

83%

17% 19%

81%

63%

3%

35% 42%

58%

50%

27%

23%

Interruptible Firm Tolling Long-Term Contract Spot Market

Transportation Procurement

Source: EIA Form 923 Schedule 5.
16 n 2023 STATE OF THE MARKET 

Expansion of Electricity Market Arrangements

Wholesale electricity market participants developed or expanded organized electricity markets (or market 

arrangements) in the West and Southeast in 2023. The Western Energy Imbalance Market (WEIM), operated by CAISO, 

and the Western Energy Imbalance Service (WEIS), operated by SPP, both added more participants, as shown in Figure 

10.50 WEIM expanded in April 2023 to include three new balancing authority areas: Western Area Power Administration 

Desert Southwest region, El Paso Electric, and AVANGRID – a generation-only balancing authority. WEIM now operates 

in 11 states.51 According to CAISO, WEIM provided economic benefits of about $462 million in the third quarter of 2023 

through cost savings, achieving over $4 billion in cumulative benefits since the start of the market in 2014.52 Cost savings 

are primarily driven by the expanded resource diversity across the WEIM footprint, which allows cheaper, variable energy 

resources to serve demand as well as more efficient balancing of supply and demand, according to CAISO.53

WEIS also expanded in April 2023 to include three new balancing authority areas: Xcel Energy-Colorado, Platte River 

Power Authority, and Black Hills Colorado Electric, LLC. This expansion doubled the size of WEIS in terms of peak load 

served and increased the number of participants to 12.54 Both CAISO and SPP are separately pursuing day-ahead 

markets in the West, with CAISO’s Extended Day-Ahead Market approved by the Commission in December 202355 and 

SPP’s Markets + effort still under development.56

The Southeast Energy Exchange Market (SEEM) is an intra-hour, bilateral trading platform that matches willing 

buyers and sellers to maximize economic benefits of potential bilateral trades through a split-the-savings matching 

algorithm that commenced in November of 2022.57 In July 2023, SEEM expanded when four Florida utilities joined 

and began trading such that SEEM currently has 17 members and one non-member participant. In terms of size, the 

average hourly demand of all balancing authority areas participating in SEEM averaged 86,930 MW in 2023.58 Economic 

benefits derived from SEEM transactions totaled $3.7 million in 2023, according to SEEM.59 Although demand and 

supply have grown on the platform since SEEM’s launch on average, less than 10% of the volume of demand bids 

submitted and just over 10% of the volume of supply offers summitted have cleared the SEEM market since July 

2023, as shown in Figure 11. There are many reasons why demand bids might not match supply offers and thus not 

be traded. According to the SEEM Market Auditor, the primary driver is a lack of mutually beneficial trades when 

supply offers are uneconomic as the supplier requires a higher price than the buyer is willing to pay and vice-versa for 

uneconomic demand bids.60

50. Both WEIM and WEIS are real-time markets that optimize electricity imbalance among participating entities using security-constrained, economic dispatch.

51. CAISO, Press Release, New entities expand WEIM’s reach to a total of 11 Western states (Apr. 5, 2023), https://www.westerneim.com/Documents/new-entities-expand-weims-reachto-a-total-of-11-western-states.pdf. 

52. CAISO, Press Release, Western Energy Imbalance Market hits $4.66 billion in total benefits (Oct. 31, 2023), https://www.westerneim.com/Documents/western-energy-imbalancemarket-hits-4-66-billion-in-total-benefits.pdf. WEIM calculates the total WEIM benefit as the cost savings of the WEIM dispatch compared with a co+unterfactual without the WEIM 

dispatch. See CAISO, EIM Quarterly Benefit Report Methodology (Accessed Jan. 31, 2024), https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.

53. Id. 

54. SPP, SPP’s Western Energy Imbalance Service Market (WEIS) provides millions in benefits, more than doubles in size (Apr. 10, 2023), https://spp.org/news-list/spp-s-western-energyimbalance-service-market-weis-provides-millions-in-benefits-more-than-doubles-in-size/.

55. Cal. Indep. Sys. Operator Corp., 185 FERC ¶ 61,210, (Dec. 20, 2023). 

56. SPP, Markets+ (Accessed Jan. 31, 2024), https://www.spp.org/western-services/marketsplus/.

57. In July 2023, the U.S. Court of Appeals for the District of Columbia Circuit remanded to the Commission orders establishing SEEM. Trading on SEEM continues while the Commission 

considers the remand. 

58. Staff analysis of EIA 930 data on the balancing authority areas participating in SEEM. This includes the Florida utilities that joined SEEM in 2023 and excludes PowerSouth 

Cooperative and municipal utilities because of data limitations. https://www.eia.gov/electricity/gridmonitor/dashboard/electric_overview/US48/US48.

59. SEEM, Public Data (Accessed Jan. 31, 2024), https://southeastenergymarket.com/reports/.

60. SEEM Independent Market Auditor, Monthly Audit Report on The Southeast Energy Exchange Market for September 2023 at 6-7 (Oct. 30, 2023), https://southeastenergymarket.com/

wp-content/uploads/SEEM-Audit-Report-2023_9-Final.pdf. 
2023 STATE OF THE MARKET n 17

Figure 10: Organized U.S. Wholesale Electricity Market Arrangements in 2023

Source: Hitachi ABB Power Grids Velocity Suite.

Figure 11: Average Demand Bids and Supply Offers and Average Cleared MW in SEEM Per 15-Minute Interval 

(2023)

0

200

400

600

800

1,000

1,200

1,400

Dec.

20

40

60

80

100

120

140

0

Supply MW Demand MW Cleared MW

Jan. Feb. March April May June July Aug. Sept. Oct. Nov.

Cleared MW (line)

Demand/Supply MW (bars)

Source: Staff analysis of SEEM Public Monthly Informational Reports.
18 n 2023 STATE OF THE MARKET 

TRANSFORMING INFRASTRUCTURE 

61. U.S. Department of Energy, National Transmission Needs Study (Oct. 2023), https://www.energy.gov/gdo/national-transmission-needs-study. The U.S. Department of Energy 

undertook this study pursuant to Section 216(a)(1) of the Federal Power Act; 16 U.S.C. 824p(a)(1).

62. Id.at vi-xi. 

63. Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, Notice of Proposed Rulemaking, 179 FERC ¶ 61,028 (Apr. 

21, 2023). See also, FERC, Press Release - FERC Issues Transmission NOPR Addressing Planning, Cost Allocation (Apr. 21, 2023), https://www.ferc.gov/news-events/news/ferc-issuestransmission-nopr-addressing-planning-cost-allocation. 

64. NERC, 2023 Long-Term Reliability Assessment at 10 (December 2023), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf. 

65. Grid Strategies LLC, The Era of Flat Power Demand is Over (Dec. 2023), (summarizing planning region load forecast growth as reported in FERC Form 714), https://gridstrategiesllc.

com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf.

66. Id.; PJM, PJM Inside Lines: PJM Publishes 2024 Long-Term Load Forecast (Jan. 28, 2024), https://insidelines.pjm.com/pjm-publishes-2024-long-term-load-forecast/.

67. PJM, PJM Board of Managers Approves Critical Grid Upgrades (Dec. 11, 2023), https://insidelines.pjm.com/pjm-board-of-managers-approves-critical-grid-upgrades/. 

68. PJM, Data Center Planning & Need Assessment Update (Jan. 10, 2023), https://pjm.com/-/media/committees-groups/committees/teac/2023/20230110/item-04---data-center-loadplanning.ashx. See also immediate need reliability project b3718.1-14 at https://www.pjm.com/planning/project-construction/immediate-need-projects.

69. ISO-NE, 2023 Regional System Plan at 81-84 (Nov. 1, 2023), https://www.iso-ne.com/static-assets/documents/100005/20231114_rsp_final.pdf.

This section discusses evolving electricity transmission needs, evolving natural gas infrastructure needs, and rising capital 

costs as they relate to infrastructure investment. The drivers of these evolving infrastructure needs are diverse and include 

the changing resource mix, increases in actual and forecasted demand for energy, and evolving reliability concerns that 

prompt the need for new and upgraded infrastructure to ensure reliable and cost-effective system operations. 

Evolving Electricity Transmission Needs 

Actual and forecasted load growth, the changing resource mix, and projected extreme weather conditions all 

drove transmission needs identified by transmission providers in 2023 to support a more economic and reliable 

electricity transmission system, as described below. In October 2023, the U.S. Department of Energy released a study 

identifying transmission needs that are currently harming consumers or expected to do so in the future and that 

could be alleviated by transmission solutions.61 The Department of Energy study found significant need for future 

transmission.62 Recognizing the need for longer-term transmission planning processes, the Commission issued in April 

2022 a Notice of Proposed Rulemaking to address the need for the United States’s energy infrastructure to be more 

resilient and reliable while also achieving cost savings for consumers by reforming regional transmission planning and 

cost allocation processes.63

Load growth can change the physical use of the transmission system and require transmission providers to identify 

new transmission lines or network upgrades that are needed to meet reliability needs. NERC’s 10-year forecasts of 

electricity peak demand and energy growth were higher in 2023 than any point in the last decade.64 In 2023, many 

planning areas, including some RTOs/ISOs, increased their forecasted load growth compared to previous forecasts.65

Of all RTOs/ISOs, PJM expects the largest amount of nominal growth by 2028 and recently forecasted even higher load 

growth in its new long-term load forecast.66 In December 2023, PJM approved a set of proposed projects, estimated to 

cost approximately $5 billion, to maintain reliability as PJM prepares for 7,500 MW of new demand from planned data 

centers in Virginia and Maryland and the planned retirement of more than 11 GW of generation capacity (discussed 

below).67 In addition, the large projected increase in load from data centers in northern Virginia has prompted PJM to 

identify immediate-need reliability transmission projects to meet established reliability standards.68

Plans from the transmission providers indicate that the changing resource mix will drive future transmission needs as 

well. For example, CAISO’s 2022-2023 Transmission Plan identified $5.53 billion in potential transmission investments 

that could facilitate the addition of 40 GW of new resources — mostly solar and lithium battery storage. ISO-NE 

faces a similar issue related to transmission planning, with a growing interconnection queue of mostly wind, solar, 

and battery resources, and has identified the need for forward-looking transmission planning efforts to address 

these trends.69 Similarly, NYISO recently claimed that transmission expansion is “critical to facilitating” the efficient 
2023 STATE OF THE MARKET n 19

achievement of energy targets included in the state’s Climate Leadership and Community Protection Act (CLCPA), as 

the current transmission system is inadequate to do so.70 For example, according to NYISO, transmission upgrades are 

necessary to meet the CLCPA target of 9,000 MW of offshore wind installed by 2035. NYISO took a step towards meeting 

that target in 2023 by selecting a transmission project through the Public Policy Transmission Planning Process to 

increase export capability from Long Island to the rest of the state and thereby ensure access to 3,000 MW of planned 

offshore wind.71 Subsequently, the New York Public Service Commission found that the CLCPA constitutes a Public 

Policy Requirement driving the need for additional transmission to support the injection of offshore wind generation 

into New York City.72 The New York Public Service Commission referred that need to NYISO and NYISO is in the early 

stages of identifying solutions to meet that need.73

A steady, nationwide increase in the cost and quantity of network upgrades needed to facilitate generator 

interconnections indicates that existing transmission systems have limited available capacity. Data from Lawrence 

Berkeley National Laboratory (LBNL) show that over the last five years interconnection costs have increased in SPP, 

MISO, PJM, NYISO, and ISO-NE across all resource types.74 The highest overall increases occurred in MISO and PJM. In 

the last five years, interconnection projects for onshore wind resources experienced the highest increases in average 

costs of all resource types and in all RTOs/ISOs, particularly in ISO-NE.75

Major resource retirements are also driving transmission needs. As a specific example, the planned 2025 retirement of 

the Brandon Shores power plant in Maryland has prompted PJM to identify immediate-need reliability transmission 

projects that are projected to cost a collective $785 million.76 NYISO also identified the fast pace of resource 

retirements, compared to the pace of additions, as a key reliability risk factor in its 2023-2032 Comprehensive 

Reliability Plan.77 For example, NYISO expressed concerns about the phaseout of natural gas plants owned by New 

York Power Authority that could cause a 517 MW deficiency to the New York City transmission security margin in 

2031; NYISO has indicated that it will evaluate this issue further in future assessments.78 NYISO also identified a nearterm reliability need in Summer 2025 within New York City, driven by forecasted increases in peak demand and the 

assumed unavailability of certain combustion turbines affected by the New York State Department of Environmental 

Conservation’s Peaker Rule.79

Transmission planners also examined in 2023 how extreme weather events, including heatwaves and winter storms, 

can threaten reliable operations of the transmission system. ISO-NE found that worst-case winter scenarios indicate 

an increasing risk of energy shortfalls between 2027 and 2032 due to generation retirements and increased load 

electrification, which can be mitigated by the timely addition of incremental transmission imports from the New 

70. NYISO, 2023-2032 Comprehensive Reliability Plan at 12 (Nov. 28, 2023), https://www.nyiso.com/documents/20142/2248481/2023-2032-Comprehensive-Reliability-Plan.pdf/

c62634b6-cdad-31dc-5238-ee7d5eaece04?t=1701203618895. 

71. NYISO, Long Island Offshore Wind Export Public Policy Transmission Plan (June 13, 2023), https://www.nyiso.com/documents/20142/38388768/Long-Island-Offshore-Wind-ExportPublic-Policy-Transmission-Planning-Plan-2023-6-13.pdf. 

72. Order Addressing Public Policy Requirements for Transmission Planning Purposes at 2, 45, Appendix A at 1 ([New York Public Service Commission] June 22, 2023), https://www.nyiso.

https://www.nyiso.com/documents/20142/40894368/New-York-City-PPTN-Technical-Conference-Dec-7-Presentation.pdf/.

73. Id. See also NYISO, Technical Conference on New York City Public Policy Transmission Need (Dec. 7, 2023), https://www.nyiso.com/documents/20142/40894368/New-York-City-PPTNTechnical-Conference-Dec-7-Presentation.pdf.

74. LBNL, Generator Interconnection Costs to the Transmission System (June 2023), https://eta-publications.lbl.gov/sites/default/files/berkeley_lab_interconnection_cost_webinar.pdf.

75. Id. at 14, 23.

76. E.g., PJM, Generation Deactivation Notification Update (June 6, 2023), https://www.pjm.com/-/media/committees-groups/committees/teac/2023/20230606/20230606-item-02---

generation-deactivation-notification-update.ashx. See also immediate need reliability project b3780.1-13 at https://www.pjm.com/planning/project-construction/immediate-needprojects. Initial cost estimates are available here: PJM, Transmission Expansion Advisory Committee Recommendations to the PJM Board (July 2023), https://www.pjm.com/-/media/

committees-groups/committees/teac/2023/20230711/20230711-pjm-teac-board-whitepaper-july-2023-public.ashx.

77. NYISO, 2023-2032 Comprehensive Reliability Plan at 9 (Nov. 28, 2023), https://www.nyiso.com/documents/20142/2248481/2023-2032-Comprehensive-Reliability-Plan.pdf.

78. Id. at 49.

79. Id. at 5. NYISO has designated the generators on the Gowanus 2 & 3 and Narrows 1 & 2 barges in New York City to temporarily remain in operation after the Peaker Rule compliance 

date until permanent solutions to the near-term reliability needs are in place, for an initial period of up to two years (through May 1, 2027). NYISO, Short-Term Reliability Process 

Report: 2025 Near-Term Reliability Need at 9 (Nov. 20, 2023), nyiso.com/documents/20142/39103148/2023-Q2-Short-Term-Reliability-Process-Report.pdf/. 
20 n 2023 STATE OF THE MARKET 

England Clean Energy Connect transmission project and generation resources such as behind-the-meter and utilityscale solar and offshore wind.80 NYISO also identified how extreme weather events pose a threat to grid reliability and 

could result in energy shortfalls, especially in New York City as early as 2027-2028 for an extreme 1-in-100-year winter 

event combined with natural gas supply shortages. NYISO states that it must continue to rely on emergency assistance 

from neighboring regions to mitigate energy shortfalls, noting that otherwise New York would not have adequate 

resources throughout the next ten years. NYISO’s studies indicate that the reliability of the grid is heavily reliant on the 

timely completion of the Champlain Hudson Power Express transmission project, a transmission line connecting New 

York with Quebec that is scheduled to enter service in the spring of 2026.81

Regional Transmission Plans. Public utility transmission providers in each Order No. 1000 transmission planning 

region worked towards or completed a regional transmission plan in 2023, some of which are discussed below. 

• CAISO’s 2022-2023 Transmission Plan identified 46 needed transmission projects. This includes 24 reliability driven 

projects required to reliably serve projected load, totaling $1.76 billon, and an additional 21 policy-driven projects 

needed to meet the renewable generation requirements established by the CPUC, totaling an additional $5.53 

billion.82 Some of these policy-driven projects would expand the capability to import wind from outside of CAISO.

• MISO’s 2023 MISO Transmission Expansion Plan (MTEP) proposed 572 new transmission projects totaling $8.98 

billion, the second-highest investment following the $13.38 billion in MISO’s 2021 MTEP. Of the 572 projects, 142 are 

Generator Interconnection Projects, 45 are Baseline Reliability Projects, two are Market Participant Funded Projects, 

and one is a Multi-Value Project. In addition, 382 projects are classified as Other, most of which address localized 

reliability issues related to load-serving needs, local specific reliability needs, and aging transmission infrastructure. 

The 572 new projects include 742 miles of new or upgraded lines, 87% of which are 161 kV or below.83

• PJM’s 2023 Regional Transmission Expansion Plan identified 48 new baseline projects to maintain grid reliability 

at an estimated cost of $6.6 billion and 93 new network transmission projects to enable the reliable delivery of 

generation seeking interconnection at an estimated cost of $180 million. PJM also evaluated 227 supplemental 

projects put forward by transmission owners which are estimated to cost $2.4 billion. 84

• SPP’s 2023 Integrated Transmission Plan recommended 44 transmission projects, totaling $735.5 million, which 

includes 16 reliability projects, 24 economic projects, and 4 short-circuit projects. The 44 projects include 150 miles of 

new transmission including 51 miles at or above 345 kV in addition to 93 miles of rebuilt high-voltage transmission.85

Developments in Interregional Transmission Planning. In 2023, some transmission providers advanced efforts to 

identify transmission projects designed to increase transfer capability between transmission planning regions.86

The MISO-SPP Joint Targeted Interconnection Queue Study identified five transmission projects, which would add 

80. ISO-NE, ISO-NE’s Study Of Energy Shortfall Risks Produces Innovative Tool For Assessing Energy Adequacy (Dec. 11, 2023), https://isonewswire.com/2023/12/11/iso-nes-study-ofenergy-shortfall-risks-produces-innovative-tool-for-assessing-energy-adequacy. New England Clean Energy Connect is a planned HVDV transmission line designed to deliver 1,200 

MW of hydropower from Quebec into the ISO-NE system at an interconnection in Lewiston, Maine. 

81. NYISO, 2023-2032 Comprehensive Reliability Plan at 9-10, 48, 63, 86 (Nov. 28, 2023), https://www.nyiso.com/documents/20142/2248481/2023-2032-Comprehensive-Reliability-Plan.pdf/.

82. CAISO, California ISO 2022-2023 Transmission Plan (May 10, 2023), https://www.caiso.com/InitiativeDocuments/Revised-Draft-2022-2023-Transmission-Plan.pdf. 

83. MISO, 2023 MISO Transmission Expansion Plan (Nov. 2023), https://cdn.misoenergy.org/MTEP23%20Full%20Report630587.pdf. 

84. PJM, 2023 Regional Transmission Expansion Plan (Mar. 7, 2024), https://www.pjm.com/-/media/library/reports-notices/2023-rtep/2023-rtep-report.ashx.

85. SPP, 2023 Integrated Transmission Planning Assessment Report (Nov. 20, 2023), https://www.spp.org/documents/70584/2023%20itp%20assessment%20report%20v1.0.pdf. 

86. Order No. 1000 requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan. See 

Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051 at 1 (2011). In this context, a transmission planning region is 

the collection of public utility transmission providers participating in the same single regional transmission planning process. 
2023 STATE OF THE MARKET n 21

28.7 GW of capacity and are estimated to cost $1.06 billion.87 In the West, CAISO coordinated with WestConnect and 

NorthernGrid to examine potential interregional projects. Of the seven projects submitted by stakeholders, only the 

97-mile 500 kV North Gila – Imperial Valley No. 2 project between CAISO and Arizona met the requirements of an 

interregional project that connects two transmission planning regions. CAISO determined the project to be necessary 

and included the project in its regional transmission plan as a policy-driven project.88 In the Northeast, eight states 

submitted a request to the Department of Energy to form a Collaborative on Interregional Transmission seeking to 

expand interregional ties and enhance system reliability.89

Evolving Natural Gas Infrastructure Needs 

Infrastructure needs for the U.S. natural gas pipeline system over the past decade have been mainly driven by 

increasing demand in the South-Central region, namely, Texas, Louisiana, and other parts of the Gulf Coast. This 

strong regional demand, along with production from Marcellus and Utica shale formations in the Appalachian Basin, 

has changed long standing natural gas flow patterns.90

The South-Central region has experienced a significant transformation, requiring new infrastructure build-out for 

LNG. What used to be primarily a natural gas supply market is becoming the center of demand growth from LNG 

exports and pipeline exports to Mexico, both of which make the region a destination for gas supply. A decade ago, the 

opposite trend was the case, and natural gas from the South-Central region was transported to population centers in 

the Northeast.91 The United States began exporting LNG in February of 2016.92 In 2023 LNG exports averaged 11.5 Bcfd. 

In addition, pipeline exports to Mexico averaged 6.8 Bcfd in 2023. These volumes demonstrate the extent to which 

international exports drive demand in the South-Central region. Consistent with this trend, EIA’s pipeline project 

database indicates that for 2019 to 2023, Commission-jurisdictional incremental pipeline capacity additions in the 

South-Central region that went into service totaled 14.2 Bcfd, approximately 43% of total interstate capacity additions. 

Half of the South-Central region projects were to provide LNG feedstock. See the Natural Gas Pipeline Infrastructure

Section in the Energy Fundamentals Almanac for more details on notable projects. 

87. MISO, 2023 MISO Transmission Expansion Plan (Nov. 2023), https://cdn.misoenergy.org/MTEP23%20Full%20Report630587.pdf. 

88. CAISO, California ISO 2022-2023 Transmission Plan, at 9, (May 10, 2023), https://www.caiso.com/InitiativeDocuments/Revised-Draft-2022-2023-Transmission-Plan.pdf.

89. National Association of State Energy Officials, Northeast States Propose Interregional Transmission Collaborative (July 7, 2023), https://www.naseo.org/news-article?NewsID=3899. 

90. For more on U.S shale gas development and its impact, see the Natural Gas Supply section at P. 6 in FERC’s Energy Primer: A Handbook for Energy Market Basics, https://www.ferc.

gov/media/energy-primer-handbook-energy-market-basics.

91. EIA, Increases in natural gas production from Appalachia affect natural gas flows (Mar 12, 2019), https://www.eia.gov/todayinenergy/detail.php?id=38652. 

92. EIA, U.S. LNG export capacity to grow as three additional projects begin construction (Sep. 6, 2022), https://www.eia.gov/todayinenergy/detail.php?id=53719.
22 n 2023 STATE OF THE MARKET 

93. Bentek, Regional Balances Reports Cell Model Natural Gas (Dec. 24, 2023).

94. Jinjoo Lee, Utilities Get an Inflation Shock, The Wall Street Journal (Jan. 3, 2024), https://www.wsj.com/finance/investing/utilities-get-an-inflation-shock-cb821c4e. 

Figure 12: U.S. Interstate Natural Gas Pipeline In-Service Capacity Additions by Region

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

0

5

10

15

20

25

South Central Northeast Midwest Southeast Mountain Pacific

Bcfd

Source: EIA Natural Gas Pipeline Projects Data.

In 2023, the Northeast was a net supplier of natural gas with a yearly average of 13.4 Bcfd outflows.93 In contrast, in 

2013, the Northeast market was a net consumer of natural gas with a yearly average inflow of 4 Bcfd. The Northeast 

has been a net exporter since early 2016, a result of several pipeline reversals and expansions. Such projects as the 

Access South Project and Adair Southwest Project by Texas Eastern Transmission, and the Leach Xpress project by 

Columbia Gas Transmission, contributed to the high levels of capacity additions in the Northeast seen in 2017 and 

2018 as shown in Figure 12. 

Rising Capital Costs and Infrastructure Investment

Rising interest rates increased the costs of financing capital-intensive investments such as new electric generation 

facilities, natural gas pipeline infrastructure, and transmission infrastructure. Higher interest rates also generally 

increase the return that utility investors expect to earn from their energy assets.94 Interest rates in the United States 

began to rise sharply during the first half of 2022 and continued to rise through 2023. The effective federal funds rate, 

the interest which banks charge one-another for overnight loans, rose from 0.08% in early 2022 to 5.33% in December 

2023 after being close to zero for two years. 
2023 STATE OF THE MARKET n 23

Increased costs have threatened the economic viability of certain U.S. offshore wind projects. Some developers 

entered into power purchase contracts with load serving entities at prices the developers now claim are too low to 

cover their increased capital costs. In 2023, large offshore-wind developers such as Orsted, BP, and Equinor collectively 

wrote off $4.8 billion of wind projects as their contracts to supply power no longer covered the rising costs of building 

offshore wind facilities.95 In light of similar financing issues, in September 2023, six governors wrote an open letter 

to the President requesting federal assistance to ensure that offshore wind development remained economically 

viable in the face of an “orders of magnitude” increase in project costs.96 Illustrating this change in costs, the National 

Renewable Energy Laboratory estimated that high inflation and capital costs had raised the costs of constructing 

offshore wind projects by 11% to 30%.97 Several states have scheduled additional solicitations for offshore wind 

projects to make up for the cancelled projects, and these solicitations could provide an opportunity for offshore wind 

developers with cancelled contracts to rebid their projects.98

95. Giulia Petroni, Wind Power Write-Downs Cast Shadow Over Industry Outlook, Wall Street Journal (Nov. 1, 2023), https://www.wsj.com/articles/wind-power-write-downs-castshadow-over-industry-outlook-578db3f7. 

96. American Clean Power Association, Letter from Governors to President Biden Concerning Offshore Wind Power Projects (Sept. 13, 2023), https://cleanpower.org/wp-content/

uploads/2023/09/Governors-Offshore-Wind-Letter_ACP.pdf. 

97. National Renewable Energy Laboratory, Offshore Wind Market Report: 2023 Edition, at xiii. https://www.energy.gov/sites/default/files/2023-09/doe-offshore-wind-market-report2023-edition.pdf. 

98. E.g., Diana DiGangi, New Jersey approves two offshore wind projects totaling 3.7 GW Utility Dive (Jan. 25, 2024), https://www.utilitydive.com/news/new-jersey-offshore-windcapacity-project-awards-invenergy-energyre-totalenergies/705553/. Diana DiGangi, Developers rebid offshore wind contracts in New York’s fourth solicitation as Equinor and BP split 

Utility Dive (Jan. 29, 2024), https://www.utilitydive.com/news/offshore-wind-new-york-developers-rebid-equinor-bp-orsted-eversource-rwe-national-grid/705852/.

CONCLUSION

In 2023, across most of the United States, natural gas prices declined from 2022 levels due to increased natural 

gas production and a mild winter that reduced natural gas demand for space heating. Lower natural gas prices led 

to lower electricity prices because natural gas power plants often set the price as the marginal resource type in 

competitive markets. Meanwhile, the nation’s electricity resource mix continued to change, consistent with longerterm industry trends of coal plant retirements and natural gas, wind, and solar resource additions. Several RTOs/ISOs 

reformed their energy and ancillary services markets or capacity markets to reflect these trends and address emerging 

system needs, such as the need for increased operational flexibility. The nation in 2023 also saw a significant addition 

of solar capacity—more than double that of wind, battery, or natural gas resources. Nevertheless, natural gas capacity 

continued to have the highest share of the nation’s installed generation capacity, followed by coal, wind, and nuclear 

capacity. Focusing on the generation mix, natural gas resources had the highest share of electricity generation in 2023, 

followed by nuclear, coal, wind, hydro, and utility-scale solar resources. Hot summer temperatures contributed to 

higher electricity consumption in ERCOT, MISO, and SPP compared to each RTO/ISO’s ten-year average. In natural gas 

markets, increased exports and demand from natural gas power plants drove total demand to historically high levels 

even though natural gas demand in the residential and commercial sector was lower year-over-year. 

Actual and forecasted load growth, the changing resource mix, projected weather conditions, and evolving reliability 

concerns prompted transmission providers to identify new transmission needs. Across the country, developers in 2023 

completed more than 500 transmission projects to support a more economic and reliable electricity transmission 

system. In addition, pipeline companies in 2023 expanded the U.S. natural gas pipeline system in patterns consistent 

with buildout over the past decade, which has been driven largely by demand growth in the South-Central region, 

namely Texas, Louisiana, and other parts of the Gulf Coast. 
24 n 2023 STATE OF THE MARKET 

2023 ENERGY FUNDAMENTALS ALMANAC 

99. EIA, Natural gas prices fall in first half of 2023 amid record production and mild temperatures (July 24, 2023), https://www.eia.gov/todayinenergy/detail.php?id=57200. 

100. EIA, New England’s power grid weathers last weekend’s record-breaking cold and wind (Feb. 8, 2023), https://www.eia.gov/todayinenergy/detail.php?id=55459.

101. EIA, High Permian well productivity, crude oil prices drive U.S. natural gas production growth (Oct. 18, 2023), https://www.eia.gov/todayinenergy/detail.php?id=60702.

This Almanac provides more detailed information on the state of the markets in 2023 discussed above, including 

additional information on market fundamentals. To ensure continuity across recent State of the Markets reports, 

much of the analysis below is similar to the analysis provided in the body of the recent reports. This year, we include 

the analysis in a separate Almanac for easy reference and to focus the body of the report on the most significant 

market trends and fundamentals. 

Natural Gas Market Fundamentals

This section expands on natural gas market fundamentals for the year 2023 by detailing natural gas prices, demand, 

production, exports and imports, storage, pipeline infrastructure, and physical natural gas market trading. 

NATURAL GAS PRICES 

Natural gas spot prices throughout the United States decreased significantly from 2022 to 2023, with major natural 

gas trading hubs showing year-over-year price declines between 29% and 73%, as shown below in Figure 13. The 

benchmark price at Henry Hub averaged $2.53/MMBtu in 2023, a significant decline (60%) from the $6.38/MMBtu 

average in 2022. In the first quarter of 2023, relatively mild weather reduced natural gas space heating demand across 

the United States while record-high domestic production put downward pressure on prices.99

Despite the warmer-than-normal, some regions experienced short bouts of cold winter weather in the beginning of 

2023 that affected demand for space heating. In the West, pipeline constraints due to colder weather caused natural 

gas prices to soar at SoCal Gas Citygate outside Los Angeles on January 4, 2023 ($26.41/MMBtu), and PG&E Citygate 

near the Bay Area on January 13, 2023 ($26.46/MMBtu). In the East, constrained import capacity during a cold snap100

on February 3 and 4, 2023, caused prices at the Algonquin Citygates, a Boston area hub, to reach as high as $66.37/

MMBtu. 

Rising production in West Texas and the Appalachian Basin helped the United States reach record annual production 

levels (see the Natural Gas Production section) resulting in significant year-over-year price declines at production 

hubs.101 The annual average price of natural gas at the Waha hub in West Texas, a Permian Basin hub, declined by 

$3.67/MMBtu (or 71%) from 2022 levels. Furthermore, prices at the Waha hub fell into negative territory in October 

2023 due to maintenance events along regional pipelines, namely, the Gulf Coast Express Pipeline and the Permian 

Highway Pipeline, which limited regional takeaway capacity from the West Texas market. As a result, the annual 

average natural gas price at Waha hub in 2023 was $1.52/MMBtu – the lowest of the major hubs in 2023.
2023 STATE OF THE MARKET n 25

Figure 13: Average Natural Gas Spot Prices at Major Trading Hubs in 2022 and 2023 ($/MMBtu)

Trading Hub 2023 2022 Change % Change

SoCal Gas Citygate $6.60 $9.26 -$2.66 -29%

PG&E Citygate $6.09 $9.63 -$3.54 -37%

NWP-Rockies $3.32 $6.90 -$3.58 -52%

NGPL-Midcon $2.17 $5.79 -$3.61 -62%

Waha $1.52 $5.18 -$3.67 -71%

Henry Hub $2.53 $6.38 -$3.85 -60%

Chicago Citygate $2.30 $6.10 -$3.80 -62%

Eastern Gas-S $1.63 $5.51 -$3.87 -70%

Transco Zone 6 N.Y. $1.93 $7.09 -$5.16 -73%

Algonquin Citygate $2.94 $9.15 -$6.21 -68%

Source: S&P Global Commodity Insights.

NATURAL GAS DEMAND

In 2023, demand for natural gas in the United States exceeded 100 Bcfd on average for the first time, while domestic 

consumption of natural gas grew for the second straight year. Power burn—the largest component of U.S. natural 

gas demand at 34.5% in 2023—reached a new annual average high of 35.4 Bcfd after growing 7% year over year, as 

shown in Figure 14. As lower natural gas prices and coal power plant retirements contributed to higher natural gas 

generation, power burn in every month of 2023 exceeded the prior year’s level and the five-year average, as shown in 

Figure 15. Net exports of natural gas increased 21% from 2022 and represented 12.7% of total U.S. natural gas demand 

in 2023 (see Natural Gas Exports and Imports section). Domestic natural gas consumption, which excludes net exports, 

is largely dependent upon manufacturing outputs and weather. The industrial sector, which relies on natural gas as a 

feedstock in many processes, grew 2% in 2023. Residential and commercial demand for natural gas tends to be highly 

dependent on weather, which drives natural gas consumption for space heating.
26 n 2023 STATE OF THE MARKET 

Figure 14: U.S. Natural Gas Demand by Sector Bcfd

0

20

40

60

80

100

2019 2020 2021 2022 2023

Net Exports Electric Power Residential and Commercial Industrial Other

13 Bcfd

21%

35 Bcfd

7%

23 Bcfd

-8%

21 Bcfd

2%

9 Bcfd

3%

Source: EIA Natural Gas Consumption by End Use.

Figure 15: U.S. Power Burn by Month

5

10

15

20

25

30

35

40

45

0

50

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2023 2022 5 Year Average

Bcfd

Source: EIA Natural Gas Consumption by End Use.

NATURAL GAS PRODUCTION

U.S. natural gas production in 2023 saw a year-over-year increase of 4.19 Bcfd and an all-time high monthly average of 

106 Bcfd. Most of the production continued to come from shale rather than conventional formations, with shale gas 

comprising approximately 79% of the annual dry gas produced since 2021. The Marcellus Basin in the East continued 

to dominate with 26 Bcfd of annual production, followed by Permian’s 16 Bcfd (in Texas) and Haynesville’s 15 Bcfd (on 

the Texas Louisiana border) (Figure 16). In the past five years, annual production from the Permian and Haynesville 

Basins has approximately doubled. In contrast, smaller basins have seen year-on-year declines in production. 
2023 STATE OF THE MARKET n 27

102. Volume of available FERC-authorized export liquefaction capacity varied in 2023 with the 2.4 Bcfd Freeport export terminal coming fully back online on Mar. 8, 2023 and the 

addition of Venture Global’s Calcasieu Pass 0.6 Bcfd Units 7-9 in Oct. 2023; See FERC, North American LNG Export Terminals – Existing, Approved not Yet Built, and Proposed (Dec. 31, 

2023), https://www.ferc.gov/media/us-lng-export-terminals-existing-approved-not-yet-built-and-proposed.

Figure 16: Dry Natural Gas Production by Formation 

0

20

40

60

80

100

2018 2019 2020 2021 2022 2023

Marcellus Permian Utica Haynesville Bakken Conventional Rest of U.S. Shale

Bcfd

Source: EIA.

NATURAL GAS EXPORTS AND IMPORTS

U.S. natural gas net exports increased from 2022 to 2023. As shown in Figure 17 and Figure 18, net exports of natural 

gas in 2023 averaged 12.8 Bcfd, up 21.8% from 10.6 Bcfd in 2022. The increase in net exports was primarily driven 

by gross exports of LNG and pipeline exports to Mexico and Canada. Specifically, daily average U.S. LNG exports 

increased by 1.3 Bcfd to 11.9 Bcfd in 2023 according to EIA monthly data, facilitated in part by of increases in available 

LNG export capacity.102 Gross imports of LNG and natural gas via pipeline decreased by 3.1% from 2022. 
28 n 2023 STATE OF THE MARKET 

103. LNG spot landed prices refers to the price that is received at the regassification terminal. International LNG spot landed prices are generally higher than the Henry Hub (the largest 

U.S. hub closest to U.S. LNG export terminals).

Figure 17: U.S. Natural Gas Exports and Imports

-10

-5

0

5

10

15

20

25

2018 2019 2020 2021 2022 2023

LNG Imports Pipeline Imports LNG Exports Pipeline Exports Net Exports

Bcfd

Source: EIA Imports and Exports by Country. Note: Negative values mean imports into the United States and positive values mean exports out of the United States.

Figure 18: U.S. Natural Gas Exports and Imports Table

Bcfd 2018 2019 2020 2021 2022 2023

Pipeline Exports 6.92 7.77 7.93 8.47 8.32 8.95

LNG Exports 2.97 4.99 6.55 9.76 10.59 11.9

Pipeline Imports -7.70 -7.37 -6.85 -7.63 -8.22 -7.98

LNG Imports -0.21 -0.14 -0.13 -0.06 -0.07 -0.04

Net Exports 1.97 5.25 7.49 10.53 10.63 12.83

Source: EIA Imports and Exports by Country. Note: Negative values mean imports into the United States and positive values mean exports out of the United States.

In contrast to the tight market conditions in 2022, improvement of global LNG supply/demand balances in 2023 drove 

down international LNG spot landed prices.103 According to IHS, international LNG spot landed prices in Europe and 

Asia averaged about $13/MMBtu in 2023, a nearly 60% decrease in average prices from 2022 for both continents. 

European natural gas inventories began the 2023 withdrawal season in November 2023 at 99% full, according to the 
2023 STATE OF THE MARKET n 29

Aggregated Gas Storage Inventory.104 Generally, global LNG markets softened somewhat in 2023 and prices were less 

volatile than in 2022. Nevertheless, geopolitical events and global uncertainty caused prices to increase near the end 

of the year in certain regions. International LNG spot landed prices increased by about $2/MMBtu in Europe and Asia 

on average, between the months of October and December 2023, in comparison to the 2023 average.105

Figure 19 shows monthly U.S. LNG exports by region. The United States exported 4.3 trillion cubic feet to 40 countries 

via vessels in 2023, with Europe and Asia as the two largest markets for U.S. LNG cargoes abroad. As in 2022, more U.S. 

LNG cargoes were delivered in 2023 to Europe than to Asia, with nearly two-thirds of total U.S. LNG volumes shipped 

to Europe. Gross pipeline exports of natural gas averaged 9.0 Bcfd in 2023, an increase of 7.6% from 8.3 Bcfd in 2022. 

In 2023, U.S. natural gas pipeline exports to Mexico increased by 7.8% to an average of 6.1 Bcfd, and exports to Canada 

increased by 6.9% to an average of 2.8 Bcfd.106

104. Gas Infrastructure Europe, Aggregated Gas Storage Inventory (Accessed Jan. 31, 2024), https://www.gie.eu/transparency/databases/storage-database/.

105. E.g., Liam Denning, No Rain in Panama Means More Pain in LNG, Washington Post (June 22, 2023), https://www.washingtonpost.com/business/energy/2023/06/22/panama-canaldrought-threatens-disruption-in-us-lng-shipments/187e9388-10de-11ee-8d22-5f65b2e2f6ad_story.html.

106. EIA, LNG Export Capacity from North America is Likely to More than Double Through 2027 (Nov. 13, 2023), https://www.eia.gov/todayinenergy/detail.php?id=60944.

Figure 19: Monthly U.S. LNG Exports by Destination Region

0

2

4

6

8

10

12

14

16

Europe Asia Rest of World

Jan-22

Feb-22

Mar-22

Apr-22

May-22

Jun-22

Jul-22

Aug-22

Sep-22

Oct-22

Nov-22

Dec-22

Jan-23

Feb-23

Mar-23

Apr-23

May-23

Jun-23

Jul-23

Aug-23

Sep-23

Oct-23

Nov-23

Dec-23

4.3 TCF

Bcfd

Source: EIA Natural Gas Exports and Re-Exports by Country.

U.S. natural gas imports primarily came from Canada, accounting for 8.0 Bcfd on average in 2023, a decrease of 2.8% 

from 8.2 Bcfd in 2022. In addition to pipeline imports, LNG imports play a meaningful role in supplying the market—

particularly in New England— during winter months. In 2023, LNG import volumes into the United States averaged 

0.04 Bcfd, 40% less than in 2022, with Trinidad and Tobago as the major supplier. 
30 n 2023 STATE OF THE MARKET 

NATURAL GAS STORAGE

Natural gas storage inventories help to balance natural gas demand and supply and are fundamental to price 

formation. Figure 20 shows U.S. natural gas storage levels rose above last year’s storage levels surpassing the five-year 

average for much of 2023 despite lessened injections.107

Relatively full levels of natural gas storage in the U.S. lower 48 states at the start of the 2023 injection period in April led 

to 11.3% less injections than in 2022 and 6.4% less than the average injections of the previous five years. As a notable 

regional variation, the Pacific region saw higher than average injections in part due to the increase in working gas 

capacity of the Aliso Canyon natural gas storage facility near Los Angeles from 41.2 billion cubic feet (Bcf) to 68.6 Bcf.108

The Northeast region, which relies on LNG storage tanks, ended the 2023 injection period 5.6% above levels at the end 

of the 2022 injection period.109

Figure 20 shows that approximately 2,006 Bcf of natural gas was injected into natural gas storage inventories in the 

2023 injection period (April-November). The 2023-2024 withdrawal period began in November 2023 with 3,836 Bcf of 

natural gas in storage, 5.3% more than the start of the 2022-2023 withdrawal period in November 2022 and 5.2% more 

than the average of the start of the previous five withdrawal periods. 

107. U.S. natural gas storage inventory data listed in this section is for the lower 48 states.

108. EIA, California Regulators Approve Increase in Working Natural Gas Storage Capacity at Aliso Canyon (Sept. 6, 2023), https://www.eia.gov/naturalgas/weekly/archivenew_

ngwu/2023/09_07/.

109. Northeast Gas Association, About LNG (Accessed February 23, 2024), https://www.northeastgas.org/about_lng.php.

110. EIA, Natural Gas Pipeline Project Tracker, https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx. 

Figure 20: Lower 48 Natural Gas Storage Inventories

Source: EIA Weekly Natural Gas Storage Report.

NATURAL GAS PIPELINE INFRASTRUCTURE

Several interstate pipelines increased their natural gas transmission capacity through project expansions in the 

year 2023, according to EIA’s pipeline project database.110 Notable expansion projects include (1) the Alberta Xpress 

upgrade project, placed in service in January 2023, adding 0.165 Bcfd in capacity from the Canadian border to the BCF
2023 STATE OF THE MARKET n 31

Gulf Coast region on the ANR pipeline, (2) TC Energy’s North Baja Xpress Project, a 0.495 Bcfd project placed in service 

in May 2023, designed to deliver natural gas to the planned Energia Costa Azul LNG export terminal project along 

Mexico’s Pacific Coast,111 and (3) Tennessee Gas’s East 300 upgrade project, a 0.115 Bcfd project placed in service in 

November 2023, providing supply to the Northeast.112

Other domestic projects have increased the routes available to shippers by adding capacity within states. Intrastate 

capacity additions in 2023 totaled 4.8 Bcfd, all of which was in Louisiana and Texas, and many of which are increasing 

takeaway capacity out of the Haynesville Basin in Louisiana and East Texas and the Permian Basin in West Texas to 

serve high-demand Gulf Coast markets. Figure 21 shows all new intrastate pipeline capacity added in 2023.113

111. North Baja Pipeline, LLC, 179 FERC ¶ 61,039 (Apr. 21, 2022).

112. Tennessee Gas Pipeline, LLC, Notification of Placing Project Facilities at Compressor Station 321 and Compressor Station 327 In-Service. Docket CP20-493 (Nov. 6, 2023), https://

elibrary.ferc.gov/eLibrary/docinfo?accession_number=20231106-5082; Gas Daily, Tennessee Gas Gets OK to Partially Start Up East 300 Upgrade as Cold Weather Hits Northeast (Nov. 

1, 2023). 

113. Some included pipelines may be subject to NGA Section 311 compliance despite classification as intrastate projects. See FERC, Intrastate Transportation (Accessed Feb. 7, 2024), 

https://www.ferc.gov/industries-data/natural-gas/intrastate-transportation.

114. National Grid LNG LLC, Letter to National Grid LNG LLC Granting the July 19, 2022, et al Request to Place the Fields Point Liquefaction Project in Service Etc. Docket No. CP16-121 (May 

15, 2023), https://elibrary.ferc.gov/eLibrary/docinfo?accession_number=20230515-3037; National Grid, Fields Point - Domestic Liquefied Natural Gas (LNG) in New England (Accessed 

Sept., 2023), https://www.nationalgridus.com/Fields-Point/.

115. Venture Global Calcasieu Pass, LLC, Letter to Venture Global Calcasieu Pass, LLC Authorizing the Modified Commissioning Plan to Place Phase 3 Facilities In-Service by Individual 

Systems or Equipment, Etc. Docket No. CP15-550 (Oct. 26, 2023), https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20231026-3024.

Figure 21: Intrastate Pipeline Capacity Additions 2023

Project Name Pipeline Operator Name State Capacity (Bcfd)

Acadian Haynesville Extension Enterprise Products Partners LA 0.40

Eagle Ford Project Kinder Morgan Tejas Pipeline TX 2.00

Louisiana Energy Access Project Expansion Phase 1 DTE Midstream LA 0.30

Oasis Pipeline Modernization Project Energy Transfer TX 0.06

Permian Highway Pipeline Expansion Kinder Morgan Energy Partners TX 0.55

Spears Expansion Project Howard Energy Partners TX 1.00

Whistler Pipeline Expansion MPLX, WhiteWater TX 0.50

Source: EIA, Natural Gas Pipeline Project Tracker, https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx. 

.

In addition to pipeline projects, National Grid added liquefaction capability to its existing LNG storage facility, Fields 

Point LNG in Rhode Island, allowing National Grid to diversify winter peaking supplies by bringing in natural gas by 

pipeline instead of transporting LNG by truck.114 Total liquefaction capacity for U.S. LNG export terminals increased by 

3.0 Bcfd since last year, from 11.2 Bcfd to 14.2 Bcfd, with Freeport LNG coming fully back online in March 2023 and the 

in-service authorization of Venture Global’s Calcasieu Pass Units 7-9 in October 2023. 115
32 n 2023 STATE OF THE MARKET 

116. Platts and NGI both include fixed-price transactions from the InterContinental Exchange (ICE) to increase the liquidity of their price indices. Commission staff analysis of the 

estimated volumes reported to price index developers via the Form No. 552 does not include supplemental information from ICE.

Figure 22: Comparison of Fixed-Price and Physical Basis Transactions and Index-Based Transaction Volumes

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Fixed-Price & Physical Basis Index-Based Transactions

Number of Transactions

Source: FERC Form 552 Data.

PHYSICAL NATURAL GAS MARKET TRADING 

The FERC Form No. 552 requires market participants to provide an annual summary of the physical natural gas 

sales and purchases made in a calendar year. This information, reported May 1 of each year, helps the Commission 

understand the types of transactions market participants make when buying or selling natural gas in the next-day or 

next-month physical natural gas markets. The FERC Form No. 552 data for 2022, the latest data available at the time 

of publication, shows the majority of the physical natural gas market continues to be represented by index-based 

transactions (86%) while fixed-price transactions (a subset of which are reported to price index developers to form 

natural gas price indices) continue to represent a relatively small share of the total physical natural gas market (14%). 

Robust reporting of fixed-price transactions to price index developers helps ensure natural gas indices remain liquid, 

resulting in accurate and reliable natural gas prices. 

Compared with the previous reporting year (2021), the volume of fixed-price and physical basis transactions increased 

by 1% and the volume of index-based transactions increased by 3% in 2022, as shown in Figure 22. Since 2009, 

the volume of index-based transactions has increased by 64%, and the volume of fixed-price and physical basis 

transactions declined by 34%. Data from FERC Form No. 552 suggests that in 2022, for every MMBtu of fixed-price 

or physical basis transactions reported to price index developers, 23 MMBtu were settled on index-based prices, 

compared to 21.2 MMBtu in 2021 and 16 MMBtu in 2020.116
2023 STATE OF THE MARKET n 33

The Commission’s 2022 Revised Policy Statement modified the Commission’s price index policy to encourage 

additional fixed-price reporting to price index developers by reducing the burden for market participants who 

voluntarily report their transactions.117 These modifications became effective on January 1, 2023. 

Electricity Market Fundamentals

This section on electricity market fundamentals for the year 2023 covers wholesale electricity prices, demand, 

electric generation and capacity, transmission infrastructure, and generators requesting to interconnect to the 

transmission system. 

WHOLESALE ELECTRICITY PRICES 

Figure 23 shows the annual average day-ahead, on-peak wholesale electricity prices at major trading hubs for 2022, 

2023, and the average from 2017-2021.118 Prices were lower in 2023 compared to 2022 overall; however, prices varied 

across regions. Compared to the five-year average prior to 2022, prices are up an average of 24% across the entire United 

States with the highest increase in the West, a smaller increase in the East, and price declines compared to the five-year 

average in SPP and MISO South. Comparing 2023 prices to the five-year average, prices have risen an average of 24% 

across all representative hubs. Prices at Mid-Columbia increased 119% from $37.02/MWh to $80.99/MWh; and prices at 

SPP North Hub fell 13% from $36.55/MWh to $31.67/MWh. Prices in the Northeast and Southeast remained relatively flat. 

117. Actions Regarding the Commission’s Policy on Price Index Formation and Transparency, and Indices Referenced in Natural Gas and Electric Tariffs, 87 FR 25237 (Apr. 28 2022) FERC 

Policy Statement, Docket No. PL20-3-000, https://www.federalregister.gov/documents/2022/04/28/2022-08972/actions-regarding-the-commissions-policy-on-price-indexformation-and-transparency-and-indices. 

118. On-peak prices are pre-defined hours of the day when electricity demand is relatively high. The exact hours vary by region. For example, according to S&P Global, peak hours 

include: NYISO, ISO-NE, PJM hour beginning (HB) 7-22, Mon.-Fri., ET (prevailing); MISO HB 6-21, Mon.-Fri., year-round EST; ERCOT, SPP HB 6-21, Mon.-Wed. CT (prevailing); CAISO HB 

6-21, Mon.-Sat. PT (prevailing). 

Figure 23: On-Peak Average Wholesale Electricity Prices at Select Trading Hubs

Five Year 

Average 

(2017-2021)

2022 Average 2023 Average Change % Change Change Five 

Year Average2023

% Change 

Five Year 

Average2023

Mid-Columbia $37.02 $97.60 $80.99 -$16.61 -17% $43.97 119%

CAISO NP15 $42.00 $93.12 $63.92 -$29.20 -31% $21.92 52%

CAISO SP15 $43.10 $88.00 $60.07 -$27.93 -32% $16.97 39%

Palo Verde $40.83 $90.10 $58.96 -$31.14 -35% $18.13 44%

ERCOT North $66.33 $77.36 $79.27 $1.91 2% $12.94 20%

SPP North Hub $36.55 $52.78 $31.67 -$21.11 40% -$4.88 -13%

MISO Indiana Hub $35.97 $82.03 $38.92 -$43.11 -53% $2.95 8%

MISO Louisiana Hub $35.87 $71.23 $33.72 -$37.51 -53% -$2.15 -6%

Into Southern $31.10 $70.78 $32.28 -$38.50 -54% $1.18 4%

PJM Western Hub $35.42 $83.59 $39.22 -$44.37 -53% $3.80 11%

NYISO Zone J $38.69 $93.45 $38.71 -$54.74 -59% $0.02 0%
34 n 2023 STATE OF THE MARKET 

Five Year 

Average 

(2017-2021)

2022 Average 2023 Average Change % Change Change Five 

Year Average2023

% Change 

Five Year 

Average2023

ISO-NE Internal Hub $40.20 $92.17 $41.02 -$51.15 -56% $0.82 2%

Source: S&P Global Capital IQ.

Figure 24 shows how wholesale electricity prices trended across the quarters of 2023 at four representative trading 

hubs. During the first quarter, prices in NYISO and ISO-NE were elevated due to a cold weather spell in February. NYISO 

saw an average first quarter price of $45.05/MWh with the latter half of the year averaging at $38.93/MWh; ISO-NE saw 

first quarter prices at $51.98/MWh while the rest of the year sat at $37.35/MWh. Due to high natural gas prices, CAISO’s 

NP15 saw an average first quarter prices of $100.31/MWh which fell to an average of $51.76/MWh for the rest of the 

year.119 At MISO’s Indiana Hub, prices were high during the second and third quarters as hot weather drove up demand. 

119. CAISO, Q1 2023 Report on Market Issues and Performance (Sep. 19, 2023), https://www.caiso.com/Documents/2023-First-Quarter-Report-on-Market-Issues-and-PerformanceSep-19-2023.pdf.

Figure 24: On-Peak Average Quarterly Wholesale Electricity Prices at Select Trading Hubs in 2023

15

30

45

60

75

90

105

120

Average Quarterly Price ($/MWh)

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

NYISO Zone J MISO Indiana Hub ISO-NE Internal Hub CAISO NP15

0

Source: S&P Global Capital IQ.
2023 STATE OF THE MARKET n 35

ELECTRICITY DEMAND

Total electricity consumption decreased in most RTOs/ISOs in 2023 relative to the previous year, after an increase 

in 2022, as shown in Figure 25.120 By contrast, total consumption in ERCOT increased 3.4% on top of a 9.5% yearover-year increase between 2021 and 2022. The largest decreases among RTOs/ISOs were in NYISO, which saw 

a 3.7% decrease, and ISO-NE, which saw a 3.6% decrease. As is typical, weather had a large impact on electricity 

consumption in 2023 due to demand for both heating and cooling. Milder winter conditions in the Midwest and 

Northeast reduced consumption relative to 2022. For example, electricity consumption in ISO-NE during January 

2023 was 10% lower than the same time in 2022. Also in 2023, hotter summer weather drove up consumption 

in the South and Central United States. ERCOT saw double-digit increases in electricity consumption for the 

summer and fall with a 17% increase in August, 15% in September, and 10% in October compared to the year prior. 

120. These figures include net interchange used to serve load within each footprint minus exports to other markets. These figures do not include behind-the-meter generation or load 

which is not tied to the wholesale markets.

Figure 25: Total Annual Electricity Consumption by RTO/ISO

100

200

300

400

500

600

700

800

900

1,000

Total Consumption (TWh)

2019 2020 2021 2022 2023

CAISO WECC* ERCOT SPP MISO PJM SERC NYISO ISO-NE

0

Source: Hitachi ABB Power Grids Velocity Suite based on RTO/ISO Total Load Dataset and EIA-930. WECC* refers to WECC without CAISO. Staff removed EIA-930 intervals with negative 

or missing load values. 

Prolonged periods of hot weather have contributed to higher peak electricity demand in some RTOs/ISOs in recent 

years. Peak electricity demand in ERCOT and SPP reached a record high during hot weather events in the summer of 

2023. In MISO, peak electricity demand in August 2023 approached but did not surpass the record peak demand that 

was set in 2011. Maximum daily electricity consumption, which is the most electricity consumed during a single day 

of the year (adding the hourly average demand for all hours of the day), reached a new high in ERCOT, SPP, and MISO 

in 2023 compared to the prior ten years with data available. In CAISO, peak electricity demand and maximum daily 

electricity demand reached a record high in 2022 due to hot summer weather and fell slightly in 2023. Annual peak 

electricity demand has declined or remained relatively flat in PJM, NYISO, and ISO-NE.
36 n 2023 STATE OF THE MARKET 

Looking back at a longer timeframe, Figure 26 below shows the percentage change in total seasonal electricity 

consumption from the most recent five years compared to the prior five years. ERCOT and SPP had the highest 

percentage increase in seasonal loads between the 2014-2018 and 2019-2023 time periods, and CAISO, 

NYISO, and ISO-NE experienced low or moderate declines in seasonal loads over the same time periods. 

121. These figures include exports used to serve load in other markets. These figures do not include behind-the-meter generation or load, which is not tied to the wholesale markets. 

EIA estimates that small scale solar installations (less than 1MW in nameplate capacity) produced an additional 12.3 GWh of generation in 2023 compared to 2022. See EIA, Electric 

Power Monthly Table 1.1.A (Feb.2023).

Figure 26: Total Electricity Consumed by Season, 2014-2018 compared to 2019-2023.

16%

12%

8%

4%

-4%

-8%

ISO-NE

WinterSum

mer

SERC

WinterSum

mer

PJM

Sum

mer

Winter

MISO

WinterSum

mer

SPP

WinterSum

mer

ERCOT

WinterSum

mer

NYISO

WinterSum

mer

WECC*

Winter

Sum

mer

CAISO

Winter

Sum

mer

0%

Source: Hitachi ABB Power Grids Velocity Suite based and EIA-930. Note summer includes June, July, and August. Winter includes December, January, and February. Data for SERC 

and WECC is limited to the years 2015 to 2023. SERC data includes balancing authority areas that were members of the Florida Reliability Coordinating Council prior to 2019. Staff 

removed EIA-930 intervals with negative or missing load values.

ELECTRICITY SUPPLY: ANNUAL NET GENERATION BY FUEL TYPE

Net generation in the United States in 2023 was roughly equal to 2022 levels, with total net generation of 4,022 

terawatt-hours (TWh) in 2023, a decline of 1.3% compared to 2022.121 Nevertheless, the proportion of annual net 

generation by fuel type changed in 2023 as shown in Figure 27. Total coal generation declined by 19% in 2023 

compared to 2022. In contrast, natural gas generation increased by 7% and accounted for 42.1% of total generation 

in 2023, increasing from 38.8% in 2022. Renewable generation also increased in 2023. Utility-scale solar generation 

increased by 14%, while wind generation declined by 2%. In 2023, utility-scale solar and wind generation combined 

accounted for 14.7% of total electric generation output in the lower 48 states compared to 13.8% in 2022. 
2023 STATE OF THE MARKET n 37

Figure 27: Aggregate Net Generation by Fuel Type

2022 2023

Resource Type % TWh % TWh

Natural Gas 38.8% 1,583 42.1% 1,695 

Coal 20.3% 826 16.7% 671

Nuclear 18.9% 772 19.3% 775 

Wind 10.7% 434 10.6% 425 

Hydro 6.2% 254 5.9% 239 

Solar 3.5% 143 4.1% 163

Oil 0.4% 15 0.3% 11 

Other 1.2% 48 1.1% 43 

Source: EIA Electric Power Monthly. Electric generation from utilities and independent power producers. Data excludes industrial, commercial, and residential sectors. 

Figure 28 shows the generation mix by region in 2022 and 2023. Wholesale markets where solar and wind generation 

have a significant and growing presence include SPP, CAISO, ERCOT, and MISO. Hydro generation remains a significant 

source of renewable generation in several regions, particularly non-CAISO WECC, NYISO, ISO-NE, and CAISO. 

Figure 28: Net Generation by Fuel Type and Region in 2022 and 2023. 

100%

0%

20%

40%

60%

80%

CAISO

2022 2023

WECC*

2022 2023

ERCOT

2022 2023

SPP

2022 2023

MISO

2022 2023

PJM

2022 2023

SERC

2022 2023

NYISO

2022 2023

ISO-NE

2022 2023

Nuclear Coal Natural Gas Hydro Solar Wind Oil Other

Source: EIA Form 930. Data exclude Alaska and Hawaii. WECC* refers to WECC without CAISO.
38 n 2023 STATE OF THE MARKET 

ELECTRICITY SUPPLY: RESOURCE CAPACITY ADDITIONS AND RETIREMENTS

Figure 29 shows the total nameplate capacity in the United States as of the end of 2023 and the total shares 

of nameplate capacity by resource type across both RTOs/ISOs and other regions as of January 2024. At 

the end of 2023, natural gas represented 45% of the capacity mix across the United States, followed by coal 

at 15%, wind at 12%, nuclear at 8%, hydro at 8%, solar at 7%, oil at 2%, other at 2%, and batteries at 1%. 

Figure 29: Total Nameplate Capacity and Percentage Share by Resource Type Across the United States 

100%

80%

60%

40%

20%

0%

SPP MISO PJM SERC NYISO ISO-NE

80 174 143 101 198 218 265 44 38

Total Nameplate Capacity (GW)

CAISO WECC* ERCOT

Nuclear Coal Natural Gas Hydro Solar Wind Oil Batteries Other

Source: EIA Form-860M, February 2024 Release. Data exclude Alaska and Hawaii. WECC* refers to WECC without CAISO.

With respect to generation capacity additions by resource type across the United States in 2023, most came from solar, 

natural gas, battery storage, and wind resources. Among the RTOs/ISOs, SERC added the most generating capacity 

with 7.7 GW coming on-line in 2023. The largest resource additions across the United States in 2023 included the 

natural gas combined-cycle Guernsey Power Station plants in PJM in Ohio (2,055 MW), the natural gas combined-cycle 

CPV Three Rivers Energy Center plants in PJM in Illinois (1,300 MW), the Vogtle Unit 3 nuclear facility in SERC in Georgia 

(1,114 MW), the High Banks Wind facility in SPP in Kansas (643 MW), and two 500 MW solar farms, the Roseland Solar 

Project and Aktina Solar, both in ERCOT in Texas. 
2023 STATE OF THE MARKET n 39

Figure 30: 2023 Nameplate Capacity Additions by Resource Type Across the United States

Nuclear Coal Natural Gas Solar Wind Oil Batteries Other

Nameplate Capacity (GW)

ISO-NE

0

1

2

3

4

5

6

7

8 7.8 7.4

7.2

5.7

5.2 4.8

2.0

0.8

0.2

SERC ERCOT PJM CAISO WECC* MISO SPP NYISO

Source: EIA-Form 860M, February 2024 Release. Note: Expected and actual additions and retirements from January 2023 through December 2023. Data exclude Alaska and Hawaii. 

WECC* refers to WECC without CAISO.

Figure 31: Battery Storage Nameplate Capacity Additions Across the United States from 2013 to 2023

1

2

3

4

5

6

7

0

8

Nameplate Capacity (GW)

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

0.0 0.0 0.1 0.2 0.2 0.2

0.6

3.4

4.1

6.1

0.1

ISO-NE NYISO SERC PJM MISO SPP ERCOT WECC* CAISO

Source: EIA-Form 860M, February 2024 Release. Data exclude Alaska and Hawaii. 

Battery storage additions have grown significantly since 2013, with nearly 15 GW of battery storage capacity entering 

operation. Annual battery storage additions have increased from 10 MW in 2013 to over 6 GW in 2023. Figure 31 shows 

that most of the battery storage additions over the 2013 to 2023 period —50% of total capacity additions since 2013—
40 n 2023 STATE OF THE MARKET 

occurred in CAISO, although most other regions also added battery storage capacity. According to EIA estimates, the 

largest-battery storage capacity additions by RTO/ISO over the last 10 years, were in: CAISO (7.9 GW), ERCOT (3.4 GW), 

WECC* (2.0 GW), SERC (0.7 GW), ISO-NE (0.3 GW), PJM (0.3 GW), NYISO (0.2 GW), and MISO and SPP with less than 100 

MW each. 

Continuing the trend of recent years, more U.S. coal capacity retired in 2023 than capacity of any other resource 

type. Among the RTOs/ISOs, PJM retired the most total capacity, with 6.8 GW of retirements in 2023. Overall, the 

largest retirements in 2023 included the following coal and gas plants: the W.H. Sammis coal power plant in PJM 

in Ohio (1,360 MW), the Joliet 29 natural gas power plant in PJM (1,320 MW), the Bull Run coal power plant in 

SERC in Tennessee (950 MW), the Yorktown natural gas power plant in PJM in Virginia (882 MW), the Sherburne 

County coal power plant in MISO in Minnesota (765 MW), and the Pirkey coal power plant in SPP in Texas (721 MW).

Figure 32: 2023 Nameplate Capacity Retirements by Resource Type across the United States Nameplate Capacity (GW)

-8

-7

-6

-5

-4

-3

-2

-1

0

-6.8

-3.0

-1.7

-0.9 -0.7 -0.6 -0.4

-0.1

-0.9

PJM MISO SERC ERCOT CAISO SPP NYISO ISO-NE WECC*

Nuclear Coal Natural Gas Solar Wind Oil Batteries Other

Source: EIA Form -860M, February 2024 Release. Note: Expected and Actual Additions and Retirements from January 2023 through December 2023. Data exclude Alaska and Hawaii. 

WECC* refers to WECC without CAISO. 
2023 STATE OF THE MARKET n 41

Some RTOs/ISOs administer a centralized capacity market to ensure that load-serving entities procure 

sufficient capacity to meet system reliability targets.122 Capacity auctions held in 2023, for varying capacity 

commitment periods, cleared prices from $10/MW-day to $135.70/MW-day, as shown in Figure 33.123

Capacity prices cleared lower in ISO-NE, PJM and MISO than in 2022, while prices cleared higher in NYISO. 

MISO’s capacity prices saw the largest year-over-year decrease. Capacity prices across the RTOs/ISOs were 

largely driven by capacity supply changes, lower-priced capacity offers, or delayed resource retirements.124

122. For more information on capacity markets, see the RTO/ISO Capacity Markets and Resource Adequacy section on P. 72 in FERC’s Energy Primer: A Handbook for Energy Market Basics, 

https://www.ferc.gov/media/energy-primer-handbook-energy-market-basics.

123. Capacity prices in Figure 33 refer to NYISO’s monthly spot auctions for the New York City Control Area, ISO-NE Rest of Pool, PJM Rest of RTO, and MISO’s spring and summer capacity 

prices across all zones. 

124. MISO, Planning Resource Auction, Results for Planning Year 2023-24 (May 19, 2023), https://cdn.misoenergy.org/2023%20Planning%20Resource%20Auction%20(PRA)%20

Results628925.pdf; ISO-NE, 2022 Annual Markets Report (June 5, 2023), https://www.iso-ne.com/static-assets/documents/2023/06/2022-annual-markets-report.pdf; Potomac 

Economics, Quarterly Report on the NYISO Electricity Markets, Third Quarter 2023 (Nov. 2023), https://www.nyiso.com/documents/20142/38026057/NYISO-Quarterly-Report-2023-

Quarter-3.pdf. 

Figure 33: Capacity Prices Across RTOs/ISOs from Auction Year 2013 to 2023

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

0

200

 400

0

200

400

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

0

100

200

MISO

0

100

200

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

NYISO PJM

ISO-NE

Source: RTO/ISO data via Hitachi Energy. NOTE: The range of the y-axis varies. 
42 n 2023 STATE OF THE MARKET 

Figure 34 below shows how capacity market costs compare to the “all-in” wholesale energy costs for select RTOs/ISOs 

and sub-regions in 2023.125

125. All-in Costs are defined as follows: NYISO All-in Cost is the sum of NYISO Operations, Uplift, Ancillary Services, Capacity, and Energy; ISO-NE All-in Cost is the sum of Energy, 

Capacity, Net Commitment Period Compensation, Ancillary Services, and Mystic Cost of Service; PJM All-in Cost is reported as the sum of Energy, Capacity, Transmission, Ancillary 

Services, Administration, Uplift, Demand Response, and Other, to better align with the other RTOs/ISOs transmission costs were subracted from the PJM All in Cost in Figure 34, 

MISO All-in Cost is the sum of Capacity, Ancillary Services, Energy, and Uplift. Potomac Economics, Quarterly Report on the NYISO Electricity Markets, Third Quarter 2023 at 22 (Nov. 

2023), https://www.nyiso.com/documents/20142/38026057/NYISO-Quarterly-Report-2023-Quarter-3.pdf; ISO New England Inc. Internal Market Monitor, Summer 2023 Quarterly 

Markets Report, at 14 (Oct. 27, 2023), https://www.iso-ne.com/static-assets/documents/100004/2023-summer-quarterly-markets-report.pdf; Monitoring Analytics, LLC, 2023 

Quarterly State of the Market Report for PJM: January through September, Section 1 Introduction at 20 (Nov. 9, 2023), https://www.monitoringanalytics.com/reports/PJM_State_

of_the_Market/2023/2023q3-som-pjm-sec1.pdf; Potomac Economics, IMM Quarterly Report: Fall 2023 at 11 (Dec. 5, 2023), https://www.potomaceconomics.com/wp-content/

uploads/2023/12/IMM-Quarterly-Report_Fall-2023-Final.pdf. 

126. Potomac Economics, Quarterly Report on the NYISO Electricity Markets, Third Quarter 2023 at 4, 18, 22 (Nov. 2023), https://www.nyiso.com/documents/20142/38026057/NYISOQuarterly-Report-2023-Quarter-3.pdf; ISO New England Inc. Internal Market Monitor, Summer 2023 Quarterly Markets Report, at 8, 14 (Oct. 27, 2023), https://www.iso-ne.com/staticassets/documents/100004/2023-summer-quarterly-markets-report.pdf; Monitoring Analytics, LLC, 2023 Quarterly State of the Market Report for PJM: January through September, 

Section 1 Introduction at 20 (Nov. 9, 2023), https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2023/2023q3-som-pjm-sec1.pdf; Potomac Economics, 

IMM Quarterly Report: Spring 2023 at 8 (June 13, 2023), https://potomaceconomics.com/wp-content/uploads/2023/06/IMM-Quarterly-Report_Spring-2023-MSC.pdf; Potomac 

Economics, IMM Quarterly Report: Fall 2023 at 11 (Dec. 5, 2023), https://www.potomaceconomics.com/wp-content/uploads/2023/12/IMM-Quarterly-Report_Fall-2023-Final.pdf.

Figure 34: Capacity Costs as Percentage of All-in Costs in 2023 Across RTOs/ISOs

RTO/ISO (Zone) Period in 2023 Capacity Cost Percentage 

of All-in Cost

All-in Cost ($/MWh)

NYISO (Zone J) July-September 49% $83

ISO-NE (RTO-wide) June-September 16% $50

PJM (RTO-wide) January-September 12% $37

MISO (RTO-wide) September-November 6% $33

Source: Market monitor data.126

ELECTRICITY TRANSMISSION INFRASTRUCTURE

Figure 35 shows the transmission line miles that entered service in 2023 by region and driver. Most projects were 

driven by reliability needs. Reliability-driven projects represented just over 30% of all transmission projects completed 

by all RTOs/ISOs in 2023, with ERCOT and MISO having the highest shares of such projects. ERCOT completed nearly 

400 circuit miles of transmission lines designed to improve reliability, while MISO completed over 700 circuit miles 

of reliability-related projects in 2023. Across all RTOs/ISOs, transmission projects driven by aging infrastructure 

contributed over 800 circuit miles and represented the second-largest category of projects entering service in 2023, 

with nearly a quarter of these miles completed in PJM. Transmission projects driven by public policy and economic 

needs were the smallest in number in 2023. Public policy-driven transmission projects added a total of 11.4 circuit 

miles entering service in 2023, with nearly half of these miles completed in CAISO. Only three projects driven by 

economic needs were completed in 2023.
2023 STATE OF THE MARKET n 43

Figure 35: Transmission Line Miles by Region and Driver

200

400

600

800

1,000

1,200

0

1,400

Circuit Miles

Non-RTO 

East

Non-RTO CAISO ERCOT MISO SPP PJM NYISO ISO NE

West

Reliability Policy Load Growth Generation Aging Infrastructure Other

Source: The C3 LLC Group.

Figure 36 shows that most projects entering service in 2023 were at the 138kV level, with over 200 projects and nearly 

1,700 circuit miles completed. ERCOT and MISO led in the completion of transmission projects at the 138 kV level, with 

over 800 and 600 circuit miles respectively. Over 60% of transmission projects completed in 2023 fell between the 

range of 69 and 138 kV.
44 n 2023 STATE OF THE MARKET 

Figure 36: Number of Transmission Projects Completed in 2023 by Line Voltage 

50

100

150

200

250

Number of Projects

69 kV 115 kV 138 kV 230 kV 345 kV

0

Source: The C3 LLC Group.

Below are a few major projects that entered service in 2023 by region: 

• In MISO, most of the new circuit miles are designed to address reliability concerns. Ameren Illinois completed two 

of the largest reliability-driven projects (both 345 kV transmission lines) in MISO. These projects included a $115.5 

million upgrade of the 47.6-mile line between the Massac and Jordan substations, along with an upgrade of the 

50-mile line between the Jordan and Joppa substations. In terms of circuit miles, the Jordan-Joppa line rebuild 

was the largest transmission project completed in MISO during 2023.

• In PJM, completed projects primarily focused on upgrading aging infrastructure, followed by reliability-driven 

projects in 2023. AEP completed a large share of these projects, mostly in Ohio and Pennsylvania. For example, 

AEP invested $42.2 million in the rebuilding of the 19.4-mile, 138 kV line between the North Newark and Sharp 

Road substations. AEP also invested $21.75 million to upgrade the 16.7-mile, 69 kV West Rockaway Switch line. 

Both projects were completed to address aging transmission lines in Ohio. However, the largest project completed 

in PJM in 2023 targeted reliability needs in Michigan. For this project, AEP invested $84.7 million into rebuilding the 

35-mile, 69 kV line between the Pokagan and Corey substations.

• In NYISO, most of the completed projects supported generation interconnection during 2023. The largest 

generation interconnection project completed was the 99-mile, 345 kV Central East Energy Connect Project 

(formerly called the Marcy - New Scotland Upgrade Project) by LS Power Group. 

• ISO-NE transmission providers also invested in the transmission system in 2023, including Connecticut Light and 

Power’s Plumtree-Norwalk Laminated Wood Structure Replacement Program, Phase II, which upgraded Line 

3403—a 345 kV transmission line in Connecticut—at a total cost of $12.09 million. 

• SPP upgraded and expanded its transmission system to improve reliability and interconnect new generation. 

Newly completed projects include the Neset - Northshore 230-kV Transmission Line, which integrates a new 

transformer, supports load growth and connects new generation in North Dakota. The $73 million Neosho - 

Riverton 161kV line rebuild project also advanced to improve reliability in southeastern Kansas. 
2023 STATE OF THE MARKET n 45

GENERATORS REQUESTING TO INTERCONNECT

Strong renewable generation and electric storage growth in 2023 continue to prolong generator interconnection 

queue backlogs. Preliminary data from LBNL shows that there were 11,841 active requests from generators seeking 

to interconnect to the transmission system at the end of 2023, a 16% increase compared to the end of 2022. Yearover-year, the number of active interconnection requests continues to exceed the number of completed or withdrawn 

interconnection requests. Figure 37 shows that the number of active interconnection requests remaining at the end of 

the year has more than quadrupled since 2019, although the change in the active interconnection requests at the end 

of 2023 was the smallest since 2020. 

127. LBNL’s official 2023 interconnection queue data and report will be available in April 2024, at Lawrence Berkeley National Laboratory, Queued Up: Characteristics of Power Plants 

Seeking Transmission Interconnection, https://emp.lbl.gov/queues. The capacity of storage from hybrid storage and generation interconnection requests reported here excludes 

storage capacity for projects where it was not reported (missing). LBNL imputes the missing data and estimates that hybrid storage capacity was 525 GW in 2023.

Figure 37: Requests to Interconnect Year Over Year

Year Ending Remaining Interconnection Requests Change in Active Requests Compared 

to the Prior Year

Year-Over-Year Change

2019 2,801 1,052 60%

2020 4,326 1,525 54%

2021 7,182 2,856 66%

2022 10,247 3,065 43%

2023 11,841 1,594 16%

Source: Preliminary data from LBNL, Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection. NOTE: Active interconnection requests with missing dates 

are counted towards year ending 2019. Data up to 2022 are based on 2023 data.

Total capacity active in interconnection queues at the end of 2023 totaled 1,565 GW of generation, 299 GW of storage 

capacity from hybrid storage and generation interconnection requests, and 503 GW of standalone storage capacity.127

Figure 38 shows that much of this capacity comes from solar, wind, and battery storage resources, totaling nearly 

95% of the total capacity in interconnection queues as of the end of 2023, 1% higher than the prior year. Nearly half 

of the total capacity consists of solar resources, followed by storage capacity at nearly a third of the total capacity. 

The capacity from storage resource requests increased the most. Total generation capacity active in interconnection 

queues increased by 29%, storage capacity from hybrid storage and generation interconnection requests increased by 

87%, and standalone storage capacity increased by 55%, compared to the end of 2022. 
46 n 2023 STATE OF THE MARKET 

Figure 38: Cumulative Capacity in Interconnection Queues by Resource Type

Cumulative Capacity (GW)

Year Ending Wind Offshore

Wind

Solar Gas Storage 

(standalone)

Storage

(hybrid)

Other / 

Unknown

Total

2022 187 113 947 82 325 159 27 1,841

2023 246 120 1,086 79 503 299 33 2,366

% of Total 

Capacity 

(2023)

10% 5% 46% 3% 21% 13% 1% 100%

% Change in 

Total Capacity 

From 2022 to 

2023

32% 6% 15% -3% 55% 87% 22% 29%

Source: Preliminary data from LBNL, Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection. NOTE: Storage (hybrid) and Other/Unknown use LBNL’s 2023 

Preliminary Data for 2022.
2023 STATE OF THE MARKET n 47

ACKNOWLEDGEMENTS

The 2023 State of the Markets report is the result of the combined efforts of many dedicated individuals throughout 

the Commission, including many within the Division of Energy Market Assessments in the Office of Energy Policy and 

Innovation. We want to recognize the following staff for their role in developing the report.

Leah Adelman (Coordinator, Natural Gas Market Fundamentals)

Jeff Beattie (Technical Editor)

Matt Butner (Co-lead; Coordinator, Transforming Markets)

Jerry Chiang (Technical Editor)

Noa Slater (Coordinator, Electricity Market Fundamentals)

David Smith (Coordinator, Transforming Infrastructure)

Taylor Webster (Co-lead)
FEDERAL ENERGY REGULATORY COMMISSION

Office of Energy Policy and Innovation

DEPARTMENT OF ENERGY

F E D E R A L E N E R G Y R E G U L AT O RY C O M M I S S I O N

market.assessments@ferc.gov