Reference data

Energy market
statistics.

Key numbers every commercial energy buyer should have at their fingertips — rates, capacity prices, clean energy costs, deployment data, and market benchmarks.

Reference figures — 2024–2025
Commercial rates Capacity markets Clean energy costs Deployment Corporate procurement Grid & reliability Incentives

Section 01

Commercial electricity rates

Source: EIA Electric Power Monthly · 2024

US avg. commercial rate

12.7¢

per kWh, all-in retail

↑ 3% yr/yr

US avg. industrial rate

8.1¢

per kWh, large loads

↑ 2% yr/yr

Highest state (Hawaii)

36.8¢

per kWh commercial avg.

→ Stable

Lowest state (Louisiana)

8.2¢

per kWh commercial avg.

→ Stable

New England avg.

18.4¢

per kWh commercial

↓ from 2023 peak

10-yr price increase

+31%

US commercial, nominal

↑ vs. 2014
ISO / Region Avg. commercial rate (¢/kWh) Day-ahead LMP avg. ($/MWh) Peak/off-peak ratio Market type
PJM Mid-Atlantic 13.2¢ $48–$72 1.8× Nodal, capacity market
CAISO California 21.4¢ $42–$68 3.2× Nodal, RA requirements
ERCOT Texas 9.8¢ $28–$58 2.4× Nodal, energy-only
ISO-NE New England 18.6¢ $44–$78 2.1× Nodal, capacity market
NYISO New York 15.8¢ $52–$88 2.6× Nodal, capacity market
MISO Midwest 10.4¢ $32–$54 1.6× Nodal, capacity market
Non-ISO Southeast 9.6¢ N/A bilateral N/A Vertically integrated
Retail rates include energy, capacity, transmission, distribution, and ancillary service components. Day-ahead LMP ranges reflect 2023–2024 annual averages and exclude scarcity/emergency events. Peak/off-peak ratio is summer weekday peak to overnight off-peak. Sources: EIA Electric Power Monthly, ISO/RTO market reports.

Section 02

Capacity market prices

Source: PJM, ISO-NE, NYISO market reports · 2025/2026
$333
PJM RTO clearing price
2027/28 BRA ($/MW-day)
Hit FERC cap — entire RTO short
$329
PJM RTO clearing price
2026/27 BRA ($/MW-day)
Cleared July 2025 — also at cap
$65
ISO-NE FCA 18
Clearing price ($/kW-month)
2025/26 delivery year
$120–180
NYISO NYC zone ICAP
Typical range ($/kW-year)
NYC premium vs. ROS

PJM capacity price history ($/MW-day, RTO zone)

2022/23 BRADelivery year
$34
2023/24 BRADelivery year
$34
2024/25 BRAFirst spike
$270
2026/27 BRAHit FERC cap
$329
2027/28 BRAAll LDAs at cap
$333

2026/27 and 2027/28 BRAs both hit the FERC-imposed price cap. 2027/28 was the first time the entire RTO cleared at the cap — meaning capacity is short across every zone, not just constrained areas. Drivers: data center load growth, electrification, generator retirements, slow new build progressing through interconnection queue.

What capacity costs mean for buyers

Facility size CP tag (MW) Annual capacity cost
Small office 0.2 MW ~$24K/yr
Mid-size manufacturer 2 MW ~$243K/yr
Large industrial 10 MW ~$1.22M/yr
Data center 50 MW ~$6.1M/yr

Based on PJM RTO 2027/28 $333/MW-day × 365 days. Buyers who reduce their CP tag by 1 MW save ~$122K/yr in the next delivery period — and even more in constrained zones.

Capacity prices shown are clearing prices from PJM base residual auctions (BRA). Actual buyer costs depend on zone, load shape, and retailer pass-through methodology. PJM 2026/27 BRA cleared July 2025 at $329.17/MW-day; 2027/28 BRA cleared December 2025 at $333.44/MW-day — the first time the entire RTO hit the FERC-imposed price cap. Sources: PJM Capacity Market Results, ISO-NE FCM results, NYISO ICAP reports.

Section 03

Clean energy levelized costs (LCOE)

Source: Lazard LCOE 2024 · BloombergNEF

Utility-scale solar

$29–$92

per MWh, unsubsidized

↓ 90% since 2009

Onshore wind

$27–$73

per MWh, unsubsidized

↓ 71% since 2009

Offshore wind

$72–$140

per MWh (US, 2024 projects)

↑ from 2020 lows

Battery storage (4hr)

$82–$152

per MWh, standalone

↓ rapidly

Combined-cycle gas

$39–$101

per MWh, new build

↑ gas price exposure

New gas peaker

$115–$221

per MWh, OCGT

→ Solar+storage now cheaper

Battery storage installed cost trends ($/kWh, utility-scale Li-ion)

2015Early deployment
~$1,100/kWh
2018
~$750/kWh
2021
~$440/kWh
2024Current estimate
~$270/kWh
2030 targetIndustry forecast
~$150/kWh
LCOE ranges reflect geographic, project, and financing variation. Subsidized LCOEs for solar and wind are approximately 30–45% lower after ITC/PTC. Offshore wind LCOE increase reflects 2022–2024 supply chain inflation and interest rate environment. Battery cost = installed $/kWh of energy capacity for 4-hour duration system. Sources: Lazard Levelized Cost of Energy Analysis v17.0 (2024), BloombergNEF Battery Price Survey 2024.

Section 04

US renewable energy deployment

Source: EIA, SEIA, AWEA · 2024

Total solar capacity (US)

178 GW

utility-scale + distributed, 2024

↑ ~25 GW added in 2023

Total wind capacity (US)

148 GW

onshore + offshore, 2024

↑ ~7 GW added in 2023

Grid-scale battery storage

26 GW

operational capacity, 2024

↑ 80%+ yr/yr growth

Renewable share of US gen.

24%

wind + solar + hydro, 2023

↑ from 18% in 2020

Solar % of US generation

5.6%

2023 annual share

↑ fastest growing source

Interconnection queue

2,600+ GW

projects awaiting connection

↑ 5× growth since 2016

Renewable share of generation by ISO (2023)

CAISO (California)Solar + wind
~47% VRE
ERCOT (Texas)Wind #1 in US
~41% VRE
SPP (Plains)Wind-dominant
~35% VRE
MISO (Midwest)Growing fast
~22% VRE
PJM (Mid-Atlantic)Adding rapidly
~15% VRE
ISO-NE (New England)Offshore pipeline large
~14% VRE
VRE = variable renewable energy (wind + solar only, excluding hydro). Interconnection queue of 2,600+ GW represents projects that have submitted applications — historical completion rate is approximately 20–25% of queued capacity. Sources: EIA Electric Power Monthly, LBNL Electricity Markets & Policy Group interconnection queue tracker 2024.

Section 05

Corporate renewable energy procurement

Source: BloombergNEF, SEIA, RE100 · 2024

Corporate PPAs signed (2023)

46 GW

global, record year

↑ 12% vs. 2022

US corporate PPAs (2023)

~19 GW

physical + virtual

↑ largest single market

RE100 members

420+

committed to 100% renewable

↑ from 100 in 2018

Avg. US PPA tenor

15 yr

corporate offtake agreements

→ 10–20 yr range

Typical solar PPA price

$35–55

per MWh, new US contracts

↑ from 2020 lows

Typical wind PPA price

$30–50

per MWh, new US contracts

→ Broadly stable

Largest corporate PPA buyers (cumulative, all-time)

CompanyApprox. portfolio (GW)Primary instrument
Amazon~30 GW+PPA / VPPA
Meta~15 GW+PPA / VPPA
Google / Alphabet~14 GW+PPA (24/7 focus)
Microsoft~12 GW+PPA (24/7 focus)
Apple~3 GW+Direct investment

Demand response market size (US)

Program typeEnrolled capacityAnnual payments
PJM DR (total)~9,500 MW~$500M+
ISO-NE DR~1,800 MW~$200M+
NYISO DR~1,200 MW~$120M+
CAISO ELRP~2,000 MWGrowing

DR payments vary significantly with capacity market prices. PJM DR payments spiked sharply in 2024/25 with record capacity clearing prices.

Corporate PPA volumes include physical and virtual (financial) contracts. Technology companies represent approximately 40–50% of global corporate renewable procurement by volume. PPA prices are indicative for new contracts executed in 2023–2024; actual prices depend on location, tenor, project type, and market conditions. Sources: BloombergNEF Corporate Energy Market Outlook 2024, RE100 Annual Report, LBNL Tracking the Sun.

Section 06

Grid & reliability

Source: NERC, EIA, FERC · 2024

US peak demand (summer)

~800 GW

estimated 2024 max

↑ data center + EV load growth

Average US outage duration

~7 hrs

per customer per year (SAIDI)

↑ weather events increasing

ERCOT negative price hrs (2023)

~900 hrs

real-time negative prices

↑ solar curtailment growing

CAISO curtailment (2023)

~2.5M MWh

renewable energy curtailed

↑ duck curve deepening

Average interconnection wait

3–5 yrs

from application to COD

↑ queue congestion worsening

US transmission investment

$26B

annual, 2023 estimate

↑ growing but insufficient
SAIDI (System Average Interruption Duration Index) excludes major event days in some reporting. ERCOT negative price hours reflect real-time market settlement points below $0/MWh. CAISO curtailment figures represent instructed curtailment of renewable resources. Interconnection timelines vary significantly by ISO and project type. Sources: NERC 2024 Long-Term Reliability Assessment, EIA Form 861, CAISO annual curtailment report.

Section 07

IRA incentives & tax credits

Source: IRS, DOE, Treasury · 2024
$369B
Total IRA climate + energy investment
10-year budget window (2022–2032)
30%
Base ITC rate
Solar, storage, and qualifying technologies
10%
Domestic content bonus
US-manufactured components
$3/kg
Maximum 45V clean hydrogen credit
For lowest-emission electrolytic H₂
Credit / incentive Technology Base value Max with bonuses Key condition
ITC (Section 48/48E) Solar, storage, wind 30% of project cost Up to 50% Prevailing wage + domestic content
PTC (Section 45/45Y) Wind, solar, geothermal ~$15/MWh ~$33/MWh Prevailing wage + apprenticeship
45V clean hydrogen Electrolytic hydrogen $0.60/kg $3/kg <0.45 kg CO₂e per kg H₂
45X advanced manufacturing Modules, cells, inverters Varies by component $0.07/W (modules) US manufactured
48C advanced energy MFG Clean energy manufacturing 30% of project cost 40% Competitive allocation
Energy community bonus ITC + PTC projects +10 percentage pts Applied to base rate Former fossil fuel community
Low-income community bonus Distributed solar +10 to +20 pts Applied to base rate Qualified census tracts
IRA credits are subject to prevailing wage and apprenticeship requirements for full base rates. Domestic content bonuses require specified US-manufactured percentages for structural components. Energy community designations are updated periodically by Treasury. 45V eligibility requires meeting strict lifecycle emissions thresholds with hourly matching of electricity consumption to clean generation. Credits available through 2032 (technology-neutral credits through 2035+). Transferability provisions allow credits to be sold to third-party buyers without tax equity partnerships. Sources: IRS Notice 2023-29, Treasury/IRS guidance, DOE Loan Programs Office.

Data notes: Statistics represent reference figures compiled from publicly available industry sources and are intended as benchmarks for commercial buyers. Electricity rates, capacity prices, and procurement costs vary significantly by location, load size, contract structure, and market conditions. LCOE figures are unsubsidized unless noted. Forward-looking figures (deployment targets, cost projections) are industry consensus estimates and subject to change. This page is updated periodically — verify current figures with your energy advisor or directly from cited sources before making procurement decisions. The Outlet is not a licensed energy advisor and this data does not constitute investment or procurement advice.