Key Market Drivers: High IRR Fueled by Rate Cuts, Grid Volatility, and Incentives
California and Texas Lead the U.S. Energy Storage Boom, Capturing ~70% of New Installations
| U.S. New Added Energy Storage Capacity Growth | |||
| Year | New Added Capacity (MW) | New Added Capacity (MWh) | Year-on-Year Growth (yoy) |
| 2020 | ~500 | ~1,000 | ~ |
| 2021 | ~3,500 | ~10,000 | ~500% |
| 2022 | ~4,500 | ~11,800 | ~0-50% |
| 2023 | ~6,800 | ~19,000 | ~100% |
| 2023 U.S. New Added Energy Storage Capacity Distribution | ||
| Region | New Added Capacity (MW) | Proportion |
| California | 2951 | 44.91% |
| Texas | 1468.8 | 22.35% |
| Arizona | 841 | 12.80% |
| Other Regions | 1310 | 19.94% |
| Total | 6570.8 | 100% |
In 2023, the U.S. added 6.57 GW / 18.71 GWh of new energy storage capacity, representing a year-over-year growth of 55.6% in power energy storage battery installations. California and Texas emerged as the two leading states driving this growth.
- California added 2.95 GW, accounting for 44.9% of total U.S. new installations.
- Texas contributed 1.47 GW, representing 22.4% of the total.
Together, these two states accounted for nearly 70% of all new energy storage capacity installed in the United States in 2023.
U.S. Energy Storage Projects Achieve IRR Above 20%
| U.S. Energy Storage Unit Revenue Breakdown | |||
| Revenue Item | California Standalone Storage (USD/MWh) | Texas Solar-Storage (USD/MWh) | Texas Wind-Storage (USD/MWh) |
| Arbitrage | 95 | 93 | 61 |
| Frequency Regulation | 56 | 101 | 42 |
| Spinning/Non-Spinning Reserve | 8 | 24 | 13 |
| Capacity Adequacy | 64 | – | – |
| Total Unit Revenue | 223 | 218 | 116 |
Revenue for energy storage projects primarily comes from arbitrage, frequency regulation, spinning/non-spinning reserves, and capacity adequacy (domestic capacity-based pricing).
According to Lazard, storage projects demonstrate high IRRs:
- In California, standalone energy storage achieves an IRR of 28.9% after state incentives.
- In Texas, co-located wind-plus-storage and solar-plus-storage projects have IRRs of 25.5% and 21.1%, respectively.
These figures highlight the strong profitability of energy storage investments in key U.S. markets.
U.S. Energy Storage Projects Exhibit IRR Above 20%
| California Standalone Energy Storage Revenue and IRR | |
| Key Indicator | Value |
| Power Capacity (MW) | 100 |
| Duration (h) | 4 |
| Energy Capacity (MWh) | 400 |
| Daily Cycles at 90% DOD | 1 |
| Annual Operating Days | 350 |
| Charging Cost ($/kWh) | 0.064 |
| Fixed O&M Cost ($/kWh) | 1.3 |
| Annual Fixed O&M Cost Growth Rate (%) | 2.50% |
| Charging Cost Degradation Growth (%) | 1.87% |
| Efficiency (%) | 91% |
| Capital Structure | |
| Debt Ratio (%) | 20.00% |
| Debt Cost (%) | 8.00% |
| Equity & Free Capital Ratio (%) | 80.00% |
| Equity Cost (%) | 12.00% |
| Combined Tax Rate (%) | 21.00% |
| Operating Life (Years) | 20 |
| Depreciation Period (Years) | 5 |
| Federal ITC-BESS (%) | 30% |
| Residual Value Rate (%) | 20% |
| Initial Acquisition Cost ($/kWh) | 291.25 |
| Additional Security Deposit (% of Capital Cost) | 0.70% |
| Initial Year of Additional Security Deposit | 3 |
| Total Capital Expenditure ($mm) | 116.5 |
| 20-Year Financial Projection for California Standalone Energy Storage | ||||||||||
| Metric | Year 0 | Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | … | Year 18 | Year 19 | Year 20 |
| Power Capacity (MW) | – | 100 | 100 | 100 | 100 | 100 | … | 100 | 100 | 100 |
| Total Generation (‘000 MWh) | – | 126 | 126 | 126 | 126 | 126 | … | 126 | 126 | 126 |
| Total Revenue ($mm) | – | 28 | 28 | 28 | 28 | 28 | … | 28 | 28 | 28 |
| Total Charging Cost ($mm) | – | -8.9 | -9 | -9.2 | -9.4 | -9.6 | … | -12.2 | -12.4 | -12.7 |
| Total Fixed O&M & Security Deposit ($mm) | – | -0.5 | -0.5 | -1.4 | -1.4 | -1.4 | … | -1.6 | -1.6 | -1.6 |
| Total Operating Cost ($mm) | – | -9.4 | -9.6 | -10.6 | -10.8 | -10.9 | … | -13.8 | -14.1 | -14.3 |
| EBITDA ($mm) | – | 18.7 | 18.5 | 17.5 | 17.3 | 17.2 | … | 14.3 | 14 | 13.8 |
| Remaining Debt ($mm) | – | 23.3 | 22.8 | 22.2 | 21.6 | 21 | … | 6.1 | 4.2 | 2.2 |
| Debt – Interest Expense ($mm) | – | -1.9 | -1.8 | -1.8 | -1.7 | -1.7 | … | -0.5 | -0.3 | -0.2 |
| Debt – Principal Repayment ($mm) | – | -0.5 | -0.5 | -0.6 | -0.6 | -0.7 | … | -1.9 | -2 | -2.2 |
| Normalized Debt Expense ($mm) | – | -2.4 | -2.4 | -2.4 | -2.4 | -2.4 | … | -2.4 | -2.4 | -2.4 |
| EBITDA ($mm) | – | 18.7 | 18.5 | 17.5 | 17.3 | 17.2 | … | 14.3 | 14 | 13.8 |
| Depreciation (5-year, 20% residual value) ($mm) | – | -18.64 | -18.64 | -18.64 | -18.64 | -18.64 | … | -0.5 | -0.3 | -0.2 |
| Interest Expense ($mm) | – | -1.9 | -1.8 | -1.8 | -1.7 | -1.7 | … | -0.5 | -0.3 | -0.2 |
| Pre-Tax Income ($mm) | – | -1.8 | -1.9 | -2.9 | -3 | -3.2 | … | 13.8 | 13.7 | 13.6 |
| Taxes ($mm) | – | 0.4 | 0.4 | 0.6 | 0.7 | 0.7 | … | -2.9 | -2.9 | -2.9 |
| Federal Tax Credit (ITC) ($mm) | 34.95 | – | – | – | – | – | … | – | – | – |
| Capital Expenditure ($mm) | -93.2 | -23.3 | – | – | – | – | … | – | – | – |
| Cash Flow ($mm) | -93.2 | 51.7 | 16.6 | 15.8 | 15.6 | 15.4 | … | 9 | 8.8 | 8.5 |
| IRR | 22% | – | – | – | – | – | … | – | – | – |
According to Lazard, the initial capital cost of 4-hour energy storage in the U.S. ranges from $190 to $392.5/kWh, with an assumed average of $291.25/kWh (~2 RMB/Wh). This includes $221/kWh for the DC component, $45/kW for the AC component, and $59/kWh for installation and other related costs. Under a financing structure with 20% debt at an annual interest rate of 8%, standalone energy storage in California achieves an IRR of 22%, corresponding to a Levelized Cost of Storage (LCOS) of $174/MWh (~1.2 RMB/kWh).
Increased Renewable Capacity Widens Peak-to-Valley Price Spread
The increase in renewable energy capacity may widen the intraday peak-to-valley price spread. The so-called “Duck Curve” illustrates the variation of net load throughout the day, where net load is defined as actual load minus renewable generation output. According to Synergy, as cited by the International Solar PV Network, since 2018, the Duck Curve has shown a pronounced midday dip and higher evening peak in regions with growing renewable capacity. This trend suggests that in the U.S. electricity market, which is largely driven by market supply and demand, the intraday fluctuations in supply and demand could further amplify the day-ahead and intraday peak-to-valley price differentials.
Increased Renewable Capacity Widens Intraday Peak-to-Valley Price Spread
PG&E’s time-of-use (TOU) electricity rates show significant peak-to-valley price differentials during the summer. Under the TOU-C plan, the summer peak-to-valley spread is $0.09/kWh (~0.63 RMB/kWh). The TOU-D plan exhibits a higher summer spread of $0.14/kWh. For PG&E E-ELEC, a program designed for customers with high electricity consumption due to home electrification upgrades such as EV charging, battery storage, heat pumps, and solar panels, the summer peak-to-valley price differential reaches $0.22/kWh.
PG&E Time-of-Use (TOU) Electricity Rates
PG&E offers two main time-of-use (TOU) plans: TOU-C, which applies a peak period from 4:00 PM to 9:00 PM daily, and TOU-D, which applies a peak period from 5:00 PM to 8:00 PM on non-holiday weekdays only. While TOU-D appears advantageous at first glance due to its shorter peak hours, it is specifically designed for high-usage customers. TOU-C is PG&E’s standard plan, intended for average or low electricity-consuming households. Additionally, E-ELEC is a specialized program for customers with high electricity consumption resulting from home electrification upgrades, including electric vehicle charging, lithium battery storage, heat pumps (for water heating and/or climate control), and solar PV installations.
Aging and Fragile U.S. Grid: Energy Storage Supports Grid Stability
Insufficient Grid Modernization and Extended Energy Supply Chain Lead Times Affect U.S. Grid Reliability
Limited Interconnection Between Regional Grids: The U.S. grid originally developed as isolated systems and later interconnected on a mutually beneficial basis. However, the three major interconnections are linked by only a few low-capacity DC lines, limiting their ability to balance supply and demand across regions.
Challenges from Aging Infrastructure and Energy Transition: With the shift toward renewable energy, aging infrastructure has become a critical issue. According to statistics cited by CCTV Finance from the U.S. Department of Energy, 70% of transmission lines and transformers have been in operation for over 25 years, and 60% of circuit breakers have exceeded 30 years of service. The North American Electric Reliability Corporation (NERC) has noted that the U.S. requires additional transmission lines, which could take 7 to 15 years to construct.
Extended Energy Supply Chain Lead Times: Extended delivery times for energy equipment have further impacted grid reliability. According to the 2024 Summer Reliability Assessment released by NERC (as cited by People’s Daily), since 2020, delivery times for transformers, transmission cables, switchgear, and photovoltaic panels in the U.S. have increased significantly, severely affecting the construction and upgrading of new projects as well as seasonal preparedness.
Market Outlook: Abundant Planned Projects and Simplified Grid Connection Unlock Growth Potential
U.S. Energy Storage Market Potential: 97 GWh of New Installations in 2026, Sustained High Growth
| U.S. New Added PV and Energy Storage Capacity | |||
| Year | New Added PV Capacity (GW) | New Added Energy Storage Capacity (GW) | New Added Energy Storage Capacity (GWh) |
| 2017 | ~11 | ~0 | ~1 |
| 2018 | ~11 | ~0 | ~1 |
| 2019 | ~13 | ~0 | ~1 |
| 2020 | ~19 | ~0.5 | ~4 |
| 2021 | ~23 | ~2.5 | ~11 |
| 2022 | ~21 | ~4 | ~13 |
| 2023 | ~32 | ~8 | ~28 |
| 2024E | ~44 | ~15 | ~46 |
| 2025E | ~55 | ~22 | ~70 |
| 2026E | ~66 | ~30 | ~97 |
According to Wood Mackenzie, in 2023 the U.S. added 32.4 GW of new energy storage capacity, representing a 51% year-on-year increase. The average storage duration in the market was 3.2 hours, with commercial & industrial and residential storage adoption rates at 5% and 13%, respectively, which are expected to rise to 10% and 25% in 2024.
Assuming a steady increase in solar-plus-storage adoption and continued high growth for standalone energy storage, we estimate that new energy storage installations in 2024 and 2025 will reach 14.9 GW and 22.0 GW, representing year-on-year growth of 66% and 48%, respectively.
FERC’s New Interconnection Rules Expected to Ease U.S. Energy Storage Grid Bottlenecks
| U.S. Energy Storage Grid Connection Status | |||||
| Month 2024 | Projected Grid Connection (MW) | Actual Grid Connection (MW) | New Added Capacity (MW) | Monthly Grid Connection Rate | Cumulative Grid Connection Rate |
| January | 1044 | 155 | 889 | 14.83% | 14.83% |
| February | 1535 | 36 | 2388 | 2.34% | 7.39% |
| March | 1759 | 1045 | 3102 | 59.43% | 28.49% |
| April | 829 | 685 | 3245 | 82.69% | 37.19% |
| May | 655 | 1073 | 2827 | 163.84% | 51.43% |
| June | 2526 | 1250 | 4103 | 49.48% | 50.84% |
| July | 412 | 753 | 3762 | 182.84% | 57.05% |
| August | 260 | 961 | 3061 | 369.54% | 66.06% |
| September | 614 | – | – | – | – |
| October | 162 | – | – | – | – |
| November | 210 | – | – | – | – |
| December | 4299 | – | – | – | – |
According to the EIA, from January to August 2024, the U.S. connected a total of 5.96 GW of energy storage, achieving 66.06% of the annual target and representing a 4.03 percentage point year-on-year increase. The growing number of storage projects in the interconnection queue and lengthy approval cycles are key factors limiting grid connection efficiency.
Extended review times have resulted in many queued storage projects. In the U.S., the time from submitting an interconnection application to the start of commercial operation was less than 2 years between 2000 and 2007, but increased to over 4 years between 2018 and 2023.
FERC’s New Interconnection Rules Expected to Alleviate U.S. Energy Storage Grid Bottlenecks
| 2023 vs 2024 Actual vs. Projected Grid Connection Rate | ||
| Month | 2023 Cumulative Grid Connection Rate | 2024 Cumulative Grid Connection Rate |
| 1 | ~9.5% | ~15.0% |
| 2 | ~9.5% | ~7.5% |
| 3 | ~21.0% | ~28.5% |
| 4 | ~26.0% | ~37.0% |
| 5 | ~24.0% | ~51.5% |
| 6 | ~34.0% | ~51.0% |
| 7 | ~60.0% | ~57.0% |
| 8 | ~62.0% | ~66.0% |
| 9 | ~64.0% | ~- |
| 10 | ~60.0% | ~- |
| 11 | ~60.0% | ~- |
| 12 | ~65.0% | ~- |
On July 28, 2023, FERC issued new interconnection rules aimed at simplifying the grid connection process. Key measures include compressing feasibility and system impact studies to be completed within 150 days and shifting from individual project studies to batch cluster studies, thereby reducing queue times. The rules came into effect on November 6, 2023. Since implementation, total actual vs. forecasted energy storage interconnections for January–August 2024 are slightly higher than in 2023, although there is still room for improvement in completion rates.
In May 2024, FERC issued Order 1920, covering the long-term planning and investment of cross-regional transmission networks in the U.S. over the next 20 years. The order requires transmission operators to update their plans every five years (previously rarely done) and to consider economic feasibility, reliability, and extreme weather impacts. FERC also introduced new cost allocation rules for grid upgrades and operations, which are expected to support energy storage demand and interconnection efficiency.
