Can Grid Scale Energy Storage Compete with Gas Fired Peakers? Not Yet, But Coming Soon

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Eric Selmon Hugh Wynne

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February 5, 2018

Can Grid Scale Energy Storage Compete with Gas Fired Peakers?

Not Yet, But Coming Soon

In this note, we compare the all-in cost to a regulated utility of meeting its capacity needs during the highest demand hours of the year through a grid scale battery storage facility rather than a traditional gas fired peaking plant. At 2018 prices for batteries and combustion turbines, we find that the all-in cost of power from grid storage is some 35% above that of a conventional peaker. Assuming a 9% annual rate of decline in the installed cost of grid storage, well below the 13% average annual decrease realized since 2015, we estimate that the all-in cost of power from grid storage falls to ~15% above that from a conventional peaker by 2020, and by 2024 falls ~15% below it.

Portfolio Manager’s Summary

Methodology and Assumptions

  • Our analysis seeks to replicate the decision-making process of a regulated utility faced with the need to add capacity to meet the growth in its peak demand. We assume the utility is assessing alternatives to meet its capacity requirements during the highest demand hours of the year, and is considering grid scale battery storage as an alternative to traditional gas fired peakers.
  • Our analysis compares the all-in cost (including fuel, operation and maintenance expense, and capital recovery costs) of a grid scale lithium ion battery storage facility with (i) a gas-fired combustion turbine, the current standard to serve large scale capacity needs (>100MW) and (ii) a gas-fired internal combustion engine, used for smaller capacity requirements (<100MW).
  • The three alternatives have the following characteristics:
    • The lithium ion battery storage facility costs ~$290/kWh or $1,160/kW installed, is capable of four hours of discharge, and will charge during the four hours of the day when electricity costs are lowest with 90% efficiency through the charge/discharge cycle.
    • The gas-fired internal combustion engine costs ~$950/kW and has a heat rate of 9.0 MMBtu/MWh.
    • The gas-fired combustion turbine has an installed cost of ~$875/kW and a heat rate of 8.9 MMBtu/MWh.
  • We repeat our assessment using estimated costs in 2020 and 2024 for the three technologies:
    • We assume that the installed cost of the storage facility declines at a compound annual rate of 9% p.a., well below the 13% average annual cost declines for grid scale battery storage realized since 2015;
    • We assume that the installed cost of the combustion turbine and internal combustion engine remain constant in real terms (i.e., expressed in constant 2018 dollars).
  • Our operating assumptions, which are the same for 2018, 2020 and 2024, include:
    • A uniform capacity factor of 10% across the three alternative technologies;
    • A delivered gas price of $3.00/MMBtu;
    • An off-peak charging price of $20/MWh for the battery;
    • Variable operation and maintenance expense $10 for the internal combustion engine, $5/MWh for the combustion turbine, and none for the battery;
    • Fixed operation and maintenance expense of $15/kW-year for the internal combustion engine, $10/kW-year for the combustion turbine and $10/kW-year for the battery;
    • A useful life of 15 years for the storage facility, corresponding to ~3300 cycles; and
    • A useful life of 25 years for the gas-fired peakers.
  • We have modeled the cash flows of the three projects under two sets of ownership assumptions: first, assuming ownership by a regulated utility, with the asset placed in rate base and its cost recovered in customer rates, and second, assuming ownership by an independent power producer with cost recovery under a long-term power purchase agreement with the utility.
  • We do this to capture the different tax treatment of regulated utility and IPP assets stipulated by the Tax Cuts and Jobs Act of 2017.
    • Under the Act, regulated utilities are precluded from using bonus depreciation. We assume therefore that the utility’s investment in the storage facility is depreciated using 7-year MACRS, while the gas-fired peakers are depreciated using 15-year MACRS.
    • For the IPP, by contrast, assets placed in service over the five years from 2018 through 2022 are eligible for 100% bonus depreciation; thereafter, the percentage of an asset’s cost that may be expensed falls by 20% per year, from 80% in 2023 to zero in 2027, with the remainder of the asset’s cost subject to depreciation under MACRS.
  • To compare the all-in cost of the three alternatives, we have calculated the revenue required by each to recover capital costs, operation and maintenance expense, income taxes and an after-tax, weighted average cost of capital of 7%. We have expressed the revenue requirement of each technology in $/kW-month, and trace their trajectory over time in Exhibit 1.

Exhibit 1: Comparison of the All-in Cost of Power from a Battery Storage Facility, Gas-fired Combustion Turbine and Gas-fired Internal Combustion Engine, in $kW-month

Utility Ownership IPP Ownership


Source: Lazard’s Levelized Cost of Storage Analysis, Version 3.0 and Lazard’s Levelized Cost of Energy Analysis, Version 11.0; SSR analysis and estimates


  • At 2018 prices for grid scale battery storage, combustion turbines and internal combustion engines, we find that the all-in cost of power from a battery storage facility exceeds that from a combustion turbine peaker by 35% in the utility ownership case and 30% in the IPP ownership case.
    • This primarily reflects the fact that the capital cost of the storage facility (estimated at $290/kWh or, assuming four hours of discharge, $1,160/kW) is ~33% above that of a combustion turbine ($875/kW).
    • Also tending to increase the all-in cost of power from the battery storage facility is its shorter useful life, assumed to be 15 years as opposed to 25 for the combustion turbine and internal combustion engine.
    • Partially offsetting these factors, the storage facility enjoys a lower cost of energy, reflecting its ability to charge during the lowest priced four hours of the day. We assume the battery can charge at an off-peak power price of $20/MWh, typical of the lowest cost four hours of the day across a range of wholesale markets. Allowing for the battery’s 90% efficiency across the charge/discharge cycle, this implies an energy cost of $22/MWh. By contrast, our assumption of a delivered gas price of $3.00/MMBtu, multiplied by our assumed combustion turbine heat rate of 8.9 MMBtu/MWh, implies an energy cost of $27/MWh. Given our low assumed capacity factor of only 10%, however, this energy cost advantage is insufficient to offset the much higher capital cost of the battery and the shorter useful life over which it must be recovered.
  • By 2020, however, our analysis suggests that the all-in cost of energy from a grid scale battery storage facility could fall to 12% above of the all-in cost of power from a combustion turbine peaker, in the IPP ownership case, and 16% above the cost of a combustion turbine in the utility ownership case. Moreover, by 2020, the all-in cost of battery storage becomes competitive with that of an internal combustion engine, which is often preferred for small scale applications (<100 MW).
    • This decline in the relative cost of energy storage reflects our assumption that the installed cost of lithium ion batteries will fall at a rate of 9.0% p.a., while the capital cost of combustion turbines and internal combustion turbines will remain unchanged in real terms.
  • Extending our assumed 9.0% annual rate of decline in the installed cost of lithium ion batteries out to 2024, we calculate that by then the all-in cost of power from a grid scale energy storage facility could fall to 16% below that of a combustion turbine in the IPP ownership case, and 13% below in the utility ownership case. Compared to an internal combustion engine, battery storage is 23% cheaper given utility ownership and 22% cheaper assuming IPP ownership.


  • The four hour duration of discharge typical of today’s lithium ion batteries will constrain their deployment as peaking capacity in certain contexts.
  • While this analysis seeks to replicate the decision making of a regulated utility planning to meet its capacity needs during the highest demand hours of the year, it is nonetheless relevant that certain competitive power markets have stipulated that any capacity resources they procure must be available for periods longer than four hours.
    • The PJM Interconnection, for example, has stipulated that capacity resources wishing to participate in its annual capacity auctions must be capable of “sustained, predictable operation” for 16 hours per day for three consecutive days, and the New England ISO has adopted a similar standard.
    • Both RTOs tightened their definitions of eligible capacity resources in response to the market conditions that prevailed during the 2014 polar vortex, including long hours of high demand due to frigid weather conditions.
  • Similar concerns about duration of discharge may limit the deployment of lithium ion batteries by utilities whose peak loads occur in the winter and tend to last longer than four hours.
  • However, as battery costs continue to decline, stacking battery installations to allow for longer duration deployments (e.g. using two battery installations with 4 hours of energy each, one after the other, to allow for dispatch up to 8 hours) should become economic beyond 2024.

Where We Expect Batteries to Be Deployed First

  • Initially, batteries will be deployed as part of a diverse generating fleet, with some conventional peaking capacity available for longer duration events.
  • In this context, we expect utilities will find many situations where batteries could be deployed effectively and economically as costs decline.
    • Utilities facing summer peaks, which tend to be of shorter duration, might find a low cost source of four hour peaking capacity to be attractive from both an economic and reliability standpoint.
    • Utilities may also find battery storage an attractive alternative to more expensive conventional peakers if the utility’s primary objective is to support grid reliability at particularly strained points in the transmission or distribution network or to backstop intermittent renewable generation.
  • The capacity value of batteries as short duration peakers, their usefulness in alleviating transmission and distribution bottlenecks, and their effectiveness in offsetting the intermittency of renewable resources, could result in large scale installations much sooner than 2024, as we are already seeing in California.
    • We note also that batteries have been favored over conventional peakers in situations where speed of deployment is of the essence (e.g., in response to the interruption of gas supplies from the Aliso Canyon storage facility, and on the South Australia power grid).
  • Finally, large commercial and industrial customers may find customer-sited storage to be increasingly attractive as a means of reducing their net demand for grid power and thus their demand charges. Such deployments are already economic for some customers with high demand charges.
    • The impact of this peak shaving by large commercial and industrial customers would be to reduce the need for peaking capacity on the utility grid. As batteries charge during the lowest cost hours of the day, moreover, their deployment tends to lower energy costs for all customers, who otherwise would face peak hour prices set by higher cost peakers.
    • Utility subsidies for battery installations by large customers, similar to subsidies for energy efficiency, may therefore be cost effective.

Implications for Wholesale Power Markets

  • Importantly, the electricity prices required for the economic operation of conventional gas fired peakers are much higher than those at which battery storage facilities may be dispatched, a distinction that has critical implications for wholesale power prices and generator revenues.
    • The peak hour prices offered by conventional peakers must be sufficient to cover their cost of fuel and variable operation and maintenance expense. Given the generally low fuel efficiency of conventional peakers (a function of the priority placed on minimizing the capital cost of these infrequently used plants), peakers tend to sustain peak hour prices at elevated levels.
    • By contrast, battery storage facilities can be charged during the lowest demand hours of the day, when power prices are at their minimum. The deployment of batteries as a substitute for conventional peakers would thus have the effect of reducing the variable cost of energy supplied during peak demand hours, tending to erode peak hour prices and thus generator revenues.
  • Our analysis of the impact of grid storage on wholesale power prices suggests that even relatively modest amounts of storage capacity, regardless of why it is deployed, could have a material impact on peak hour prices and generator revenues(please see our notes of March 22, 2017, 20% Price Declines for Wholesale Power? The Compelling Social Case for Electric Energy Storage and Why Regulated Utilities Are Likely to Roll It Out First and August 14, 2017, Which Power Markets Are Most Vulnerable to Energy Storage and Why?).

Exhibit 2: Heat Map: Preferences Among Utilities, IPP and Clean Technology

Source: SSR analysis

©2018, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

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