Essential And Achievable
by Tyson Siegele
California’s grid of the future will run on 100% carbon-free energy by leveraging energy storage and spare renewable generating capacity. To accomplish this, will we need expensive and environmentally questionable solutions? Or will emerging technologies and the family vehicle create a greener future than even optimists foresee? To explore those questions, we’ll look at some of the most important factors influencing the design use of grid-supporting batteries: electric vehicles (EVs), bi-directional charging, low solar prices, spare renewable capacity, and grid planners’ imminent obsession with December.
Electric Vehicles: The Future of Storage
Regardless of solar and wind procurement decisions, California’s grid operator will need a lot of electricity storage. Today, the California grid operator, CAISO, controls 3,136 megawatts (MW) of battery capacity.[i] Modeling in the Senate Bill (SB) 100 Report found that California will need to install 55,000 MW of utility-scale battery storage for reliable grid operations.[ii] Each of those 55,000 MW has a duration of four hours, equaling 220,000 megawatt hours (MWh) of stored energy. According to the report, California needs 17 times as much battery storage as has been installed today.
The electric utilities will not have to buy anything near this proposed storage capacity because of an exciting feature of upcoming electric vehicles (EV). Soon most EVs will have bi-directional charging capabilities. Car batteries will act as a battery, not just for the vehicle but for the home, for a local business, or even for the grid itself. Cars will be able to buy electricity from the grid or sell it back. Because of the battery’s large size, the typical EV can go six days between charging, allowing it to sell some of its stored electricity back to the grid on the handful of days each year when electricity supplies fall short of demand.
By 2035, 100% of light-duty vehicles sold in California must be electric. The California Air Resources Board (CARB) proposed a regulation for vehicle sales requiring that 35% of annual vehicle sales be electric by 2026 and that 68% be electric by 2030.[iii] Enforcement of the proposal ensures that a large number of electric vehicles will join the one million California EVs already on the road. The average EV battery capacity is 75 kWh, and approximately 30 million light duty vehicles are registered in California. If 75% of the registered vehicles are electric by 2045 – the target year for a carbon-free electricity grid – the fleet’s battery capacity will equal 1,687,500 MWh or seven times what grid planners’ claim will be needed to secure electric reliability.
In just a few years, most EVs will include (1) bi-directional charging hardware that will allow owners to either buy from or sell to the grid, (2) software to make sure the owner always has enough electricity after unplugging, and (3) software to maximize charging during times of low electricity cost. When manufacturers integrate these features, EV batteries will enable grid planners to reduce their projections for stationary battery storage needs, entirely remove the need for grid-based multi-day storage, and still maintain a supply buffer to ensure reliability. EVs will save electric customers money and save everyone time in the transition to a carbon-free grid.
Access to EV storage capacity addresses our daily and weekly storage needs but leaves the question of seasonal storage untouched. Should grid planners require utilities to purchase seasonal storage or are there better ways to address the large seasonal variations in renewable energy supply?
The Seasonal Storage Mirage
Over the last few years, the natural gas industry has championed hydrogen for a large number of possible applications. The industry has decided that the only way it can survive the coming era of widespread electrification is to transition from its high-impact global-warming product, methane, to a less potent greenhouse gas, green hydrogen.[iv] One of the proposed uses for hydrogen has been the seasonal storage of electricity. Seasonal storage means that electricity would be produced in the summer, stored through the fall, and supplied in the winter. Unfortunately, no form of seasonal storage has ever been found to be cost effective. That includes hydrogen-based seasonal storage. As we look at the best way to generate and store enough energy for California’s green future, I’ll explain why seasonal storage has remained intriguing and why it always disappoints.
California adds new renewable energy and storage to the grid every day. As these resources become available, summer electricity supply continues to grow rapidly even while summer peak demand has started to shrink.[v] Summer electricity supply will easily outstrip demand within the next few years, and the trend is expected to continue.
Grid planners will soon ignore summer generation and instead will focus on how to meet the winter demand, specifically customers’ electricity demand in December. This is the final problem to solve because both wind and solar production decrease substantially in the winter, and solar, in particular, always bottoms out in December. Grid planners must size the state-wide renewable capacity to serve December demand even though that will necessitate spare capacity through the rest of the year.
This new renewable electricity supply will rely almost entirely on solar, because wind is significantly more expensive. In California, solar energy costs half as much as wind at $0.03/kWh versus $0.06/kWh.[vi] California Public Utility Commission consultants have also determined that solar-plus-storage facilities provide twice the reliability as wind-plus-storage facilities.[vii] In combination, California would have to spend four times as much money on wind generators to achieve the same reliability level met by solar generators. Additionally, rooftop solar alone could serve nearly all of the state’s electricity demand.[viii] Rooftop solar (i.e., generation at the point of use) would minimize the proposed $30 billion expansion of California’s transmission system.[ix]
The assumption that solar will emerge as the primary electricity generation source aligns with the SB 100 Report. Some of the report's modeling concludes that California should add 20-times more in-state solar than in-state wind. As solar will dominate future energy production, we’ll use solar generation and the annual solar production curve to describe California’s electricity procurement needs.
CAISO operates the transmission lines that deliver electricity to 80% of California. The chart below shows two metrics from 2021 for the CAISO service territory: monthly demand in blue bars corresponding to the left y-axis and monthly solar supply in yellow bars corresponding to the right y-axis.
In this visualization, we’re looking at the scale of solar production at 12.5 times the scale of demand. The yellow solar supply bars have been scaled up in this way to closely align the lowest-supply solar month, December, with the demand for that month. In all months other than December and January, the scaled solar supply bars far exceed the bars representing total demand. By comparing the demand bars to the supply bars, one can see that when the grid achieves a zero-carbon energy supply, December will be the month most likely to experience a supply shortfall. Supplying summer demand will have long since ceased to be a concern.
Conservation has always been a theme of the environmental movement and an ethic for people in general. The spare solar capacity shown in the chart has triggered planners’ conservation mentality. Grid planners want to align electricity supply with electricity demand rather than see electricity generation capacity so significantly surpass demand during most months of the year. For this reason, grid planners continue to research the idea of seasonal storage. The seasonal supply imbalance also encourages gas companies to promote the idea that hydrogen-based seasonal storage will reduce costs and aid in the energy transition.
We can see that shifting the excess solar energy from spring and summer months to serve demand in winter months would reduce the need for renewable generation capacity. Unfortunately, the poor conversion efficiency of hydrogen-based seasonal storage and its high equipment costs make seasonal storage more wasteful and costly than building spare renewable generating capacity.
Hydrogen-based electricity storage employs a “power-to-hydrogen-to-power” storage method. The process involves powering electrolyzers with the electricity to be stored. The electrolyzer generates hydrogen. The hydrogen is stored until electricity is needed. When needed, the hydrogen is burned in gas-fired generators to produce electricity. The average efficiency factor of the process is 31%.[i] That means the storage process requires three times more input electricity than will be returned after storage.
If California were to use hydrogen as a seasonal storage medium, the state would have to generate additional energy to offset the losses occurring during the energy conversions. This additional generating capacity would be similar to the amount needed to meet the winter demand in the first place. Dismissing hydrogen-based seasonal storage eliminates the cost of electrolyzers, the cost of hydrogen-fired generators, the cost of hydrogen storage, the cost of hydrogen pipelines, the NOx pollution emitted when burning hydrogen, and the global warming effects caused by hydrogen. California grid planners agree that hydrogen storage costs are not competitive with other sources of storage and generation.[ii]
Choosing the more efficient excess capacity plan would produce spare power in the summer months. Some of the spare power will be purchased by industrial customers that chose to take advantage of the lower-cost seasonal electricity prices by operating only during months of excess supply. Industrial users will likely plan their repairs and upgrades for January and December during which time they will suspend typical operations. The spare capacity can also be sold as exports aiding neighboring states in their clean energy transitions.
But even if none of the spare capacity is used, the costs are much lower than might be intuitive. In the example from the chart, 49% of the generating capacity goes unused. Solar is currently $0.03/kWh, but if we have to pay for approximately twice as much as what we use, the price doubles to $0.06/kWh. To put that three cent cost increase into context, San Diego Gas and Electric charges its residential customers up to $0.69/kWh for electricity, 23 times the three cent price difference.[iii]
While conceptually appealing, seasonal storage would reduce summer supply without conveying associated environmental or fiscal benefits. For this reason, spare capacity outperforms seasonal storage.
Storage Advancements: Inevitable, Welcome, Unnecessary
In 2010, no one could have guessed what the electricity storage landscape would have looked like today. Battery pack prices have dropped 89%. Electric vehicle sales grew from non-existent to over 6 million last year alone. Battery energy densities have skyrocketed, and battery chemistry options have multiplied. Because of the last decade’s advancements, today’s commercialized technology enables a carbon-free grid. The future of electricity storage will be just as exciting. Automotive companies have committed to spending over half a trillion dollars on batteries throughout the coming decade. New funding guarantees incremental improvements in battery performance, incentivizes manufacturing efficiencies, and increases the possibility of technological breakthroughs. California can achieve its 2045 electric grid goals with today’s technology. Tomorrow’s technology may allow us to meet those goals well ahead of schedule.
Tyson Siegele has worked for two decades integrating energy efficiency and renewable energy into electricity grids from New York to California. He currently provides expert testimony and analysis in proceedings at the California Public Utilities Commission.
 California Independent System Operator, Key Statistics, (June 2022), p. 2, available at https://www.caiso.com/Documents/Key-Statistics-May-2022.pdf.
 Senate Bill 100 Report (“SB 100 Report”), Study Scenario (March 15, 2021), p. 75-76, available at https://www.energy.ca.gov/publications/2021/2021-sb-100-joint-agency-report-achieving-100-percent-clean-electricity.
 California Air Resources Board, Public Hearing to Consider the Proposed
Advanced Clean Cars II Regulations (April 12, 2022), Table XI-1, p. 174, available at https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2022/accii/isor.pdf.
 Ocko, I. B. and Hamburg, S. P.: Climate consequences of hydrogen leakage, Atmos. Chem. Phys. Discuss. [preprint], https://doi.org/10.5194/acp-2022-91, in review, 2022.
 California Independent System Operator, California ISO Peak Load History 1998 through 2021, available at https://www.caiso.com/documents/californiaisopeakloadhistory.pdf.
 LevelTen Energy, Q1 2022 PPA Price Index Executive Report (2022), pp. 9-10, available at https://www.leveltenenergy.com/ppa-q122.
 California Public Utilities Commission, Incremental ELCC Study for Mid-Term
Reliability Procurement (Updated), (October 22, 2021) Table ES2, p. 9, available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/20211022_irp_e3_astrape_incremental_elcc_study_updated.pdf.
 Google Project Sunroof, Estimated rooftop solar potential of California (November 2018), available at https://sunroof.withgoogle.com/data-explorer/place/ChIJPV4oX_65j4ARVW8IJ6IJUYs/.
 California Independent System Operator, 20-year Transmission Outlook (January 31, 2022) available at http://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf.
 Sepulveda, N.A., Jenkins, J.D., Edington, A. et al. The design space for long-duration energy storage in decarbonized power systems. Nat Energy 6, 506–516 (2021), (31% is the average of the “round-trip efficiency” ranges shown in Table 1 for the “power-H2-power” technologies.), available at https://doi.org/10.1038/s41560-021-00796-8.
 SB 100 Report, p. 109 (“Production costs are not cost-competitive with other sources of storage and generation…”).
 SDG&E, Schedule TOU-DR1 Residential Time-of-Use, (May 16, 2022), p. 2, (Summer On-Peak Total Rate = 0.69008), available at https://static1.squarespace.com/static/61787bd78d872411f0f3a50e/t/62ac0e9f5478ff177d68d289/1655443103645/2022-01-01+-+SDG%26E+-+ELEC_ELEC-SCHEDS_TOU-DR1.pdf.