The Planetary Opportunity In The Climate Crisis
This “planetary civilization” governed by the laws of physics is the opportunity the fight for New Energy can lead to. From Our Nebula via YouTube
Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...
This “planetary civilization” governed by the laws of physics is the opportunity the fight for New Energy can lead to. From Our Nebula via YouTube
This commitment to 100,000 electric delivery vehicles is a gamechanger. From Amazon News via YouTube
Antarctica’s Thwaites Glacier, the size of Florida, is melting at an “alarming rate” and will likely cause sea level rise that will remake the world’s coast lines. From PBS NewsHour via YouTube
Opinion: Why is humanity so reluctant to save itself from climate change? The biggest challenge in keeping Earth from overheating isn’t technical, it’s political
Willem E, Buiter, February 23, 2020 (MarketWatch)
“…[The world’s current environmental prospects include] three obstacles: climate-change denial; the economics of reducing greenhouse-gas (GHGs) emissions; and the politics of mitigation policies, which tend to be highly regressive…There is a massive free-rider problem…Even if the current Nationally Determined Contributions (NDCs) under the 2015 Paris accord were met, emissions in 2030 would 38% above where they need to be…The NDC targets would need to be roughly tripled just to limit warming to 2°C, and would have to increase fivefold to achieve the 1.5°C goal…[D]enialism is the least serious of the three main obstacles…
As the real-world costs of climate-driven disasters mount over time, denialism will become less of an issue…The second major challenge is that greenhouse-gas emissions are the quintessential global economic externality…But given the current state of multilateralism, expecting a truly global effort in pursuit of the common good is a tall order…The third obstacle is that effective policies to reduce emissions disproportionately hurt the poor (both globally and within countries)…[A] global carbon-emissions tax is likely to be the best solution to the climate challenge…
But with such a tax in place, average household electricity prices over the next decade would increase cumulatively by 45%, and gasoline prices by 15%...The only way to square the circle is to extend financial aid to developing and emerging economies undergoing unavoidably energy-intensive development, so that they can afford to internalize the externality through an appropriately steep tax on emissions. Unfortunately, sustained large-scale international aid programs are deeply unpopular…Unless and until that changes, an existential crisis of our own making will only worsen…” click here for more
The Case For Pivoting Into Renewable Energy
Frank Holmes, February 21, 2020 (Forbes)
“…More and more, people are demanding cleaner, more sustainable energy…[It] is the direction the world is headed in. Rather than fight it, we’ve made the [investment] decision to follow the money…Last year, corporations around the world [including tech giants and traditional oil and gas companies] bought a record amount of clean energy…[In Europe,] renewables accounted for an incredible 34.6 percent of total electricity generation in 2019…[A] greater share of European households and businesses get their power from wind and solar than they do coal…[The U.S. Energy Information Administration] expects electricity generation from renewable sources to surpass nuclear and coal by as early as next year…By 2045, it may even surpass natural gas…
…[China has] been a leader in clean energy investment…[and recently joined 60] other countries in announcing a ban on single-use plastic items…[That] represents a major headwind for oil and gas companies that manufacture the petrochemicals needed to make plastic…[The] mob is clearly telling us which way the wind is blowing…Clean energy stocks have completely decoupled from natural resources, returning more than 66 percent for the three-year period through February 18. Natural resources stocks, meanwhile, returned only 11 percent over the same time…” click here for more
Northeastern utilities aim to 'crush and flatten' system peaks as DERs boost grid efficiency; DER providers and utilities have found shared market interests in New England, leading to cooperative BYOD programs that provide a range of benefits for customers and the power system.
Herman K. Trabish, Sept. 23, 2019 (Utility Dive)
Editor’s note: Utilities are beginning to welcome customers’ devices as a way to manage their increasingly variable and hard-to-predict demand and supply.
The power system's growing need for flexible load and customers' rising demand for backup power are driving new partnerships between utilities and providers of customer-sited resources across the Northeast. Vermont's Green Mountain Power (GMP) is leading this transition toward distributed energy resources (DER) as grid assets. But others are right behind. And instead of the usual market battle, DER providers and utilities are becoming enthusiastic collaborators.
The objective is "a home-, business- and community-based energy system," GMP CEO Mary Powell told Utility Dive. "We envision a future in which the distribution system is primary [and] the distribution utility is the symphony conductor of many different DER devices, with battery storage leading," she said. "And the devices are an almost living, breathing system that inhale when costs go down and exhale as prices go up."
New bring-your-own-device (BYOD) programs, which target peak demand reductions, are just the beginning, stakeholders told Utility Dive. Synergies among utilities, DER providers and customers can deliver a range of cost-effective advanced grid services. The key, they said, is standardized pay-for-performance and shared savings provisions to protect ratepayers. There are BYOD programs or proposals in Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island, Maine and New York. But four states are leading.
GMP's DER programs have attracted over 2,700 customers, Powell said. The utility now has 11 MW of DER assets, including customer-owned batteries, EV chargers, water heaters and heat pumps. Battery programs have generated over $800,000 of net value in grid services since 2018 while maintaining customer access to the batteries for backup power. In a new BYOD proposal, private sector providers will aggregate customer-owned devices and "be compensated for reducing kWs over the peak hour each month and each year," she said. The amount of compensation to DER providers and their customers depends on how DER is used… click here for more
Watch these four clean energy trends in U.S. cities
Lacey Shaver, February 13, 2020 (GreenBiz)
“…American cities, states and businesses already have come a long way on the road to cutting greenhouse gas emissions to help tackle the climate crisis…This puts these subnational U.S. actors on pace to reduce emissions 25 percent below 2005 levels by 2030…[There are four] energy trends in U.S. cities to watch in 2020…1. Cities will sign unprecedented utility-scale clean energy deals…2. Cities will work with businesses to cut carbon emissions…
…3. Cities will band together to overcome barriers to clean energy…4. Cities will explore new channels to influence their energy future…Cities are increasingly aware of the influence that utilities and state regulatory commissions have over the renewable energy options available…[and] have formally partnered with their investor-owned utilities…Cities are also starting to participate in regulatory proceedings at state public utility commissions…[Key words for 2020 are] collaboration and creativity…” click here for more
The Costs of Revving Up the Grid for Electric Vehicles
Anshuman Sahoo , Karan Mistry , and Thomas Baker, December 20, 2019 (Boston Consulting Group)
Electricity is poised to emerge as the dominant fuel for automotive transportation in the decades ahead. However, in order to meet the demand for power that transportation electrification (TE) will create, utilities must perform a tricky balancing act. They need to invest in upgrading the pipeline for that fuel—the transmission and distribution system (or grid)—without triggering excessive upward pressure on consumer electric rates.
How exactly can utilities manage the tradeoffs? To understand the dynamics at play, BCG developed a detailed model of revenues, costs, and retail-rate impacts for a “representative” utility with 2 million to 3 million customers. (See the sidebar, “Modeling the Impact of Electric Vehicles.”) We found that the representative utility, depending on charging patterns, will need to invest between $1,700 and $5,800 in grid upgrades per electric vehicle (EV) through 2030. Given that these grid investments will largely be covered in the rate base, the cost of the investments will ultimately be passed on to ratepayers. In the majority of scenarios considered in our model, ratepayers will see some upward pressure on rates. At the high end, rates could increase 1.4 cents per kilowatt-hour (kWh), or 12%, from an assumed baseline rate of 11 cents per kWh.
To head off that sort of hit to ratepayers, utilities—while still encouraging the adoption of EVs—need to develop a plan for transmission and distribution updates that minimizes the investment required in the grid. The plan should include shaping consumer behavior, deploying technology to minimize the strain EVs will put on the grid, and creating a blueprint for investments and other actions that drive TE.
QUANTIFYING THE GRID COSTS OF EVS
There’s no denying it—EVs are going mainstream. BCG expects that, by 2030, EVs (mild and full hybrids, plug-in hybrids, and battery EVs) will account for 50% to 60% of new-car sales and 21% to 27% of all light-duty vehicles (such as passenger cars and SUVs) on the road. And the vehicles that will impact utility operations the most—plug-in hybrids and battery EVs—will account for 20% to 30% of new sales and 7% to 12% of all cars and trucks in use.
The growing electrification of mobility creates significant opportunity for utilities. The most significant is the opportunity to upgrade and enhance the electric grid.
The Impact of EVs on the Grid. Although the widespread adoption of EVs will require a significant increase in grid capacity to handle certain locations and time periods of high charging demand, the impact on overall energy load will be less dramatic.
To understand why, imagine a fleet of 200 public-transit buses charging simultaneously. If they were all to charge overnight using an 80-kilowatt (kW) charger, which charges at a relatively slow rate, they would demand 16 megawatts (MW) of grid capacity. However, if even 20% of those buses needed to charge quickly during the day (using 450 to 500 kW chargers for roughly 10 to 15 minutes), they would require 18 MW of grid capacity. That is the same amount of capacity demanded by roughly 3,000 homes at their peak capacity needs.
To ensure that the grid can handle this demand, utilities must invest in new and upgraded distribution assets to carry electricity from the transmission system to EV chargers. Although increased demand will initially put the most strain on distribution circuitry and substations, utilities will eventually need to make investments in transmission lines and substations as well.
Utilities will likely need to recoup part of their investment through higher retail rates. The additional revenue from electricity sales for EV charging will offset some of those investments. However, utilities will likely need to recoup part of their investment through higher retail rates. In addition, investment costs—and therefore the pressure on rates—will be magnified as EV adoption ramps up. That’s because investment costs increase exponentially as penetration increases, given the need for more expensive equipment and a larger number of new assets.
Modeling the Impact. How quickly EVs are adopted, as well as where and when people charge them, significantly impacts the projected grid costs of EVs. Consequently, we modeled nine scenarios for a representative utility. These scenarios are based on three different levels of EV adoption for the light-duty fleet within the utility’s territory—10%, 15%, and 20%—and three different patterns of charging by customers. The charging patterns are as follows:
Optimized: 50% of charging occurs during off-peak hours and 50% during shoulder, mid-, or partial-peak hours. Overall, a significant portion of charging activity occurs where grid capacity is not constrained.
Moderately Optimized: 33% off-peak charging; 33% shoulder, mid-, or partial-peak charging; and 33% peak charging. Some charging occurs in areas with capacity constraints.
Nonoptimized: 25% off-peak charging; 25% shoulder, mid-, or partial-peak charging; and 50% peak charging. Significant charging occurs in areas where grid capacity is constrained.
Our base case scenario assumes that EV penetration will gradually increase from about 1% in 2019 to roughly 15% in 2030, with a moderately optimized charging pattern. Under this scenario we can project transmission and distribution costs and energy consumption:
Transmission and Distribution Costs. Given 1.1 million EVs in service by 2030, our model estimates that the representative utility will need to make cumulative transmission and distribution investments of $2.8 billion through 2030, for an estimated grid capacity upgrade cost of $2,600 per EV. That’s a meaningful sum given that a US utility of this size tends to spend about $1 billion annually on transmission and distribution capital expenditures. As noted earlier, most of these costs are from investments in distribution assets; transmission assets account for only $110 per EV in costs, or less than 5% of the total investment costs.
Energy Consumption. We assume that, on average, an EV in the light-duty fleet within the utility’s territory will consume about 2,960 kilowatt-hours (kWh) per year from 2019 to 2030.
Charging patterns will have a major impact on both transmission and distribution costs and energy costs. If customers embrace optimized charging, less investment in higher-voltage and more-expensive transmission circuits and new transmission substations will be required. On the distribution side, optimized charging would limit the number of substations that must be upgraded as well as the number of substations, circuits, switches, and service transformers that must be added.
In addition, given that the wholesale cost of electricity generally varies throughout the day according to demand, energy costs will be lower if utilities can incentivize customers to adopt optimized charging behaviors. At the same time, such charging patterns can minimize the need for new power generation investment.
MANAGING THE COSTS OF GRID ENHANCEMENTS
The degree to which utilities succeed—or fail—at optimizing both the timing and location of EV charging will determine whether customers see big rate hikes.
Charging patterns determine costs and investments. Our model quantifies how different charging patterns impact total costs. On the generation cost side, we assumed wholesale costs of $23, $29, and $34 per megawatt-hour (MWh) for the off-peak; shoulder, mid-, or partial-peak; and peak charging periods, respectively. Given those costs, the cumulative generation cost (per EV) to the utility from 2019 to 2030 will vary from $770 to $880, depending on the charging pattern.
Looking at transmission and distribution investments, the optimization of both timing and location would allow a decrease of roughly 70% in transmission and distribution costs per EV through 2030—from $5,800 in the nonoptimized charging scenario to $1,700 in the optimized scenario. (See Exhibit 1.)
Demand from EVs can put upward pressure on rates. For customers, the best-case scenario in our model results in rates that are essentially flat. However, in most of our scenarios, rates rise—in some cases significantly—as utilities meet increased demand from EVs.
To model this dynamic, we look at the impact on both costs and revenues. The cost impact includes both the cost of generating or buying electricity and the investment required in transmission and distribution. This cost impact is offset by new revenues from EV charging. Without changes in the retail rate, these new revenues may not compensate the utility for all of its costs. The difference between the cost and revenue impacts is the rate impact—the change in rate required for the utility to fully recoup its investments and the increase in electricity costs.
Across our model scenarios, we estimate that increased generation costs and transmission and distribution investments will increase retail rates from 0.03 cents to 1.35 cents per kWh, which equates to an increase of less than 1% to 12% on the initial rate of 11 cents per kWh. The range reflects the implications of the nine scenarios, which differ in the level of EV adoption by 2030, and the optimization—or lack thereof—of charging, as described earlier. For a given level of EV penetration, the rate increase shrinks as the timing and location of charging are increasingly optimized. (See Exhibit 2.) At 15% penetration, for example, the rate impact drops from 0.91 cents to 0.04 cents per kWh as timing and location are optimized.
In our base case (15% EV penetration by 2030 and a moderately optimized charging pattern), we estimate that retail rates will rise by 0.24 cents per kWh, an increase of roughly 2%. That increase will occur despite significant boosts in revenue from EV charging. In the optimized charging scenarios, and especially at low levels of penetration, the revenue hike nearly offsets higher costs and leaves rates essentially unchanged.
The equation changes quite a bit as EV penetration increases. Notably, the difference in the impacts on retail rates between grids with optimized charging and those with nonoptimized charging widens. That’s because, as noted earlier, the equipment and other investments required to upgrade the grid become more expensive as EV adoption advances. At 50% EV penetration, for example, the rate impact in a nonoptimized charging scenario is roughly 4.75 cents per kWh—almost 20 times the rate impact of 0.25 cents per kWh under an optimized charging scenario. (See Exhibit 3.)
THE GAME PLAN FOR UTILITIES
To minimize the costs to ratepayers, while maintaining their ability to capture a share of the value for upgrading the grid for EVs, utilities need to take action in three areas.
Plan ahead. Utilities should build a roadmap of programs that will enable them to enhance the grid to meet EV demand at a reasonable cost. After all, customers won’t be happy waiting years for a distribution upgrade so that they can deploy EV chargers.
To do this, utilities should use their detailed network maps to identify the sites where they anticipate material demand for EV charging infrastructure. They should then segment the sites into those that would require minimal or no grid upgrades and those that would need substantial grid upgrades. On the basis of that insight, utilities can develop a plan that both minimizes the extent of grid upgrades required at all sites and meets the requirements of the sites that are in need of major upgrades.
Regulated utilities in particular should prepare to make a series of regulatory filings that will allow them to recoup their investments in upgrading the transmission and distribution system. This will put them in a position to help fuel future EV growth. Utilities should adopt new technologies to limit the strain that EVs put on the grid.
Deploy new technology. Utilities should adopt new technologies to limit the strain that EVs put on the grid. Doing so includes investing in infrastructure improvements such as advanced electricity metering technology, which allows them to charge different rates for electricity depending on the time of charging. Utilities should also invest in improvements to that technology that will allow differential pricing on the basis of location, in order to incentivize charging in some locations and discourage it in others.
In addition, most utilities should deploy controlled demand response systems that automatically shift EV charging to the right times and places on the basis of pricing signals from the grid. These systems can, for example, actively manage when specific chargers are allowed to charge EVs. The systems can make these charging decisions by leveraging information from devices that update the utility on a vehicle’s battery status.
At the same time, utilities should actively manage traditional sources of power demand, such as air conditioning, heating, and ventilation. Such efforts can help ensure that overall demand—including that from EV charging—can be met with existing grid capacity.
Moreover, utilities can help deploy battery storage at charging stations. These systems allow batteries to be charged during off-peak hours so that customers can use batteries, instead of the grid, to charge EVs during peak periods.
Shape customers’ charging behavior. As they strive to minimize the extent of grid upgrades, utilities can employ their new tools and technology to encourage EV charging during off-peak periods and discourage it in parts of the grid that are already capacity-constrained.
They should design rates in a way that dissuades customers from charging at times of high demand for grid capacity; techniques include time-of-use rates, hourly pricing, and demand charges. As the technology that enables differential pricing by location matures, utilities should also introduce rates that help direct where EVs charge. At the same time, utilities need to determine which costs should be spread across the rate base and which should be borne by particular customers. After all, the additional grid enhancements will not necessarily benefit all customers equally. Utilities may want to work with regulators to come up with ways to pass the investment cost along to customers in proportion to the benefit they receive from those investments.
EV market growth is just beginning, and it has the potential to create a win for both utilities, who aim for profitable growth, and regulators, who look to promote cleaner sources of energy. Nevertheless, a grid that can handle the demand from EVs will come at a cost. The task for utilities is to develop a strategy that supports EVs but minimizes the costs to customers.
The response to the climate crisis is now being led by the biggest investors and corporations in the world, simply because “fossil fuels will not be a good investment.” From YaleClimateConnections via YouTube
The $10 Billion Bezos Earth Fund will start giving grants this summer. From CBS News via YouTube
The transition is on and investors can see it. From CNBC Television via YouTube
Oil and gas production is contributing even more to global warming than was thought, study finds
Drew Kann, February 19, 2020 (CNN)
“…Scientists say that atmospheric methane is now responsible for about 25 percent of the human-caused warming…[and] a new study finds that methane emissions from fossil fuels are between 25% and 40% larger than past research had estimated, revealing that oil and gas production is contributing far more to warming the planet than previously thought…[Sources of methane in the earth's atmosphere] can be divided into two categories: biological and fossil…Biological methane is released by the decay of plants and animals in environments like wetlands, but also from human activity like cattle farming, landfills and rice fields…[Fossil methane] can seep naturally from underground, or it can be released into the air by human extraction of oil and gas…
...[M]ethane concentrations in our atmosphere have soared by about 150 percent in the roughly two centuries since the Industrial Revolution…[The new research shows] that oil and gas production account for nearly half of all the methane in our air that is attributable to human activity…There is not as much methane as carbon dioxide in our atmosphere, but a molecule of methane has a global warming potential that is 20 times greater than carbon dioxide…[which means] the methane emissions associated with natural gas production are a serious problem for the planet…[H]uge amounts of methane are being released from oil and gas facilities around the US…” click here for more
Renewable Energy Worldwide: 100%
February 10, 2020 (PR Newswire via Yahoo Finance)
“…Utility scale energy storage is an essential aspect of achieving a no carbon world energy profile…This study shows the opportunity for companies in the renewable energy business to leverage storage as a way to gain strategic advantage in the market…Batteries are changing in response to the implementation of wind and solar renewable energy systems. Lithium Ion batteries represent the state of the art now. Solid state batteries represent the next generation of power storage for vehicles. Nanotechnology permits units to be miniaturized, standalone, and portable. Utility scale lithium flow batteries have been developed to offer utility scale advantages…
...[L]imitations that are still being addressed by vendors…[Projects can now be financed but a] wave of advances is bringing a new generation of utility scale batteries. Flow batteries support deployment of wind and solar power on a grand scale…Demand for storage increases as the value it provides is recognized. Utility scale energy storage is useful in balancing the proportion of variable, renewable generation…Batteries increasingly will be chosen to manage this dynamic supply and demand mix…Global energy storage is on an upward trend in any case, promising a multi-fold increase every year…[SolarReserve has demonstrated 400 MWh storage capability for concentrating solar power projects and its Sandstone project] will have 20,000 MWh of storage…” click here for more
As utilities scramble to manage explosive DER growth, is power grid autonomy a solution? The U.S. electric grid could face hundreds of millions of distributed resource deployments in the near future. But optimizing these data points may exceed human ability.
Herman K. Trabish, Sept. 11, 2019 (Utility Dive)
Editor’s note: Real artificial intelligence and autonomy are still a long way off but there are some autonomous functions that can help with today’s challenges to managing an increasingly complex distribution system.
Within a decade, there may be more distributed energy resources (DER) coming onto distribution systems than any utility control room can manage. An autonomous energy grid (AEG) could optimize those high levels of DER for the benefit of power system and DER owners, research under development by the National Renewable Energy Laboratory (NREL) shows. But if this groundbreaking system autonomy proves elusive, utilities could face voltage and frequency fluctuations, potential supply-demand imbalances or even outages, according to distribution system experts.
NREL’s concept “is about controlling hundreds of millions of different kinds of devices in real time on a second-by-second basis," DOE Power Systems Engineering Center Director Benjamin Kroposki told Utility Dive. A successful AEG concept would require greater technical precision than autonomous driving and the Internet, the two most comparable examples in terms of data management, data analyst specialists and utility system authorities told Utility Dive. But the expected massive growth of DER makes NREL's ambition necessary, according to Kroposki.
Residential solar installations are expected to grow approximately 8% annually through 2050. Behind-the-meter storage deployments are anticipated to hit almost 1.9 GW by 2024. Current forecasts project around 18.7 million EVs on U.S. roads in 2030. It is not unreasonable to imagine electricity customers a decade from now having up to five devices at a time — a rooftop solar system, a home battery, a smart thermostat, a smart water heater and an EV charger, said Kroposki. By that math, the 4 million customers in the San Francisco Bay area could leave PG&E with 20 million devices to manage.
Utilities will also see rising penetrations of bulk system wind and solar generation that will create supply-demand imbalances that traditional control centers will not be able to manage simply by ramping supply up or down, he said. Instead, it will require managing demand, which could be done through DER technologies. But the sheer volume of DER could exceed a utility's ability to optimize. A comparable challenge is managing the Internet's hundreds of millions of data points, but the power system is under higher pressure to maintain precise moment-by-moment supply-demand balance and avoid any delays, he added.
The basic element of NREL's theoretical AEG architecture is the optimization and control of a "cell," which can be a home or building energy management system and their controllable devices. Kroposki describes the AEG as "distributed cells with a hierarchical, scalable, reconfigurable and self-organizing control structure on top of them."
The next level up may be the distribution circuit, and the level above that might be a substation, Kroposki said. "Each level's cells have parameters and constraints, like voltage, currents or system pricing, that they use to self-optimize and maximize self-optimizing at each level." Pilots are testing optimization algorithms… click here for more
The 50 States of Grid Modernization: Grid Modernization Activity Continues to Climb in 2019 February 5, 2020 (North Carolina Clean Energy Technology Center [NCCETC])
“…Grid modernization actions were taken by 46 states and the District of Columbia during 2019, the 2019 annual review and Q4 2019 update edition of The 50 States of Grid Modernization found. The greatest number of actions related] to energy storage deployment, customer data access policies, smart grid deployment, utility business model reforms, and distribution system planning…[NCCETC’s top ten grid modernization trends of 2019 were] State regulators establishing guidelines for distribution system plans…Utilities failing to justify the costs of grid modernization investments…Utilities including new energy storage capacity in integrated resource plans…
...States considering performance incentive mechanisms…States enabling access to customer energy usage data…Utilities pursuing advanced rate design pilots…States considering major utility business model reforms…Utilities including energy storage offerings within energy efficiency and demand-side management plans…Regulators emphasizing programs and rates to make full use of smart meter functionality…[and] States examining interconnection and compensation rules for battery storage…A total of 612 grid modernization actions were taken during 2019, representing a 33 percent increase in activity over 2018 (460 actions)…” click here for more
Introduction to Energy Storage
Faith M. Smith, January 23, 2018 (ClearPath)
Energy storage can help the grid in so many ways – it allows us to save electricity for a more appropriate time or can be used in multiple applications to assist in balancing and maintaining the grid. While energy storage can be complicated, this paper is meant to break it into digestible pieces. The electricity grid is the centerpiece of the puzzle. The grid can be broken into three parts: generation, transmission, and distribution. In order to meet demand, utilities must be prepared to distribute electricity instantaneously, through a constant balance of supply and demand. The grid receives its electric current from electricity generation and in some cases from stored electricity through energy storage. In the simplest terms, energy generation controls time, from when and how we use it.
Energy storage applications can fall into all portions of the grid and can be helpful as a way to improve the overall energy grid.
Generation is where electricity is produced and energy storage applications can assist in various ways to ensure adequate electricity supply is available. Energy storage can supply energy when demand is larger than current supply, if there are any disruptions in traditional forms of generation, and at times when renewable resources are not generating electricity. One prime example of assisting in meeting demand is the use of storage during “peak,” where the demand reaches its highest point during the day. Rather than turn on a natural gas power plant to meet peak demand, storage applications can be used instead. Using storage in some cases can potentially reduce the carbon consumed or save in cost in some locations. In most cases, energy generation occurs far from population centers, which requires the generation to be transmitted across long distances.
Transmission lines then carry the generated electricity to be distributed. Energy storage applications can help in the meantime to help relieve congestion, potentially deferring transmission upgrades, and can provide grid stabilization and maintain continuous power supply. Distribution to customers occurs after being converted to a lower voltage from the transmission lines. Energy storage applications can also apply in distribution to provide backup power in case of outages, for microgrids, and in reducing demand charges for customers by providing additional electricity during peak demand.
The Origins of Energy Storage
Energy storage as a technology has been around for almost a hundred years in the United States and Europe through pumped hydroelectric storage.2 Modern energy storage as we know it began in 1978 at Sandia National Lab through a program called “Batteries for Specific Solar Applications,” which focused on developing batteries along with other renewables.3 This program began shortly after the formal creation of the Department of Energy and was expanded quickly with a focus on batteries for electric vehicles. Over time, this program, now known as the Energy Storage Systems Program (ESSP) grew to include additional energy storage technologies such as flywheels and compressed air energy storage. While the ESSP initially began at Sandia National Lab, cross-collaborative research from materials science to demonstrations of energy storage technologies continues at Argonne National Lab, Oak Ridge National Lab, and Pacific Northwest National Lab. Research from these labs have continued to develop in the private sector, alongside separate private research and will continue to evolve over time.
Types of Technologies
Energy storage as a whole includes multiple technologies within chemical, mechanical, thermal, and kinetic energies. Chemical energy includes current batteries through chemical reactions within various battery types. Mechanical energy includes pumped hydro and compressed air energy storage. Thermal energy includes solar thermal power plants as well as heating and cooling objects by creating large temperature differences to store excess energy for later use. Flywheels are an example of kinetic energy.
Lithium-ion batteries range in chemistry composition, but all lithium-ion batteries transfer lithium-ions between their cathode and anode, where the cathode is usually a metal oxide and the most common anode is made up of graphite. Lithium-ion batteries can have a liquid electrolyte or a solid state electrolyte. Lithium-ion batteries have a lithium polymer where the electrodes are bonded together by a porous polymer matrix. This means the battery itself has a specific chemistry that varies, changing the battery’s capabilities. Depending on chemistry differences, there are benefits and concerns with each type as well as some being more successful than others. The benefits of lithium ion include: high energy density, less expensive, have long lifetime cycles, are rechargeable, have low maintenance, and have high rate discharge capability. Lithium-ion batteries have been successfully deployed in electric vehicles, mobile phones, and laptops. There is growth in research, design, and manufacturing for large scale projects for use in grid scale storage applications.
Solid State Batteries
Solid State Batteries have solid electrodes, cathodes, and anodes regardless of their chemistry. Basic chemistry varies in the types of solid state batteries, with three being very common: lithium-ion, nickel-cadmium, and sodium-sulfur. In addition to solid state lithium-ion batteries, other solid state batteries include those with the chemical compositions of nickel-cadmium and sodium-sulfur. Nickel-cadmium batteries are considered a traditional battery, meaning they remain a valid option to provide a long and reliable life cycle even when energy density and cost are not as great as lithium-ion. Nickel-cadmium batteries have been used successfully in grid scale storage as well for short duration use, and in island grid systems. Sodium-sulfur batteries are another stationary application with high efficiency. Japan has demonstrated this technology at multiple locations for six hour duration for peak shaving purposes.4 While both of these battery chemistries have been tested and deployed they are still not nearly as common as lithium-ion batteries, which currently dominate the market.
Flow batteries consist of a reversible chemical reaction, which occurs in multiple tanks. The electrodes are dissolved in electrolyte solutions stored in tanks – an anolyte tank containing an anode and a catholyte tank containing a cathode. These are pumped into cell stacks where the reversible reactions occur when the battery charges and discharges.5 There are two main flow battery systems: True flow or pure flow where all materials are stored separately from the cell and hybrid flow batteries where one or more of the active materials are stored within the cell.
Flow batteries can also vary depending on the materials used for the chemical reaction in the electrolyte tanks. Flow batteries store energy in the liquid electrolyte tanks while traditional batteries store energy in their electrode materials. Flow batteries have high energy efficiency, long life cycles, can be long duration with fast response times as well as being capable of deep discharges. However, electrolyte stability is always a concern along with potential corrosion of materials.
Flywheels are a very short duration form of energy storage that store energy by accelerating and braking a rotating mass – it’s connected to a reversible electrical machine that acts as a motor during charge that draws electricity from the grid to spin the flywheel up to a selected operating speed. The amount of energy that can be stored in a flywheel depends primarily on the momentum of inertia of the rotor (weight) and the speed at which it rotates. While flywheels have fast discharging capabilities, long life cycles, and no capacity degradation over time, they have low energy density, and can self-discharge. Overall flywheels would be best for frequency stabilization in the power grid rather than medium or long duration storage.
Compressed Air Energy Storage
Compressed Air Energy Storage or CAES stores energy in the form of compressed air in an underground reservoir for use at a later time. CAES is very similar to pumped hydro power in storage concepts, however, usage of the stored air is different than simply releasing water through a turbine. CAES systems release the pressurized air by heating it in order to expand it, which then turns a turbine, generating electricity.6 This is done through two systems – diabatic or adiabatic. Diabatic systems are really hybrid systems, where natural gas is used to heat the compressed air, resulting in expansion and a way for the turbine to generate electricity. Adiabatic systems do not use natural gas to reheat the air in the expansion process, rather the excess heat is stored above ground for future use when the air is meant to be expanded. Currently, only two CAES diabatic grid scale systems exist, one in Alabama and one in Germany. CAES have several benefits, but ideally they work best in balancing energy, for greater integration of renewable energy, ancillary services for the grid such as regulation, black-start, and grid stabilization.
Thermal Energy Storage
Thermal energy storage takes excess energy and stores it in various materials, including rocks, cement, storage tanks, hydrogen, and in liquid air. This is really a transfer of energy into a material that is capable of storing the energy for a longer time frame instead of wasting the excess or less expensive energy. A great example of this is solar thermal water heating.
Heating and Cooling of Materials
Some promising industry experiments are focused on storing excess energy in the form of thermal energy in materials such as rocks. The temperature in these substances can be cold or hot as there is energy in both forms. Siemens is currently conducting an experiment in heating rocks with excess energy until it is needed at a later point, when it will be used to drive a steam turbine to generate electricity.7
Traditional Pumped Heat Electrical Storage compresses and expands gas through tanks filled with crushed rocks. This is usually a closed circuit where the gas is connected between a compressor and expander heating and cooling the crushed rocks as needed to store or use energy.
Hydrogen Energy Storage
Hydrogen Energy Storage stores electrical energy in hydrogen through electrolysis. This means electricity is used for hydrogen production through a process called electrolysis where water molecules are split into oxygen and hydrogen ions. The oxygen is released and the hydrogen is stored in pressurized containers and can be used as a fuel to be burned in combined cycle gas fired power plants or re-electrified later through fuel cells.8
Liquid Air Energy Storage
Liquid Air Energy Storage stores energy through compressed and liquefied air. This works in three steps – charging occurs when electrical energy pulls air from the environment, cooling the air until it liquefies and is then stored in an insulated tank at low pressure until it is needed later. When the energy is needed, the liquid air is pulled from the tank and pumped to a higher pressure, where it evaporates and is heated, producing a high pressured gas that is used to turn a turbine.9
Pumped Hydropower uses gravity to turn a turbine. While this technology has been successful since the 1920s, it has been modified for additional uses such as underground pumped hydro, reservoir pumped hydro, and variable speed pumped hydro.10 In many cases, pumped hydropower is used as a form of baseload electricity generation because it is reliable and inexpensive. However, over time it has become much more complex, and can be used in various ways to help improve grid stability and even act like a “peaker plant,” used at times when peak energy demand is at its highest to help reduce consumption of natural gas in natural gas peaker plants through variable speed pump-turbines.
Traditional pumped hydropower stores energy in an upper reservoir or one higher in elevation than a lower reservoir. When wanting to store energy, water is pumped to the higher reservoir for later use. To “discharge,” or use the stored energy, it is released to the lower reservoir to generate electricity by turning a turbine.
Underground pumped hydropower uses two reservoirs as well, they are both underground. These can be in man made storage reservoirs, mines, or caverns as well. In this system, energy is pumped from the lower reservoir to the higher reservoir as it “charges” the system, and to generate electricity, the water is released from the higher reservoir to the lower reservoir.
What role does Energy Storage play in the future
The future of energy storage is very promising and will continue to evolve as new technologies are developed. As costs decrease and renewables continue to grow, energy storage may have a larger market share. Currently there are no federal energy storage policies or mandates, however, there are a few states with energy storage mandates or policies. State policies, wholesale market rules, retail rates, and technological innovations are expected to impact the future of energy storage as a whole.
The Federal Energy Regulatory Commission (FERC) released Order 841’s “Final Rule” for storage participation to remove barriers for energy storage in capacity, energy generation, and ancillary services markets in February 2018. The purpose of the order is to increase competition within the markets while supporting resiliency of the power system.11 Current markets are very difficult for energy storage to fully participate due to regulations in various markets, limiting how and if storage could participate. Generally, storage was not being utilized and could not compete with less expensive resources as a stand alone option. With this Order, each Regional Transmission Organization (RTO) is required to create a participation model that opens up market participation for energy storage resources.
As the RTOs create rules based on the requirements given by FERC, it will directly impact the value of energy storage in each market. Due to FERC Order 841, state mandates or proceedings, energy storage as a whole is difficult to predict, however, significant growth is expected in the market due to benefits and the evolution of electricity generation. Recent RTO filings will also impact how the storage space as a whole continues to move forward. This is due to each RTO’s unique plan to incorporate energy storage into the future. As things progress, each region will continue to develop uniquely based on how storage is viewed and how it is integrated will have significant impacts on storage developments and electricity markets as a whole. While this will be a learning curve for storage resources in the grid as a whole, each plan will allow the markets to be more competitive and adaptive to storage needs over time.
New Promising Technologies
As technology continues to improve and costs decline, there are several promising energy storage technologies that may become viable options in the next few years. Most of these technologies are simply adaptations of traditional or well-known energy storage technologies, but have been changed to reduce cost, reduce use of resources, or to increase energy efficiency for example. Several organizations have spurred out of the Department of Energy, universities, and think tanks all with a variety of funding from government grants or loans to foundation investments. Some interesting and promising technologies include storing energy in cement blocks as a way to mimic pumped hydro, an adapted version of subsurface pumped hydro, and liquifying air in a similar manner to compressed air energy storage.
Two new temperature records: 2020 had the warmest January in history and Antarctica has never been this hot. And projections show “it continues to get worse to the extent that we do not change our behavior.” From CBS News via YouTube
Nobody knows how bad it will get because the market does "now" risk and the climate crisis keeps threatening worse and worse "future" risk. From CNBC via YouTube
Analysts see Tesla as a good investment. From CNBC Television via YouTube
Climate change models predicted ocean currents would speed up — but not this soon; Ocean currents are the undersea conveyor belts that help regulate Earth's climate and influence weather systems around the world.
Denise Chow, February 11, 2020 (NBC News)
“Ocean currents — undersea conveyor belts that help regulate Earth's climate and influence weather systems around the world — have been speeding up over the past two decades as the planet warms…The puzzling discovery…highlights that climate change could have wide-ranging effects that are unexpected or severely understudied…Climate models had predicted that ocean circulation would accelerate with unmitigated climate change, but the changes had not been expected until much later this century…[This] suggests that some climate models may underestimate the effects of global warming…
[C]urrents in three-quarters of the world's oceans have accelerated [by 36 percent since the early 1990s], driven primarily by faster, more intense winds…Ocean currents form a complex web of underwater highways that move water and heat around the globe. Warm water funneled by currents from the equator to the poles, for example, helps regulate land temperatures and drive weather systems…Scientists have observed an increase in the intensity of surface winds, combined with a steady rise in greenhouse gas emissions, since the 1990s…[The exact links] are still unknown…[but] major impacts on fisheries could have cascading effects up and down the food chain, with impacts on countries and communities that depend on fishing…” click here for more
Renewable Energy Market by Type (Hydroelectric Power, Wind Power, Bioenergy, Solar Energy, and Geothermal Energy), and End Use (Residential, Commercial, Industrial, and Others): Global Opportunity Analysis and Industry Forecast, 2018–2025
November 2019 (Valuates Reports)
“…Increasing awareness and knowledge about carbon footprint management is expected to generate lucrative growth prospects for the renewable energy market globally…The global renewable energy market was estimated at USD 928.0 Billion in 2017 and is expected to reach USD 1,512.3 Billion by 2025, posting a 6.1 percent CAGR from 2018 to 2025…Increased greenhouse gas emissions (GHGs), especially CO2 from the use of fossil fuels for energy generation and the dwindling existence of fossil fuel on Earth coupled with its high costs, are fueling the renewable energy market…
However, the generation of energy from renewable sources requires huge capital…Continuous technological advancements and increasing government support in the renewable energy sector is expected to provide lucrative opportunities for renewable energy market growth during the forecast period. The size of the market for renewable energy is expected to grow in the developed and developing economies due to the implementation of strict government regulations regarding climate change…Asia-Pacific emerged as a renewable energy market leader in 2017, and its dominance is expected to continue over the forecast period…
China is predicted to account for the highest market share on the renewable energy market…The market is divided by type into the hydroelectric, wind, Bioenergy, solar, and geothermal energy sectors. During the forecast period, the hydroelectric power segment is expected to dominate the market…[T]he Solar Energy segment is expected to grow at the highest growth rate…” click here for more
The unknown costs of a 100% carbon-free future; State approaches to a 100% carbon-free future vary and while several costs remain unknown, some solutions are emerging.
Herman K. Trabish, Sept. 3, 2019 (Utility Dive)
Editor’s note: The value of distributed resources and the future balance between central station and distributed renewables continue to make the cost of a 100% future uncertain.
Opponents claimed zero emissions mandates in Hawaii, California, Washington, Colorado, New Mexico and New York would drive up electricity rates, but ample evidence in today's falling renewables prices led to lawmaker approval. Now, utilities and policymakers are trying to determine what the full costs of a high renewables power system will ultimately be.
But cost impact forecasts cannot be certain until technologies protecting reliability are in place, Washington and New York utilities told Utility Dive. In contrast, Colorado and New Mexico were able to use utilities' expectations of lower costs to bolster political support. There are still many unknowns about the mandates' costs, advocates acknowledged. But that is not a reason to prevent enacting them, they added.
The six mandates share a goal of very high levels of renewables and much lower greenhouse gas emissions than any state has achieved today. But their policies differ in detail. Utilities in these states don't have definitive formulas for achieving the long-term goals or a final calculation of costs. The transition to a fully decarbonized U.S. power system using currently available technologies would cost $4.5 trillion, according June's Wood Mackenzie analysis. That could mean nearly $2,000 per U.S. household per year for 20 years. But it is uncertain how much of the cost would fall on shareholders, companies or customers. Although wind, solar, and storage will make up the bulk of California's high renewables power supply, the need for "firm" generation creates another unknown, Energy + Environmental Economics found…But renewables advocates say if leaders establish a vision, engineers and advocates will find the way to achieve it…” click here for more
Renewable Energy Prices Hit Record Lows: How Can Utilities Benefit From Unstoppable Solar And Wind?
Silvio Marcacci, January 21. 2020 (Forbes)
“…[Solar and wind energy are forecast to dominate America’s new generation in 2020, making up 76% of new generation] while coal and natural gas will dominate 2020 retirements with 85% of plant closures…[For the utilities engaged in the power sector transformation, this could be a big] economic opportunity…U.S. renewable energy prices continued falling fast in 2019, with wind and solar hitting new lows…Over the last decade, wind energy prices have fallen 70% and solar photovoltaics have fallen 89% on average…
Utility-scale renewable energy prices are now significantly below those for coal and gas generation, and they're less than half the cost of nuclear…In other words, it is now cheaper to save the climate than to destroy it…[and New Energy] prices are expected to continue declining, with prices falling even farther over the next three decades…[The] utilities that stick with a business-as-usual approach do so at their own peril, increasing the risk of expensive stranded assets and higher consumer electricity prices…Instead, utilities could replace fossil fuel plants with new renewables…[New regulatory approaches and wholesale market reform can help utilities…” click here for more
Climate risk and response: Physical hazards and socioeconomic impacts
January 2020 (McKinsey and Company)
After more than 10,000 years of relative stability—the full span of human civilization—the Earth’s climate is changing. As average temperatures rise, acute hazards such as heat waves and floods grow in frequency and severity, and chronic hazards, such as drought and rising sea levels, intensify. Here we focus on understanding the nature and extent of physical risk from a changing climate over the next three decades, exploring physical risk as it is the basis of both transition and liability risks. We estimate inherent physical risk, absent adaptation and mitigation, to dimension the magnitude of the challenge and highlight the case for action. Climate science makes extensive use of scenarios ranging from lower (Representative Concentration Pathway 2.6) to higher (RCP 8.5) CO2 concentrations. We have chosen to focus on RCP 8.5, because the higher-emission scenario it portrays enables us to assess physical risk in the absence of further decarbonization. We link climate models with economic projections to examine nine cases that illustrate exposure to climate change extremes and proximity to physical thresholds. A separate geospatial assessment examines six indicators to assess potential socioeconomic impact in 105 countries. The research also provides decision makers with a new framework and methodology to estimate risks in their own specific context.
Climate change is already having substantial physical impacts at a local level in regions across the world; the affected regions will continue to grow in number and size. Since the 1880s, the average global temperature has risen by about 1.1 degrees Celsius with significant regional variations. This brings higher probabilities of extreme temperatures and an intensification of hazards. A changing climate in the next decade, and probably beyond, means the number and size of regions affected by substantial physical impacts will continue to grow. This will have direct effects on five socioeconomic systems: livability and workability, food systems, physical assets, infrastructure services, and natural capital.
The socioeconomic impacts of climate change will likely be nonlinear as system thresholds are breached and have knock-on effects. Most of the past increase in direct impact from hazards has come from greater exposure to hazards versus increases in their mean and tail intensity. In the future, hazard intensification will likely assume a greater role. Societies and systems most at risk are close to physical and biological thresholds. For example, as heat and humidity increase in India, by 2030 under an RCP 8.5 scenario, between 160 million and 200 million people could live in regions with an average 5 percent annual probability of experiencing a heat wave that exceeds the survivability threshold for a healthy human being, absent an adaptation response. Ocean warming could reduce fish catches, affecting the livelihoods of 650 million to 800 million people who rely on fishing revenue. In Ho Chi Minh City, direct infrastructure damage from a 100-year flood could rise from about $200 million to $300 million today to $500 million to $1 billion by 2050, while knock-on costs could rise from $100 million to $400 million to between $1.5 billion and $8.5 billion.
The global socioeconomic impacts of climate change could be substantial as a changing climate affects human beings, as well as physical and natural capital. By 2030, all 105 countries examined could experience an increase in at least one of the six indicators of socioeconomic impact we identify. By 2050, under an RCP 8.5 scenario, the number of people living in areas with a non-zero chance of lethal heat waves would rise from zero today to between 700 million and 1.2 billion (not factoring in air conditioner penetration). The average share of annual outdoor working hours lost due to extreme heat and humidity in exposed regions globally would increase from 10 percent today to 15 to 20 percent by 2050. The land area experiencing a shift in climate classification compared with 1901–25 would increase from about 25 percent today to roughly 45 percent.
Financial markets could bring forward risk recognition in affected regions, with consequences for capital allocation and insurance. Greater understanding of climate risk could make long-duration borrowing unavailable, impact insurance cost and availability, and reduce terminal values. This could trigger capital reallocation and asset repricing. In Florida, for example, estimates based on past trends suggest that losses from flooding could devalue exposed homes by $30 billion to $80 billion, or about 15 to 35 percent, by 2050, all else being equal.
Countries and regions with lower per capita GDP levels are generally more at risk. Poorer regions often have climates that are closer to physical thresholds. They rely more on outdoor work and natural capital and have less financial means to adapt quickly. Climate change could also benefit some countries; for example, crop yields could improve in Canada.
Addressing physical climate risk will require more systematic risk management, accelerating adaptation, and decarbonization. Decision makers will need to translate climate science insights into potential physical and financial damages, through systematic risk management and robust modeling recognizing the limitations of past data. Adaptation can help manage risks, even though this could prove costly for affected regions and entail hard choices. Preparations for adaptation—whether seawalls, cooling shelters, or droughtresistant crops—will need collective attention, particularly about where to invest versus retreat. While adaptation is now urgent and there are many adaptation opportunities, climate science tells us that further warming and risk increase can only be stopped by achieving zero net greenhouse gas emissions…