WIND AND SOLAR TO PROVIDE 30 PERCENT OF NEW ENGLAND ELECTRICITY CONSUMPTION BY 2050

Energy systems analysts of Denmark, Ireland, Germany, the UK, the Netherlands, etc., have known for decades, if you have a significant percentage of (wind + solar) on your grid, you better have available:

 

- An adequate capacity, MW, of other power plants to counteract any variations of (W+S), 24/7/365

- High-capacity, MW, connections to nearby grids

- An adequate capacity of energy storage, such as:

 

1) Pumped hydro storage

2) Hydro plants with reservoir storage

3) Grid-scale battery systems

 

The more presence of variable (W+S) on the NE grid, the more the other generators have to vary their outputs, which causes these other generators to be less efficient (more wear and tear, more Btu/kWh, more CO2/kWh).

Owners in European countries with much wind and solar on the grids get compensated for their losses.

Those compensations are charged to the general public, not to the Owners of wind and solar systems, as part of the political (subsidy + cost shifting) regimen, to make wind and solar appear price-competitive versus fossil fuels.

 

RE folks often advocate:

 

1) Electricity must be 100% renewable, or zero carbon, or carbon-neutral by 2050

2) Getting rid of the remaining nuclear plants

3) Getting rid of natural gas, coal, and oil plants

4) More biomass burning

About This Article

 

This article has four parts and an Appendix

 

Part 1 provides an introduction to miscellaneous energy topics, and consumption of world energy quantities

Part 2 provides an introduction to existing NE grid conditions

Part 3 provides an introduction to daily NE grid load shaping, to deal with heat pumps and EVs in 2030

Part 4 provides the future NE grid conditions with 20% wind and 10% solar in 2050

The Appendix shows various energy topics, such as:

 

- Turnkey Capital Costs of Grid-scale Battery Systems

- Grid-scale Battery System Operating Cost in New England

- Energy Losses of Battery Systems

- “All-in” Electricity Cost of Wind and Solar in New England

PART 1; MISCELLANEOUS ENERGY TOPICS

 

Closing Down “Dirty” Fossil Plants

 

RE folks have forced utilities to become imprudent regarding reliability of production under all weather conditions.

 

Accordingly, the UK, Texas and California had been closing down fossil plants, and building out wind and solar systems. Utilities took actions that underestimated the risk to electricity production and grid stability of having too much wind and solar. All three had rolling blackouts, and 100% blackouts, that lasted several days, during weather events, similar to what had occurred in the past.

 

1) The UK and nearby countries had long periods with minimal winds, leading to fuel shortages

2) Texas had a rare frost adversely reducing the outputs of gas plants and wind turbines

3) California had high electricity demand during a US Southwest heat wave, and minimal imports from nearby states.

 

UN Nuclear Chief Sees Atomic Energy Role in Climate Fight

 

Rafael Mariano Grossi, the director general of the International Atomic Energy Agency, sees near-zero-CO2 nuclear playing a key role regarding the world’s energy needs and CO2 reduction.

RE folks have demonized nuclear, because of waste processing and storage.

https://www.mymotherlode.com/news/science/2083337/un-nuclear-chief-...

 

Japan

Japan, with minimal domestic fossil fuel sources, adopted a new energy policy on October 22, 2021, that promotes nuclear and renewables as sources of clean energy to achieve the country’s pledge of reaching “carbon neutrality” in 2050.

https://www.usnews.com/news/business/articles/2021-10-22/japan-oks-...

 

Vermont

RE folks forced the closure of the Vermont Yankee nuclear plant, to “make room” on the grid for their own expensive, highly subsidized wind and solar electricity. The Vermont Yankee nuclear plant, after producing at about 100% of design output for 500 days, would have a shut-down for a few weeks to refuel, then would produce at 100% of design output for another 500 days. The plant proved itself highly reliable for decades, with an annual capacity factor of over 90%. In fact, the entire US nuclear sector has an annual capacity factor of over 90%, which proves it is highly reliable.

 

Russia

Russia plans to build a fleet of floating nuclear power plants and small on-shore installations, based on Russian-made small modular reactors (SMRs). These units will be available for deployment to hard-to-reach areas of Russia's North and Far-East, and for export. Such power plants could be used all over the world, instead of CO2-emitting fossil plants.

 

A Russian-built floating nuclear power plant is equipped with two KLT-40S reactor systems, each with a capacity of 35 MW, similar to those used on icebreakers. It is 144 m long and 30 m wide, and has a displacement of 21,000 metric ton. The project was started in May 2009. Reactors were installed in 2013. Since December 2019, the ship has been anchored at a dock in the City of Pevek, in northern Siberia, to provide electricity to power the plant and the entire town.

 

Steam from the low-pressure end of the steam turbine is used to produce domestic hot water and hot water for building heating. The hot water is pumped, via underground piping, to a large number of nearby buildings, i.e., a near-zero-CO2, highly efficient (about 65%), DHW/district heating system.

 

https://www.zerohedge.com/energy/russia-tests-nuclear-powered-showe...

https://world-nuclear-news.org/Articles/Russia-connects-floating-pl...

https://en.wikipedia.org/wiki/Akademik_Lomonosov

 

Global Energy Data Shows Fossil Fuels Completely Dominate World Energy Use in 2020

https://wattsupwiththat.com/2021/07/11/2020-global-energy-data-show...

 

World fossil fuel supply was 84 Percent of world primary energy in 2020. Primary energy is used for all purposes by users, such as power plants, industrial/commercial entities, processing plants, farming, buildings, transport, etc., to produce goods and services, including electricity. The percentage of fossil fuels for primary energy has remained about the same for several decades, even though wind and solar energy quantities have increased. In 2020, the percentages of the world primary energy mix were:

 

Coal, 27%; Natural Gas, 24%; Oil, 33%, a total of 84%, plus Nuclear, 4%; Hydro, 6%; Renewables, 5%, after more than 20 years of subsidies.

 

Some of the primary energy, about 10%, is used for exploration, extraction, processing and transport to provide primary energy to users. That 10% of primary energy is often called “upstream energy”.

 

For example, the A-to-Z production of ethanol from corn requires a very significant quantity of primary energy to produce a gallon of ethanol for blending with gasoline. Often, the upstream CO2 (13.56 lb CO2/gal) is ignored, and the combustion CO2 of ethanol (12.72 lb CO2/gal) is not counted; its combustion CO2 has been declared "renewable", per international agreements.

 

https://www.forbes.com/sites/rrapier/2020/06/20/bp-review-new-highs...

http://www.windtaskforce.org/profiles/blogs/politically-inspired-ma...

https://yearbook.enerdata.net/coal-lignite/coal-world-consumption-d...

 

China, India, etc., to Continue High Levels of Coal Burning, per Glasgow COP26

 

China and India will not sacrifice their economic progress on the altar of global warming. Do you really believe China and India can afford to stop burning coal? Do you think they want to? Of course not.

 

India

India made it perfectly clear at the beginning of the Glasgow COP26, the developed nations should de-industrialize first, before asking developing nations to follow suit.

India declared it would not sign the statement of COP26 goals regarding coal burning. The statement read “close down coal by 2030”. India insisted that be replaced by “phase down unabated coal” (no time limit was stated). Unabated refers to power plants without air pollution abatement systems.

BTW, China, India, and other countries, still operate such plants.

This means:

 

1) Burning coal in power plants, with air pollution abatement systems, would be unaffected (no time limit was stated).

2) The major coal burning countries, such as China, India, Australia, Brazil, etc., would continue to burn coal.

https://www.windtaskforce.org/profiles/blogs/cop26-caves-on-coal-ph...

 

China

Almost 80% of China’s electricity growth is from fossil fuels, almost entirely coal. Because China is so big, that fossil growth is worsening its own air pollution, plus the air pollution around the world; the soot falls on snow/ice-covered areas, which more quickly melts snow/ice

 

China burns about 4 BILLION metric ton of coal each year, more than the rest of the world combined. Its reliance on coal is increasing.

China has expanded its mines to produce an additional 220 million Mt of coal in 2021, up almost six percent from 2020.

China is planning to build 43 new coal-fired power plants and 18 new blast furnaces.

 

From third qtr. 2020, to third qtr. 2021, China added 460.2 TWh of fossil electricity, which is 3.9 times the total annual electricity supply of NE, or 76.7 times the annual electricity supply of Vermont.

 

Electricity production growth was 586.9 TWh, up 10.7%, of which 460.2 TWh, or 78.4%, was from fossil fuels, mostly coal.

Wind growth was 89 TWh, up 28.4%, from a low base

Solar growth was 12.6 TWh, up 10.2%, from a low base.

Nuclear growth was 33.2 TWh, up 12.3%, from a low base; equal to 33.2/4.6 = 7.2 VT Yankees in one year

 

https://wattsupwiththat.com/2021/11/03/china-still-burning-more-mor...

https://chinaenergyportal.org/en/2021-q3-electricity-other-energy-s...

 

China plans to build 200,000 MW of near-zero-CO2 nuclear plants; about 150 units, each 2,350 MW, on about 75 sites, at a cost of $440 billion, by 2035

 

Amortizing the capital cost at 3.5%/y over 60 years would be ($17,556,485,920/y) / (200,000 MW x 8,766 h/y x 0.90, CF) = $0.01113/kWh, about one third the cost of EU and US nuclear plants.

 

https://www.zerohedge.com/markets/uranium-stocks-soar-market-discov...

https://www.myamortizationchart.com

World Electricity Production, by source

Fed to grids by electricity producers = net production = gross production - self-use

“Other renewables” include electricity from biomass/tree-burning power plants

https://ourworldindata.org/grapher/electricity-prod-source-stacked

Table 1A/Source	TWh	%
Other renewables	702.89	2.7
Solar	844.39	3.3
Wind	1590.19	10.0
Hydro	4355.04	16.8
Nuclear	2616.61	10.1
Oil	1128.39	4.4
Gas	5892.44	22.8
Coal	8735.8	33.8
Total	25865.75	100.0
Fossil	15756.63	60.9

  

PART 2; EXISTING NEW ENGLAND GRID CONDITIONS 

Wind Capacity Factors

 

Unite Kingdom: This image shows the daily average capacity factors of the UK offshore (blue), and onshore (red) versus temperature (degree C).

The UK annual average CF is about 32% on-shore, and 40.4% offshore.

Note the large number of red dots for CFs of 0% to 10%, i.e., many days with weak onshore winds.

The UK has about 60 to 80 weak-wind days, spread out over a year

 

New England: The image for New England would be similar, except it would be shifted to the left, because NE has colder temperatures than the UK.

In 2020:

Electricity loaded onto the grid by all generators was about 117 million MWh/y, or a daily average of 321,000 MWh/d

Wind had an annual average CF of about 3,613,000 MWh/(1,400 MW x 8,766 h/y) = 29.4%

Wind daily average generation was 9,899 MWh/d

Almost all wind generation occurred between 5,000 MWh/d (CF = 14.9%), and 20,000 MWh/d (CF = 59.5%)

NE has about 80 weak-wind days, spread out over a year, with generation at less than 1,500 MWh/d

Periods with weak winds may last 5 to 7 days, and can occur at any time during a year.

https://wattsupwiththat.com/2021/10/25/cccs-net-zero-plans-rely-on-dramatic-rise-in-windy-days/

http://www.nvda.net/files/Renewable%20Energy%20Options%20presentation%20-%20Luce.pdf

https://www.iso-ne.com/static-assets/documents/2021/03/new_england_power_grid_regional_profile.pdf

 

EIA Dashboard of NE Grid Data

 

Here is a “Dashboard” of the NE grid, prepared by the EIA (an agency of the US-DOE), which is much more useful than the ISO-NE URL. Production data are shown on an hourly basis, for 2 days and 2 weeks, and on a daily basis, for a year

https://www.eia.gov/dashboard/newengland/electricity

 

Data for NE Grid

 

ISO-NE posts real-time data regarding grid operations, every few minutes, on a daily basis.

 

1) Go to fuel mix graph, click on rectangle with arrow, download the outputs on an Excel spreadsheet, MW, of the various electricity sources, such as gas, nuclear, hydro, wind, solar, biomass, etc., connected to the NE grid.

 

2) Go to system load graph to obtain the corresponding demand, MW

System load = Electricity loaded onto the NE grid, by all producers connected to the NE grid, including net imports from nearby grids.

 

Graphs can be prepared, based on the downloaded data, for any selected period

https://www.iso-ne.com/isoexpress/web/charts

NOTE: The images were created by Warren Van Wijck

Example 1

This image shows a stack of the electricity from all sources loaded onto the NE grid, in 2020. See table 1

Such images are often used in articles, but they lack clarity regarding the presence of each source.

It is clearer to show individual sources. See example 2

Example 2

Below are 5 images of electricity sources

 

Image 1: On July 28, 2020, a very-high-demand day, the system load, from all sources, was 493,409 MWh

 

During peak demands:

 

- Solar was 7,088 MWh from January 1, 2020 to March 1, 2020.

- Wind was 8,144 from July 1, 2020 to September 1, 2020.

 

BTW, solar peaks around mid-day, but NE peak demands occur in late-afternoon/early-evening. By that time, solar is retiring until it starts to wake up about 8 pm, in summer, or 9 pm, in winter, the NEXT day.

 

If wind were 20% and solar 10% of the NE grid load by 2050, the image would be similar, but the electricity quantities would be greater.

 

https://www.windtaskforce.org/profiles/blogs/high-costs-of-wind-solar-and-battery-systems

http://www.windtaskforce.org/profiles/blogs/cost-shifting-is-the-name-of-the-game-regarding-wind-and-solar

Image 2: Hydro was 15,494 MWh. Hydro is minimal in summer, when peak demands occur

 

Image 3: Gas was 292,657 MWh.

Gas plant capacity required during the peak demand was (292,657 MWh/d) / (24 h/d x 0.90, capacity factor) = 13,549 MW, which means almost all of NE available gas plant capacity would have to operate at very high output.

 

Image 4: NE imports were 82,447 MWh/d. Imports from NY state and Canada supply about 19% of the grid load. See table 1

 

Image 5: Nuclear was 79,447 MWh. All nuclear plants will be shut down by 2050. 

Image 1; wind, solar, system load

Image 2; hydro, system load

Image 3; gas, system load 

Image 4; imports, system load 

Image 5; nuclear, system load 

PART 3; FUTURE NEW ENGLAND GRID CONDITIONS IN 2030

 

Grid Stability and Grid Load Shaping

An electric grid with various types of synchronous power producing sources, and with minor or major connections to nearby grids, becomes an electricity delivery system, if the power sources can quickly vary their outputs, as needed by user demand.

 

The total electricity of various sources loaded onto a grid must always be equal to demand.

Temporary oversupplies, such as during high winds and mid-day sunshine, must be counteracted, on a less-than-minute-by-minute basis, by quick-reacting power plants, or absorbed by storage systems, or curtailed, to avoid instability and congestion on the grid.

 

Grid Load Shaping:

This ISO-NE report covers many of the issues regarding operating the grid in 2030. The report does not explicitly cover wind/solar lulls.

ISO-NE assumes offshore wind would be increased from 35 MW, in 2020 to 8,000 MW, by 2030

https://www.iso-ne.com/static-assets/documents/2020/06/2019_nescoe_economic_study_final.docx

The main purpose of grid load shaping is to:

 

1) Avoid grid instability issues, due to wind and solar.

2) Flatten the daily shape by managing supply and demand.

 

Wind and solar:

 

- Have weather-dependent, i.e., random outputs, which, in case of wind, can be controlled by partially feathering rotor blades, aka, curtailment.

 

- Can cause frequent stability problems on the grid, especially on grids with a large presence of wind and solar.

 

- Require quick-reacting plants, such as CCGTs and hydro plants, to counteract the (W+S) output variations, 24/7/365. The ISO-NE report shows curtailments of wind and solar would be required, if the variations would be too large, such as during high winds and mid-day solar, to avoid instability and congestion on the grid.

 

In the future, there would be millions of mandated smart heat pumps and smart major appliances, smart HVAC systems, and PHEV/EVs. Local utilities would be orchestrating the use-times of these devices. If they were turned on/off by the whims of users, there would be chaos on the grid.

 

Comments on below image:

 

1) ISO-NE used projected, hour-by-hour generation data, to obtain the below image, which shows the Modified System Load during July 27 and 28, 2030, which were high-demand days.

 

BTW, the image vertical axis is called "Production", but it should be called "Modified System Load". See figure 6.5, on page 15 in URL

https://www.iso-ne.com/static-assets/documents/2020/06/2019_nescoe_...

 

2) The image shows, gas and nuclear continue to be major sources of electricity in 2030

 

3) The image projects the presence of about 8,000 MW of new offshore wind systems, in 2030, just 8 years from now.

 

Such a rapid build-out, plus major extension/augmentation of the NE grid, would not be physically achievable, in such a short time. The production would be 8,000 MW x 8,766 h/y x 0.45, CF = 31,557,600 MWh, about 27% of the NE grid load in 2020.

BTW, the UK offshore CF is 40.4% in the windy North Sea.

 

If the NE grid load increased from 2020 to 2030, the percentage would be less in 2030. The narrow, dark-green sections of the image show the entire output could be near-zero for many hours. See page 15 of report URL

 

4) The image shows

 

Onshore wind, light green, is a mere sliver, because few additional onshore wind systems would be built by 2030. Placing thousands of 500-ft-tall wind systems, on 2000 ft-high NE ridge lines, would be environmentally unacceptable, especially by nearby people.

 

Offshore wind, dark green, often is minimal in summer, and many other hours of the year, based on historic weather data. Major wind output curtailments would be required during gusty, high-wind period

 

5) The image shows Heat Pumps, PHEV/EVs, Pumped Storage and Batteries.

Those items would be used for Grid Load Shaping

Their use would involve significant electricity losses, measured on an A-to-Z basis.

 

ISO-NE Doing Grid Load Shaping with: 

 

- Grid-scale batteries, pumped storage, etc., connected to the NE grid

- Expanded demand-curtailment-load shifting program, PRD. See table 1.

- Expanded connections to nearby grids, as practiced by many countries in Europe.

 

NE Utilities Doing Grid Load Shaping with Building Systems: Each NE state has energy efficiency programs that subsidize the installation of various “smart” electrical systems in commercial, industrial and residential buildings.

 

These “smart” systems consume a certain quantity of electricity during a day. The on/off times of the “smart” systems would be remotely controlled by a local utility, to shift demand during a day.

Electricity consumption would not be reduced. It would be shifted to different parts of the day.

The quantity of electricity subject to shifting is shown as orange in the image.

BTW, the ISO-NE report incorrectly labelled it Energy Efficiency

 

NE Utilities Doing Grid Load Shaping with EVs: If an EV originally drew 100 kWh AC from a wall outlet, about 85.0 kWh DC would end up in the EV battery, and about 1.5 kWh DC would have been sent to the EV’s 12 V battery to power various auxiliary systems during charging, for a net of 83.5 kWh DC in the EV battery.

 

A utility drawing electricity from the EV battery, such as during peak demands, as part of Grid Load Shaping, would cause a loss of about 10%, due to: 1) battery discharge losses, 2) converting the DC to synchronous AC, and 3) feeding the AC into distribution grids via a step-up transformer.

 

If 100 kWh AC were originally drawn from the grid, about 75.2 kWh AC would be returned to the grid, for a loss of 24.9%.

See table 1B

 

Would the EV owner be properly compensated by the utility, including additional wear and tear of the EV battery? See URL

https://www.windtaskforce.org/profiles/blogs/poor-economics-of-elec...

 

Table 1B/From outlet	kWh AC	100.0
Charging loss	%	15.0
In EV battery	kWh DC	85.0
To 12 V battery during charging	kWh DC	1.5
Net in EV battery	kWh DC	83.5
Discharge loss	%	10.0
To grid	kWh AC	75.2
AC to AC loss	%	24.9

 

NOTE: What would provide electricity, if offshore wind were minimal during a multi-day wind lull, which could last 5 to 7 days, and could occur at random throughout the year?

What would provide electricity, if solar, yellow, were minimal during overcast/rainy days, and during winter, after a major snowfall?

 

NOTE: Some folks think batteries produce electricity. That is not true. Batteries merely store electricity for a time period, and then release about 80% of it for later use. The other 20% are various losses, measured on an A-to-Z basis.

 

BTW, ISO-NE used 90% for battery efficiency in its 2019 Economic Report, which is in error.

See page 10 of URL. See Appendix.

https://www.iso-ne.com/static-assets/documents/2020/06/2019_nescoe_...

PART 4; FUTURE NEW ENGLAND GRID CONDITIONS WITH MULTI-DAY WIND/SOLAR LULL IN 2050

 

We have to imagine the grid in 2050, after many major changes are implemented, such as closing low-cost, low-CO2 gas plants, and low-cost, near-zero CO2 nuclear plants. During a 5-7-day wind/solar lull, which could occur at random throughout the year, according to NE weather data, there would be:

 

Grid Load Shaping

More Wind, Solar, and Import capacity, MW

More Remaining Sources capacity

More Electricity Storage capacity, such as batteries.

 

The Remaining Sources, such as domestic hydro, biomass and refuse burning, etc., normally operate at high outputs. They would be able to make only a minor contribution to offset the (W+S) shortfall during a wind/solar lull.

 

Regarding nearby grids, if a multi-day, NE-wide wind/solar lull would occur, it likely would also occur in nearby states, which could decide not to export to NE, during a lull period

 

NOTE: This actually happened when the US Southwest had a heat wave, during which California could not import enough electricity from nearby states, because these states did not have any electricity left over for export to California. RE folks had “successfully” shut down 15 of 19 Pacific Coast, because they were warming up the Pacific Ocean. The other 4 plants were due to be shut down, but that “climate fighting” measure has been placed on hold, not cancelled. None of the above had anything to do with the California transmission and distribution grids.

 

Analysis Method in this Article

 

Analyses, based on hour-by-hour values, could be made. However, such an approach would be laborious, not easy to understand by lay people, including Legislators, and would involve many spreadsheet calculations.

 

The analysis in this article is less complex, but it will provide a good understanding of some of the issues. It is based on daily averages, i.e., dividing annual generation by 365 to obtain average daily generation.

 

Comments on table 2

 

Table 2 shows the annual and daily generation of each electricity source connected to the NE grid, in 2020.

Also shown are:

 

1) The daily generation of (W+S) on the grid, in 2050

2) The daily generation of (W+S), during a lull, assumed at 0.15 x 30 = 4.5% on the grid, in 2050

 

- Wind annual average MWh/d would increase from 3.1% in 2020, to 20% in 2050, equivalent to 64,041 MWh/d

- Solar annual average MWh/d would increase from 1.8% in 2020, to 10% in 2050, equivalent to 32,020 MWh/d

 

Operation in 2050

 

It was assumed the NE grid load would remain constant from 2020 to 2050, to simplify the analysis.

In the real world, this assumption would not be valid, due to increased use of EVs and heat pumps.

 

Column 2 shows the output flexibility of a plant. Only Gas, Hydro, and Oil plants can quickly vary their outputs to counteract (W+S) output variability.

Wind and solar have wind/sun-dependent, random outputs. They could not exist on any grid, without the presence of other generators that can quickly/automatically vary their outputs to counteract the output variations.

Pumped storage systems, grid-scale battery systems, and connections to nearby grids can also be used to counteract output variations.

https://www.windtaskforce.org/profiles/blogs/pumped-storage-hydro-in-new-england

 

Columns 3 and 4 show the production of various electricity sources in 2020.

Pumped storage systems and battery systems have losses, which reduce the load on the grid.

https://www.iso-ne.com/about/key-stats/resource-mix/

 

Column 5 and 6 show MWh/d in 2050, with (W+S) increased to 30% of total NE grid load.

As a result, the NE grid fossil percent of 42.9% in 2020 became only 0.3% in 2050

 

For a 6-day (W+S) lull:

 

Normal production = 6 x (64,041 + 32,020) = 576,365 MWh

Lull production = 6 x 15% x (64,041 + 32,020) = 86,455 MWh

Shortfall = 489,910 MWh, or 81,652 MWh/d   

 

It is assumed the shortfall of 81,652 MWh/d would be offset by:

 

1) A spare capacity of CCGTs (60,000 MWh/d)

2) Rolling black-outs (15,000 MWh/d); about 100 x 15,000/320,203 = 4.7% of the NE daily load.

3) Battery storage (6,652 MWh/d)

 

BTW, if rolling black-outs would cause too much protest from people, they could be reduced, if the spare capacity of CCGTs would be increased. Increasing battery storage would be too expensive, as shown below.

  

The shortfall would be variable during a (W+S) lull. The CCGTs would need to be operated at a CF = 0.75, and ramped up/down, to offset these variations.

 

The wind/solar shortfall would require a capacity of 60,000 MW/d / (24 h/d x 0.75, CF) = 3.333 MW of CCGTs.

  

The reserve CCGTs would have to be fueled, staffed, and maintained in good working order, to counteract the (W+S) shortfall, if called upon to do so by ISO-NE.

 

Per Battery University, to achieve a long life, say 15 years, Li-ion batteries should not be discharged to less than 15%, and not be charged in excess of 80%; i.e., a working range of 65%. That range also happens to have the highest operating efficiency

 

https://www.sciencedaily.com/releases/2018/08/180801093718.htm

https://www.cnbc.com/2019/02/05/tesla-jaguar-and-nissan-evs-lose-power-in-freezing-temps-.html

https://www.windtaskforce.org/profiles/blogs/chevy-bolt-catches-fire-while-charging-on-driveway-in-vermont

https://www.windtaskforce.org/profiles/blogs/here-is-an-excellent-explanation-regarding-ev-charging-at-32f-or

 

Because battery systems perform other functions, in addition to counteracting (W+S) lulls, battery average “fullness” is assumed at 75%, i.e., available capacity to counteract wind/solar shortfall would be 75%, average - 15%, low point = 60%

 

The battery system working capacity would be 6,652 MWh/d x 6 days, shortfall x 1/0.60, available withdrawal x 1.01, transformer loss = 67,182 MWh, delivered as high voltage AC to the NE grid.

 

Turnkey capital cost:

 

CCGT plants: 3,333 MW of CCGTs would be about $5.5 billion; life about 40 years

Battery systems: 67,182 x 1000 kWh/MWh x $500/kWh = $34 billion; life about 15 years  

 

NOTE: The Hornsdale Power Reserve battery system, 100 MW/129 MWh, in Australia, is located on a 10-acre site.

NE would need 67,182 MWh/129 MWh = 521 of such systems on 5,208 acres.  

https://www.windtaskforce.org/profiles/blogs/the-hornsdale-power-reserve-largest-battery-system-in-australia

 

NOTE: The battery systems would be near 15% full after a 6-day wind/solar lull.

If a second lull would occur a few days later, existing electricity sources would not have been able to fill the battery in those few days, i.e., a second battery, of similar capacity, would be needed, unless additional CCGT capacity and connection capacity to nearby grids were available.

 

NOTE: Battery-system aging, under year-round utility service (8,766 hour/y), would be at least 1.5%/y, compounded

The capacity reduction would be at least 11%, at the 7-y mid-life, and at least 23%, at the 14-y near-end-life.

 

NOTE: Remember, none of those costs would be charged to owners of solar and wind systems.

The costs would be charged to ratepayers, taxpayers, and added to government debts.

 

https://www.windtaskforce.org/profiles/blogs/having-fun-watching-wind-and-solar-failing-to-step-up-to-power

https://www.windtaskforce.org/profiles/blogs/high-costs-of-wind-solar-and-battery-systems

https://www.iso-ne.com/about/key-stats/resource-mix/

Table 1		2020	2020	2020	2050	2050	2050
NE grid load					W+S	W+S	W+S Lull
					30%	30%	30%
		MWh/y	%	MWh/d	MWh/d	%	MWh/d
Generation		94945000	81.2	260123	260123	81.2	260123
Gas	Quick varying	49793000	42.6	136419	0.0	0.0	133844
Nuclear	Steady	25580000	21.9	70082	0.0	0.0	0.0
Renewables		11507000	9.8	31526	209019	65.3	45716
Wind	Random	3613000	3.1	9899	64041	20.0	9606
Refuse	Steady	3013000	2.6	8255	8255	2.6	8255
Wood	Steady	2315000	2.0	6342	6342	2.0	6342
Solar	Random	2079000	1.8	5696	32020	10.0	4803
Landfill gas	Steady	448000	0.4	1227	2000	0.6	2000
Methane	Steady	39000	0.0	107	300	0.1	300
Steam	Steady	0	0.0	0	0	0.0	0
Hydro	Quick varying	7728000	6.6	21173	23000	7.2	23000
Coal	Steady	147000	0.1	403	403	0.1	403
Oil	Quick varying	147000	0.1	403	403	0.1	403
PRD		15000	0.0	41	150	0.0	150
Other		27000	0.0	74	74	0.0	74
Net imports	Quick varying	23531000	20.1	64468	95541	29.8	125000
Quebec	Quick varying	13969000	12.0	38271		0.0
New Brunswick	Quick varying	2491000	2.1	6825		0.0
New York	Quick varying	7070000	6.0	19370		0.0
Pumping load		-1601000	-1.4	-4386	-4386	-1.4	-4386
Battery load		0.0	0.0	0	-4000	-1.2	-4000
Net load		116874000	100.0	320203	320204	100.0	320204
Fossil		50087000	42.9			0.3

New Wind and Solar Capacity in 2050

 

Table 2/Source	2050			2050	Existing	New capacity
	MWh/y	CF, %	h/y	MW	MW	MW
Wind, on and offshore	23374800	40.0	8766	6666	1400	5266
Solar	11687400	14.5	8766	9195	1636	7559

 

Turnkey Capital Cost for New Wind and Solar Capacity in 2050

 

Table 3/Source	New capacity	Grid cost	Plant cost	Total cost	Turnkey cost
	MW	$/MW	$/MW	$/MW	$Billion
Wind, on and offshore	5266	600000	4000000	4600000	24.2
Solar	7559	300000	3000000	3300000	24.9

APPENDIX 1

 

Turnkey Capital Costs of Grid-scale Battery Systems

 

Articles often assume turnkey capital cost of battery systems at $350/kWh, delivered as AC (which needs to be stepped up to distribution or high voltage system voltage, about a 1% loss)

 

That value would be about $500/kWh, based on five annual EIA surveys of cost trends

 

Here are the annual EIA reports for 2020 and 2021

 

Starting in 2015, EIA has prepared annual reports regarding site-specific, custom-designed, grid-scale battery systems. 

 

The average duration of deliverable electricity increased from 0.5 h in 2015 to 3.2 h in 2019.

 

Excluded are: 

 

1) Financing costs

2) Benefits of subsidies, such as grants, tax credits, accelerated depreciation, loan interest deductions, waiving of state and local taxes, fees and surcharges, etc.

3) System aging/degradation costs, because the systems had been in operation only a few years.

 

EIA 2020 Report

 

The EIA graph, based on surveys of battery system users, shows slowly decreasing costs after 2018

It appears, the range of values likely would become $900/kWh to 450/kWh in 2025.

The values would be near the high end of the range in New England. 

https://www.eia.gov/todayinenergy/detail.php?id=45596

 

The US average turnkey capital cost of battery systems was about $590/kWh, delivered as AC, in 2019. 

The NE average turnkey capital cost for such systems is about $700/kWh, delivered as AC, in 2019

 

Those prices will not decrease much for at least the next 5 to 10 years, per US EIA, unless major technical breakthroughs are discovered, and subsequently implemented on a large scale. See URL

 

EIA 2021 Report

 

Table 6 combines the data of prior reports and the 2021 report. See table 6 and page 18 of URLs

 

https://www.eia.gov/analysis/studies/electricity/batterystorage/pdf...

https://www.windtaskforce.org/profiles/blogs/economics-of-utility-s... 

 

Such battery systems operate 8766 hours per year

About 65% of capacity, from 15% full to 80% full, can be used to achieve 15-year lives

Annual capacity factor is about 0.5, i.e., a working throughput of about 50% of rated throughput

 

NOTE: Such battery systems are entirely different from the battery packs in electric cars, which operate about 700 hours per year, last about 8 years, and cost about $10,000 for a 60-kWh battery, or $165/kWh. 

That cost may become $125/kWh with more mass production in future years.

 

NOTE: Various financial services entities, such as Bloomberg and Lazard, issue reports that project lower battery system costs/kWh, delivered as AC, than the EIA, likely to hype their financial services business interests. It would be prudent to ignore those reports.

 

Table 6/Battery system turnkey cost	Range	Duration	Average
Year	$/kWh as AC	hour	$/kWh as AC
2015	2500 to 1750	0.5	2102
2016	2800 to 750	1.5	1417
2017	1500 to 700	1.8	755
2018	1250 to 500	2.4	625
2019	1050 to 475	3.2	589
2025	900 to 450		500

 

APPENDIX 2

 

Energy Losses of Grid-Scale Battery Systems

 

Articles often assume a battery loss of 10%, which likely would be only the battery.

 

That loss should have been assumed at about 20%, on a-to-z basis.

See Note.

 

Here are two sources:

 

Source 1 is based on measured data, on a-to-z basis

 

This article identifies 18 losses of a stationary battery system, totaling about 20% for a round-trip, excluding transformer losses.

See Note.

 

- The system model has four coupled, component models: 1) Battery, 2) Power Electronics, 3) Thermal Management, such as heating/cooling of batteries and enclosures, and 4) Control and Monitoring.

 

- Electricity for site lighting, O&M, surveillance, etc.

 

Open URL and click on “View Open Manuscript”

See figures 3, 4 and 17 of article.

https://www.sciencedirect.com/science/article/pii/S0306261917315696

 

Source 2 is based on EIA survey data from OPERATING grid-scale battery systems

 

Per EIA survey, grid-scale battery efficiency is about 80%, AC-to-AC basis, excluding step-down and step-up transformer losses.

Aging had only a minor effect, because the battery systems were only a few years old.

See Note.

https://www.eia.gov/todayinenergy/detail.php?id=46756

 

Sequence of Losses:

 

1) AC electricity from a distribution, or high-voltage grid, via a step-down transformer, about a 1% loss, to reduce the voltage to that of the battery

2) Through the power electronics to DC

3) In battery

4) Out battery

5) Through power electronics; DC is digitized, made into a sine wave with same phase and 60-cycle frequency as the grid

6) Via a step-up transformer, about a 1% loss, to the distribution, or high-voltage grid

 

Overall efficiency of about 78%, less with aging at about 1.5%/y. See URL

https://www.explainthatstuff.com/how-inverters-work.html

APPENDIX 3

Grid-scale Battery System Operating Cost in New England

 

I found no usable information regarding real-world operating costs, after googling on the internet for many hours. I decided the cost categories of operating a rental property are similar to a battery system.

 

1) The owning and operating cost of a rental property usually involves a down payment, say 20%, and a mortgage for 80%. The annual owning and operating cost of the property includes: 1) the cost of the mortgage, and 2) other costs, such as heating, cooling, electricity, taxes, upkeep/repairs, etc. Both costs must be offset by the rental income to break even.

 

2) The owning and operating cost of a battery system usually involves a down payment, say 50%, and a bank loan for 50%. The annual owning and operating cost of a battery system includes: 1) the cost of bank financing at, say 3.5%/y, and 2) the owner’s return on investment at, say 9%/y, and 3) other costs. The three costs must be offset by the income of the services performed by the battery system to break even.

 

Battery System Operating Modes

 

- Arbitrage mode relates to charging at night, when rates are low, and discharging during peak demand hours, when rates are high. See table 4.

- Midday solar surge mode relates to reducing the daily midday solar surge to avoid destabilizing the grid. See table 4

- RNS and FCM Charge Reduction mode relates to reducing a utility’s peak demand to reduce ISO-NE transmission and forward capacity charges. See next section

- Regulation mode relates to fine-tuning voltage and frequency of the grid (not considered in this analysis)

 

RNS and FCM Charge Reduction

 

Regional network services, RNS, are based on the utility peak demand occurring during a month

Forward capacity market, FCM, are based on the utility peak demand occurring during a year.

 

If a utility would have an average peak demand of 800 MW, a 1 MW/4 MWh battery system could reduce the demand by 800 kW (battery discharging from 90% full to 10% full), and thus reduce the RNS and FCM charges imposed on utilities by ISO-NE. The potential savings from peak shaving are estimated below.

 

RNS: 2020 RNS forecast = $129.26/kW-yr /12 = $10.77/kW-month. See page 7 of URL

If a utility could capture 800 kW during the peak hour of a month, the savings would be 800 x 10.77 x 12 = $103,408

https://www.iso-ne.com/static-assets/documents/2021/07/a03_tc_2021_07_14_rns_rates_presentation.pdf

 

FCM: 2020 FCM forecast = $5.30/kW-month. See URL

If GMP could capture 800 kW during the yearly peak hour, the savings would be 800 kW x $5.30 x 12 = $50,880
This value multiplied by the reserve margin of 1.2, yields $61,056

https://www.iso-ne.com/static-assets/documents/2020/02/20200218_pr_fca14_final_results.pdf

RNS + FCM cost reduction = $164,464/y; the batteries are used only 13 d/y x 4 h/d = 52 h/y, about 0.6% of the year, to achieve this gain. Arbitrage and mid-day solar surge modes are using the batteries 99.4% of the year.

NOTE: With more utilities dreaming of a pot of gold to be gotten with battery systems, the high value of the RNS and FCM reduction may be temporary. ISO-NE needs to raise a given quantity of funds with RNS and FCM fees. If ISO-NE does not collect enough money, it merely will increase these fees, or other fees.

 

Amortizing Turnkey Capital Cost

 

The turnkey capital cost of New England battery systems, in 2021, would be about $700/kWh, delivered as AC to a high voltage grid.

Capital cost = 4,000 kWh x $700 = $2.8 million

This cost does not include 1) disposal costs of the batteries, and 2) any owning and operating costs

 

Amortizing based on 50% borrowed from a bank at 3.5%/y for 15 years, and 50% investor money at 9%/y for 15 years

Cost of amortizing = $72,624/y

See URL and Appendix

https://www.energy.gov/sites/default/files/2019/07/f65/Storage%20Cost%20and%20Performance%20Characterization%20Report_Final.pdf

 

Other Costs were assumed at $67,002/y

 

O&M costs are for: 1) power electronics, 2) thermal management, 3) HVAC of enclosures, 4) control and monitoring, 4) staffing, 5) miscellaneous items, such as site protection, lighting, insurance, taxes, upkeep/repairs, etc.

 

Assumptions

 

- A battery system able to deliver 1 MW of power for 4 hours, i.e., a rating of 1 MW/4 MWh

- Battery normal operation from 15% full to 80% full, to achieve a 15-y life.

- Battery real-world annual capacity factor at 50%

- Daily charging:

70% night-time from grid, at 3.5, wholesale + 1.6, ISO-NE charge = 5.1 c/kWh; the all-in wholesale cost. See table 5

30% mid-day solar from grid, at 19.84 + 1.6 = 21.44 c/kWh; the all-in solar cost. See table 5

- Electric rate during peak demand is 7.5 + 1.6 = 9.1 c/kWh

- System efficiency 80%, A-to-Z basis. See Appendix 

- No battery system aging. See Note

- RNS/FCM gain is allocated to arbitrage mode and mid-day solar surge mode

Allocating Battery System Costs

 

(Battery amortizing cost + Other costs) is allocated to:

 

1) Arbitrage mode ($72,624, amortize + $67,002, other costs) x 0.7 = $97,738

 

With RNS/FCM gain, the arbitrage mode benefit would be {100 x ($13,925, gain - $97,739, cost + 0.7 x $164,464, RNS/FCM gain)}/(0.7 x 2,000 kWh/d x 365 d/y) = 6.13 c/kWh; the “benefit” would become -16.40 c/kWh, without the RNS/FCM gain.

 

2) Mid-day solar surge mode ($72,624, amortize + $67,002, other costs) x 0.3 = $41,888

 

With RNS/FCM gain, the mid-day solar surge mode drawback would be {100 x ($38,763, loss - $41,888 cost + 0.3 x $164,464, RNS/FCM gain)}/(0.3 x 2,000 kWh/d x 365 d/y) = 14.30 c/kWh; the drawback would become 36.83 c/kWh, without the RNS/FCM gain

NOTE:

The drawbacks are not charged to owners, but to ratepayers, taxpayers, and added to government debts.

At present, the NE fleet of gas-fired CCGTs perform the mid-day solar surge service at about 2.4 c/kWh. See Appendix

If “Other costs” were less than $67,002/y, there would be a gain, which could be applied to improve the c/kWh

NOTE: Excluded from this analysis were state and federal subsidies, such as 1) tax savings due to depreciation and loan interest deductions; 2) cash grants; 3) tax credits; 4) waving of various state and local taxes, fees and surcharges, etc., which politically shifts the cost of solar to other entities, to make solar electricity appear less costly, and to enable an owner to sell his solar production at a politically palatable cost of about 11.0 c/kWh, instead of an expensive-looking cost of about 17.74 c/kWh. See Note and table 5

 

NOTE: In the real world, the battery owning and operating cost/kWh would be reduced by at least 45%, due to various subsidies.

However, no cost ever disappears, per Economics 101

Costs are politically shifted from owners to ratepayers, taxpayers, and added to government debts

 

http://www.windtaskforce.org/profiles/blogs/cost-shifting-is-the-na...

https://www.windtaskforce.org/profiles/blogs/high-costs-of-wind-sol...

 

NOTE: Battery system aging at about 1.5%/y (all components, not just the battery) would decrease the capacity of the battery system, and increase the cost/kWh by at least 1.5%, each year

 

Table 4			Grid	ISO-NE	Total	Total	Battery	With	Without
							cost	RNS/FCM	RNS/FCM
							allocation	benefit	benefit
Arbitrage	Fraction	kWh/d	c/kWh	c/kWh	$/d	$/y		c/kWh	c/kWh
Charging cost	0.7	2500	3.5	1.6	89.25	32576
Discharging revenue	0.7	2000	7.5	1.6	127.4	46501
Gain					38.15	13925	97738	6.13	-16.40
Midday solar surge
Charging cost	0.3	2500	19.84	1.6	160.8	58692
Discharging revenue	0.3	2000	7.5	1.6	54.6	19929
Loss					106.2	38763	41888	-14.30	-36.83
RNS and FCM gain						164464
Net gain						139626
Amortizing						72624
Net gain						67002
Other costs						67002
Net gain						0

APPENDIX 4

 

“All-in” Electricity Cost of Wind and Solar in New England

 

https://www.windtaskforce.org/profiles/blogs/high-costs-of-wind-sol...

http://www.windtaskforce.org/profiles/blogs/cost-shifting-is-the-na...

 

Pro RE folks point to the “price paid to owner” as the cost of wind and solar, purposely ignoring the other cost categories. The all-in cost of wind and solar, c/kWh, includes:

 

1) Above-market-price paid to Owners 

2) Subsidies paid to Owners

3) Owner return on invested capital at about 9%/y

4) Grid extension/augmentation

5) Grid support services, including fees for:

 

- Capacity availability (i.e., plants are fueled, staffed, kept in good working order, ready to produce on short notice)

- More frequent plant start-up/shut-down

 

6) Future battery systems

 

Comments on table 1

   

- Vermont legacy Standard Offer solar systems had greater subsidies paid to owner, than newer systems

- Wind prices paid to owner did not have the drastic reductions as solar prices.

- Vermont utilities are paid about 3.5 c/kWh for various costs they incur regarding net-metered solar systems

- "Added to rate base" is the cost wind and solar are added to the utility rate base, used to set electric rates.

- “Total cost”, including subsidies to owner and grid support, is the cost at which wind/solar are added to the utility rate base

- “NE utility cost” is the annual average cost of purchased electricity, about 6 c/kWh, plus NE grid operator charges, about 1.6 c/kWh

for a total of 7.6 c/kWh.

- “Grid support costs” would increase with increased use of battery systems to counteract the variability and intermittency of increased build-outs of wind and solar systems.

 

NOTES:

1) NE wholesale grid price averaged about 5 c/kWh, starting in 2009, due to low-cost CCGT and nuclear plants providing at least 65% of all electricity loaded onto the NE grid, in 2019.

 

https://www.iso-ne.com/about/key-stats/resource-mix/

https://nepool.com/uploads/NPC_20200305_Composite4.pdf

2) There are Owning costs, and Operating and Maintenance costs, of the NE grid

ISO-NE charges these costs to utilities at about 1.6 c/kWh. The ISO-NE charges include: 

 
Regional network services, RNS, based on the utility peak demand occurring during a month

Forward capacity market, FCM, based on the utility peak demand occurring during a year.

 

Table 1/VT & NE sources	Paid to	Subsidy	Grid	GMP	Added	ISO-NE	Total	NE	Times
		paid to	support		to rate	RNS+		utility
	owner	towner	cost	adder	base	FCM	cost	cost
	c/kWh	c/kWh	c/kWh	c/kWh	c/kWh	c/kWh	c/kWh	c/kWh
Solar, rooftop, net-metered, new	17.4	5.2	2.1	3.5	20.9	1.6	29.8	7.6	3.92
Solar, rooftop, net-metered, legacy	18.2	5.4	2.1	3.5	21.7	1.6	30.8	7.6	4.05
Solar, standard offer, combo	11.0	6.74	2.1		11.0	1.6	21.44	7.6	2.82
Solar, standard offer, legacy	21.7	10.5	2.1		21.7	1.6	35.9	7.6	4.72
Wind, ridge line, new	8.5	3.9	2.4		8.5	1.6	16.4	7.6	2.15
Wind, offshore, new	9.0	4.1	2.4		9.0	1.6	17.1	7.6	2.25

 

Sample calculation; NE utility cost = 6, Purchased + 1.6, (RNS + FCM) = 7.6 c/kWh

Sample calculation; added to utility base = 17.4 + 3.5 = 20.9 c/kWh

Sample calculation; total cost = 17.4 + 5.2 + 2.1 + 3.5 + 1.6 = 29.8 c/kWh

 

Excludes costs for very expensive battery systems

Excludes costs for very expensive floating, offshore wind systems

Excludes cost for dealing with shortfalls during multi-day wind/solar lulls. See URL

https://www.windtaskforce.org/profiles/blogs/wind-and-solar-provide...

 

“Added to rate base” is for recent 20-y electricity supply contracts awarded by competitive bidding in NE.

“Added to rate base” would be much higher without subsidies and cost shifting.

 

US regions with good wind and solar conditions, and low construction costs/kW, produce at low c/kWh.

NE has poor wind conditions, except on pristine ridge lines, and the poorest solar conditions in the US, except the rainy, Seattle area.

NE has highest on-shore construction costs/kW ($2,400/kW in 2020), produces at high c/kWh

See page 39 of URL

https://www.energy.gov/sites/default/files/2021-08/Land-Based%20Win...