It appears the world has ample fossil fuels for at least the next 100 years, even with a growing gross world product and population. A worldwide, full-scale transition away from fossil fuels likely would take at least 100 years. It would not be wise to subsidize the build-out of technologies that have very little potential to provide the world with abundant, low-cost energy. Any rational planning and design of energy systems, and the systems of the users, should be based on the world's fossil fuels being depleted in the distant future.


Economically viable technologies are evolving to enable more generation closer to the user. Generating capacity on a distribution grid could provide most of the energy consumed within a distribution grid. Thus, the distribution grid would be less dependent on the high voltage grid, which, as a side benefit, would reduce energy losses on the high voltage grid. The role of the high voltage grid would decrease, but not eliminated. There still would be significant energy generated and fed into the high voltage grid, such as from nuclear, hydro, wind, concentrated solar power, CSP, plants, and PV solar plants; fossil plants would gradually disappear.


This article has three parts. Part I mostly deals with the economics of battery systems. Part II mostly deals with a viable US energy source mix without fossil fuels. Part III deals with zeroing population, energy and gross world product growth rates, and then having negative growth rates, because those measures are even more important for a sustainable world than moving away from fossil fuels. 




Energy storage, “before and after the meter” would need to be built out, because it is likely:


- The expansion of transmission systems will not proceed as quickly as required to keep up with the growth of variable, intermittent wind and solar energy, often because of cost and NIMBY concerns.


- Demand-side management options are at best uncertain means to manage the grid and cannot be relied upon as a substitute for increased investment in energy storage.


- Whereas fossil fuel-fired power plants can have up to several months of reserves (gas storage) or direct access to fuel (coal), there is no such strategic reserve in case of often-occurring, protracted events with insufficient wind and solar energy.


- The US power market will not operate as one grid, leading to bottlenecks whenever inter-grid energy balancing is required. For example, the Texas grid has minor connections with the Eastern Interconnect and Western Interconnect.




In the future, there will be many PV solar systems tied to a distribution grid. Increasing the capacity, MW, of those PV solar systems would decrease the stability of the distribution grid, especially during variable-cloudy weather.


Battery systems, tied to distribution grids with many PV solar systems, are used in California and Germany to smooth excessive energy variations. They act as dampers, which work as follows:


- The varying DC energy of the PV systems is fed as AC into the distribution grid.

- The battery systems maintain distribution grid stability by absorbing energy from or providing energy to the grid, as needed.

- DC to AC inverters of the battery systems are about 85%, 50%, and 10% efficient at 20%, 10% and 2% outputs, respectively, i.e., 50% of the converted energy is lost as heat, if charged and discharged energy quantities occur at less than 10% of inverter capacity!

- The round-trip efficiency: AC to DC into battery, DC to AC out of battery, is about 20% on an annual average basis. 


NOTE: Such charging and discharging has nothing to do with storing PV solar energy during the day for use at night, as is sometimes claimed.


Typically, in damping mode, the battery system would be charged to 60 to 70% of rated capacity, MWh, so it can be charged up to 90 to 95% and discharged down to 50 to 20%, depending on the battery type. The charge controller prevents charging above 90% and discharging below 20% to preserve battery life.


Typically, in damping mode, the charging-discharging range is well within 60% to 70%, i.e., this charging and discharging generates significant heat (energy is wasted), as it may occur at less than 10% of inverter capacity, unless multiple inverters are used. As more PV systems are added to the distribution grid, additional battery capacity would be required.




Hawaii has increased its PV solar systems in recent years. The energy is generated mostly between 10 am and 2 pm, whereas peak demand is later in the evening. Battery systems have been installed to shift a part of the solar energy to peak hours.


Here is a description of a PV solar/Battery system combo.


In Kauai, Hawaii, there is a 52 MWh of battery system, supplied by Tesla, combined with a 13 MW field-mounted PV solar system.


If daily solar production is 13 MW x 0.5 x 4 h = 26 MWh from 10 am to 2 pm, and 10 MWh could be used during that time, then 16 MWh would need to be shifted to peak hours. About 16 - 20% (loss) = 12.8 MWh would arrive at user meters, less transmission and distribution losses.


About half, or less, of the battery capacity, MWh, is available for daily energy shifting. Thus, if 25 MWh is available each day, shifting 16 MWh is a reasonable “day’s work”. Total shift would be 12.8 x 365 = 4672 MWh/y at user meters, less transmission and distribution losses.


Turnkey capital cost of the battery system 52000 kWh x $400/kWh = $20.8 million, based on Musk, CEO of Tesla, quoting battery packs at $250/kWh, and turnkey systems at about $400/kWh.


Just to recover capital costs, the cost of the energy shifting is $20.8 million/(4672 x 15) = $296.80, or 30 c/kWh, based on a life of 15 years. If other costs, such as interest, return on investment, taxes, insurance, O&M, repairs and replacements, etc., were included the cost likely would be about 45 c/kWh.


NOTE: Hawaii has the highest household electric rates in the US, about 33 c/kWh in 2017, whereas the US average was 11 - 12 c/kWh and the New England average was about 18 c/kWh, including taxes, fees and surcharges.


This cost may be all, or partially, offset, because a grid operator would charge the utility less for capacity charges, due to the utility shaving its demand on the grid during peak hours; these hours usually have high capacity charges.


Also, the wholesale price of electricity is usually higher during peak hours than during other hours. Utilities have power purchase agreements, PPAs, for almost all of their electricity supply. However, if a utility would have a need to buy some of its electricity on the wholesale market, then that utility would reduce its wholesale purchases during peak hours, due to the supply from the battery system. 




Most articles on batteries, as applied to electric grids, often written by non-technical people, are not based on real world data. As a result, unfounded optimism is spread regarding the economics of battery systems and their near-term implementation.


This article is based on the real-world, operating limitations of the Chevy-Volt and TESLA lithium-ion batteries, and the TESLA powerwall specification sheet data, to determine battery losses, operating limits and energy storage costs, c/kWh, of the battery systems attached to distribution grids. Without the real world data as a basis, erroneous conclusions would have been the result.


Chevy-Volt: The 2014 Chevy-Volt has a 16.5 kWh battery, but it uses a maximum of about 10.8 kWh (about 65% of its capacity, a slightly greater % on subsequent models), because the battery controls are set to charge to about 90% and discharge to about 25% of rated capacity. The 10.8 kWh gives the Chevy-Volt an electric range of about 38 miles on a normal day, say about 70 F, less on colder and warmer days, less as the battery ages.


TESLA Model S: The TESLA Model S uses 75.9 kWh of its 85 kWh battery for rare, extremely long trips, so called “range driving”, 75.9/85 = 89% of rated capacity, and uses 67.4 kWh for maximum “normal driving” discharges, or 67.4/85 = 79% of rated capacity. Almost all people use much less than maximum “normal driving” range, because they take short trips and charge their vehicles on a daily basis, thereby preserving battery life.




Batteries are not fully charged, nor fully discharged, i.e., there is a range of charge. Using large ranges shortens battery life.


For example, a 30-mile commute consumes about 10 kWh. The minor 10/85 = 12% discharge of a TESLA Model S battery allows TESLA to offer an 8-y/unlimited miles warrantee, whereas the major 10/16.5 = 61% discharge of a Chevy-Volt battery requires GM to offer an 8-y/100,000 miles warrantee to minimize warrantee costs.


That warrantee is for manufacturing defects, does NOT cover performance. According to GM, the battery is expected to have a performance loss of about 15% over its 8-y warrantee life, and more beyond that 8-y life.




TESLA: Below is a quick way and a more accurate way to determine the cost per mile of owning and operating a TESLA car for 8 years. Assumptions: 85 kWh battery; battery warrantee 8 years, unlimited miles; $80,000, new, $15,000 at 8 years; driven 100,000 miles in 8 years; 0.30 kWh/mile at customer meter; 10% free, on-road charging, 90% at home charging at 0.20 $/kWh.

Annual charging cost is (100,000/8) x 0.3 x (0.1 x 0 + 0.9 x 0.20) = $675, or 5.4 c/mile.

Car cost/mile is (80,000 – 15,000)/100,000 = 65 c/mile.

Quick way cost is 70.4 c/mile, with ignored costs about 90 c/mile.


Annual payment for amortizing $80,000 at 3%, 8y, is $11,396, or (8 x 11396 - 15000)/100000 = 76.2 c/mile.  

Annual charging cost is (100,000/8) x 0.3 x (0.1 x 0 + 0.9 x 0.2) = $675, or 5.4 c/mile.

More accurate way cost is 81.6 c/mile, with ignored costs about 90 c/mile. 


Nissan Leaf: Below is a quick way and a more accurate way to determine the cost per mile of owning and operating a Nissan Leaf car for 8 years. Assumptions: 24 kWh battery; battery warrantee 8 years, 100,000 miles; $30,000, new, $5,500 at 8 years; driven 100,000 miles in 8 years; 0.30 kWh/mile at customer meter; no on-road charging, 100% at home charging at 0.20 $/kWh.

Annual charging cost is (100000/8) x 0.3 x 0.20 = $750, or 6 c/mile.

Car cost/mile is (30000 – 5500)/100000 = 24.5 c/mile.

Quick way cost is 30.5 c/mile, with ignored costs about 40 c/mile.


Annual payment for amortizing $30,000 at 3%, 8y, is $4,274, or (8 x 4274 - 5500)/100000 = 28.7 c/mile.  

Annual charging cost is (100,000/8) x 0.3 x 0.2 = $750, or 6 c/mile.

More accurate way cost is 34.7 c/mile, with ignored costs about 40 c/mile. 


Ignored costs: The cost of financing and amortizing (for the “quick way”), PLUS any costs for O&M of car and at-home charger, PLUS taxes, license, registration; PLUS any capacity degradation due to cycling, are ignored. Capacity degradation means it takes more energy to charge and discharge the battery, a shorter range for a given battery discharge, less livelier throttle response during acceleration and uphill driving.


NOTE: Assuming a new owner buys an 8-y-old TESLA for $15,000, he likely would install a new battery for about 85 kWh x $125/kWh = $10,625, plus labor and materials, and disposal of the old battery. The price of a new TESLA likely would be about $80,000 eight years from now, because increases in car costs likely would be offset by decreases in battery costs.





miles/y assumed



Energy from battery

kWh/mile DC



Energy charged

kWh/y DC



Vampire loss

kWh/y AC @ 8 mile/d



Charging loss

kWh/y AC @ 15%



Total through meter

kWh/y AC



Elect. rate

$/kWh assumed



Elect. cost




Elect. cost





$/gal assumed




miles/gal assumed







Gasoline cost




Gasoline cost





If electric rates are high, and gasoline prices are low, EVs are not a good deal.




Batteries have a lesser RATE OF DISCHARGE to the DC motor of an EV on colder days, say 10F, than on normal days, say 70F. This causes the EV to act sluggish, especially with snow on the road, or going uphill, and causes it to have a lesser range. Also, in cold climates, cars need a cabin heater, heated seats and heated outside mirrors.


Thermal management of lithium-ion battery systems is critical for electric vehicle performance. For example: an active system may be required to heat or chill a liquid before pumping it through the battery system to regulate the temperature throughout the system. On hot days, the chilled liquid absorbs heat from the batteries, rejects it using a radiator, before going through the chiller again. On cold days, the heated liquid supplies heat to the batteries to ensure efficient charging, and to maintain a proper rate of discharge during driving.




Tesla markets a wall-hung, 14 kWh Powerwall 2.0 battery, with lithium-ion cells made by Panasonic. The unit is designed for daily charging and discharging.


The turnkey cost = $6,200, factory FOB + S & H + Contractor markup of about 10 percent + Misc. hardware + Installation by 2 electricians, say 16 hours @ $60/h = $8,200, or 586/kWh. This is a Tesla estimate, which likely would be higher, depending on customer site conditions.


Tesla offers a 10-y warrantee for manufacturing defects, does NOT cover performance. Tesla estimates 10% degradation in performance by year 10.


Example No. 1, Store Daytime PV Solar Energy for Use During Peak Hours at Night: 


The economics of this scheme is based on the unrealistic assumption PV solar energy would be available to completely charge the batteries to the maximum extent possible, each and every day, for 10 years, and that all of that energy would be used at night. Weather conditions allow for very little generation of solar energy on many days, as proven in Germany, with similar weather conditions as New England.


In reality, a 5 KW solar system would produce about 6250 kWh/y, or about 17 kWh/d, on average, in New England, more in summer, much less in winter. Adequate solar energy would be available to charge the batteries during summer on many days, but the energy would be inadequate on many days during winter. Any shortfalls required to top off the batteries, so they could be used for standby power in case of an outage, would need to be supplied by the grid.


Other Assumptions: 1) No performance loss over the 10-y warrantee life; 2) One cycle per day, i.e., 3,650 cycles in 10 years; 3) Utility has time-of-day charges; 4) Daytime solar energy generated by the homeowner could have been sold to the utility at 20 c/kWh; 5) Homeowner avoids buying nighttime energy from the utility at 30 c/kWh.


A quick way to estimate the minimum cost of storage: $8,200, turnkey cost/3650 cycles = $1.699/d. Dividing by the retrieved energy 1.699/11.962 = 0.142 $/kWh. Minimum loss over 10 years = 8200.00 - 2877.95 = $5322.05


Ignored costs: The cost of financing and amortizing; 2) Costs for O&M and disposal; 3) Capacity degradation due to cycling; 4) Other system losses; 5) Efficiency reductions of low-load operation of inverters.


Conclusion: Storing solar energy during the day to retrieve a less energy during peak hours at night is not smart, unless the rate differential and subsidies are extremely high.


NOTE: For people living "off-the-grid", it is essential to store solar energy during the day for use at night.


DC from PV system, kWh


Tesla FOB, $


Inverter eff., DC to AC


Installation, $


2.0 unit eff., AC to AC


Turnkey, $


AC out to house, kWh


Loss per cycle, kWh






Storage cost, $/d


Charging cost, $/kWh


Storage cost, $/kWh


Avoided cost, $/kWh


Gain, $/d


Gain, $/10y


$, Loss



Example No. 2, Store Nighttime Grid Energy for Use During Peak Hours at Night:


Assumptions: 1) No performance loss over the 10-y warrantee life; 2) One cycle per day, i.e., 3,650 cycles in 10 years; 3) Utility has time-of-day charges; 4) Daytime solar energy generated by the homeowner could have been sold to the utility at 20 c/kWh; 5) Homeowner avoids buying nighttime energy from the utility at 30 c/kWh.


A quick way to estimate the minimum cost of storage: $8,200, turnkey cost/3650 cycles = $1.699/d. Dividing by the retrieved energy 1.699/12.460 = 0.136 $/kWh. Minimum loss over 10 years = 8200.00 - 3423.70 = $4776.30


Ignored costs: The cost of financing and amortizing; 2) Costs for O&M and disposal; 3) Capacity degradation due to cycling; 4) Other system losses; 5) Efficiency reductions of low-load operation of inverters.


Conclusion: Storing grid energy at night to retrieve less energy during peak hours at night is not smart, unless the rate differential and subsidies are extremely high.


AC from grid, kWh


Tesla FOB, $


2.0 unit eff, AC to AC


Installation, $


AC out to house, kWh


Turnkey, $


Loss per cycle, kWh






Charging cost, $/kWh


Storage cost, $/d


Avoided cost, $/kWh


Storage cost, $/kWh


Gain, $/d


Gain, $/10y


Loss, $





GMP, a Vermont utility, is distributing two thousand Tesla Powerwall 2.0 units on its distribution grids to reduce peak demands, which would reduce its ISO-NE-imposed forward demand charges and forward transmission charges. The units deliver continuous power at 5 kW and peak power at 7 kW.


Two thousand such units would reduce GMP demand by at least 10 MW, which would significantly reduce GMP forward charges. See URL for explanation of forward charges.


GMP provides the units to customers, whether they own a PV system or not. Battery systems on customer premises are called “before-the-meter” systems.


GMP owns and controls the units, and receives any federal and state grants and subsidies, and any accelerated depreciation write offs to reduce its corporate taxers. - t6FhJf...


Customer Cost and Benefit: GMP offers to install a unit (or multiple units) at a customer for a monthly charge of $15/unit, or a one-time charge of $1500/unit. GMP would have the right to remotely discharge the unit one time per day for 10 years (usually during peak demand hours, about 5 to 8 pm). In case of a power outage, a homeowner customer would have about 24 hours of standby power, provided GMP had not earlier discharged the unit for its own purposes.


GMP direct investment would be 2000 units x $8200/unit = $16.4 million, plus GMP costs of administering the program.


It likely would be much less costly for GMP and ratepayers to turn on several quick-starting, diesel-generator sets during those peak demand hours, as GMP has been doing for decades. A standard, quick-starting, 1 MW, D-G set has a turnkey cost of about $0.7 million.


Even better would be a Siemens, quick-starting, about 40% efficient, open cycle gas turbine, such as model SGT-A45TR, 44 MW, turnkey capital cost about $30 million.


- The OCGT would reduce peak demand by 44 MW, which is much more than the 10 MW of the 2000 Powerwall 2.0 units.

- The OCGT would last at least 35 years, the battery systems about 10 years.


GMP fiddling with heavily subsidized "microgrids and islanding" , and battery systems is very expensive for ratepayers and taxpayers.


NOTE: On July 24 2017, we experienced a power outage at about 8:30 pm. If we had had a Powerwall 2.0 unit, it would have been empty. The power outage lasted about 2.5 hours.




If a Powerwall 2.0 were used for backup, it would need to have sufficient capacity to provide energy, kWh, during an outage, which may last from 1 to 36 hours. For a freestanding house using about 500 kWh per month, this may be up to 12 kWh, assuming some appliances remain turned off during the outage. That means one Powerwall 2.0 unit would be adequate. The turnkey cost to the homeowner would be about $8,200. The homeowner owns and has complete control over the unit.


However, it would be much more cost-effective to have a 3 - 5 kW, propane-fired generator with a standard 100-gallon tank, and a 1 kWh battery, to provide power during startup of the generator. The turnkey cost to the homeowner would be about $1000.




Utilities aim to reduce purchases of on-peak energy from the grid during peak demands. One way is by starting up diesel-generators and open cycle gas turbine-generators, OCGTs, for a few hours each day.


The levelized cost of energy, LCOE, of 50 MW OCGT peaking plants is about 19 - 22 c/kWh over their 30-year lives. The LCOE varies with the cost of capital, operating hours/y, fixed and variable O&M, efficiency and gas prices/million Btu. As the average on-peak wholesale energy price over the next 30 years likely would be less than 19 - 22 c/kWh, the peaking plant would be operated at a loss, which is common for peaking plants.


Assumptions: The capital cost of a 50 MW OCGT peaking plant is about $50 million; 50% is private capital requiring a return at 10%/y; 50% is borrowed at 5%/y. Estimates of the major annual costs are as follows:



50% private at 10% over 30 y



50% borrowed at 5% over 30 y


Fixed + variable O&M



0.35 efficiency and $5/million Btu



Taxes, insurance, etc.





20.49 c/kWh


At the current price of gas of less than $2/million Btu, the LCOE would be 17.57 c/kWh.




SoCal Edison is planning a 32-MWh (8 MW for 4 h), lithium-ion energy storage project in a region with a potential 4,500 MW of wind turbines. LG Chem, a South Korean company, is providing the batteries. ABB, a Swiss company, is providing the balance of plant. Project capital cost $53.5 million (includes $25 million as a cash subsidy from USDOE), or $1,672/kWh. For comparison, the below project capital cost of a TESLA-Powerpack-based system is about $400/kWh, about 4 times less.


This URL has extensive detail regarding 12 case studies of stabilizing the grid with battery systems.


Case Study No. 3 shows a 21 MW wind turbine system in Maui, Hawaii, needs an 11 MW lithium-ion battery system, capable of delivering 300 kWh for 4 hours, for balancing the wind energy. Capital cost is about $11 million. Estimated cycles is 8000, and life is 20 years.


Project funds are $91 million, government + $49 million, private = $140 million. The project’s infrastructure includes an energy storage system; a 9-mile, 34.5-kilovolt powerline; an interconnection substation; a microwave communication tower; and a construction access road. Each generator pad requires about 2.4 acres of cleared area. The entire project covers 1,466 acres.


From the above, it is clear, the turnkey installed cost, $/kWh, of a battery system based on TESLA's 100 kWh Powerpack energy storage units would be several times less than of any competitor.




Another way of reducing utility purchases of on-peak energy from the grid during peak demands is by means of battery systems. This approach is in its infancy, as battery prices per kWh have only recently decreased to make it more financially viable, compared with traditional peaking plants.


Batteries systems can meet peak demands with lower emissions than OCGTs, by charging during low-demand periods, and discharging during peak demand periods, which displaces the need to burn natural gas in a peaking plant.


Battery systems can perform regulating, and filling-in and balancing services, when not in peaking mode. These services are much less stressful, as they use a smaller range of the system capacity.


The LCOE of battery systems is dependent on difference of wholesale on- and off-peak rates, c/kWh, the useful service life, year, the degradation of the batteries, %/y, and the range of charge/discharge, %. As a minimum, the electric rate difference must be large enough to offset the “round-trip” losses of charging, discharging, and AC to DC and DC to AC conversion, which may be up to 18.6% of the off-peak energy fed into the battery system. The real-world loss likely would be at least 20%, due to other system losses.


Below is calculated the LCOE of a TESLA Powerpack-based, peak-shaving system using the following assumptions:


- The battery system is to provide 100 MWh in 2 hours.

- The real-world loss is 20%

- Range of charge is 79%

- Battery degradation in year 10 is 10%

- Replacement battery cost in year 11 and year 21 about 50% of $250/kWh = $125/kWh

- Removal, disposal, and install new in year 11 and year 21 about 15% of new battery cost, or $37.5/kWh


NOTE: About 100 MWh/0.80 = 125 MWh needs to be charged into the battery to recover 100 MWh, for a loss of 25 MWh/d. The annual cost of that loss is 365 x 25 x 75 = $684,375, at an assumed average wholesale price of $75/MWh over the next 30 years.


The battery capacity would need to be 100/(0.80 x 0.79 x 0.90)  = 176 MWh

The battery capital cost would be 176 x 1000 x 250 = $44.0 million

The capital cost of balance of plant, BOP, would be about $24.0 million

50% is private capital requiring a return at 10%/y; 50% is borrowed at 5%/y

The capital cost of the turnkey, battery SYSTEM would be about $68 million, or $387/kWh


Estimates of the major annual costs are as follows:



1 to 10

11 to 30

Private amortizing batteries at 10%



Borrowed amortizing batteries at 5%



Private amortizing removal disposal and install new at 10%



Borrowed amortizing removal disposal and install new at 5%



Private amortizing BOP at 10% over 30 y



Borrowed amortizing BOP at 5% over 30 y



Fixed + variable O&M



Battery system energy loss



Miscellaneous; taxes, insurance, etc.









LCOE batteries

18.1 c/kWh

9.1 c/kWh

LCOE removal disposal and install new


1.4 c/kWh

LCOE battery system loss

1.9 c/kWh

1.9 c/kWh

LCOE balance of plan

9.8 c/kWh

9.8 c/kWh

LCOE battery system

29.8 c/kWh

22.1 c/kWh


* This cost is only for batteries; not included are the cost of removing and disposing of the old batteries, installing the new ones, and any BOP upgrades.


Even though, battery systems can perform other services, when not in peak-shaving mode, the LCOE of the battery system, operating life of 10 to at most 15 years versus about 30 years for OCGT peaking plants, would need to become about 20 c/kWh or less to cause utilities to replace older OCGT peaking plants (which likely are already paid for) with new battery systems, unless it is mandated by law, and heavily subsidized.




Over the past 60 years electric arc furnaces, EAFs, have increased their US production to about 55.2 million metric ton, 62.6% of total steel production in 2013. EAFs have capacities up to about 400 metric ton of steel per hour. The below calculation is for a 300-metric ton unit.


At 400 kWh/metric ton, a 300-metric ton, industrial, EAF requires about 120 MWh of energy to melt the steel, and a "power-on” time (the time steel is being melted with an arc) of about 37 minutes, and “power-off” time of about 20 minutes, for a total tap-to-tap time of about 57 minutes, to produce 300 metric ton of steel.


At a capacity factor of 0.55, the EAF steel production would be 300 x 8760 x 0.55 = 1,445,400 metric ton/y, and energy consumption would be 120 x 8760 x 0.55 = 578,160 MWh/y, for 24/7/365 operation. The entire EAF mill has other energy inputs, which are ignored.


Electric arc steelmaking is economical where there is plentiful electricity, with a well-developed electrical grid. In many locations, EAF mills operate during off-peak hours, when utilities have surplus power generating capacity and the price of electricity is less.


If the EAF mill were located near the US southwest, and a CSP plant with at least 10 hours of storage were to provide energy for continuous operation (capacity factor 0.48, at grid feed-in point), the required minimum CSP plant capacity would be 120 MWh/(37/60) = 195 MW. Such a CSP plant would require about 10 acre/MW, and cost about $9 million/MW.


CSP energy production would be 185 x 8760 x 0.48 = 818,231 MWh/y, of which the EAF plant would use 578,160 MWh/y and 240,071 MWh/y would be fed to the grid.

CSP plant capital cost would be 195 x 9 million = $1.751 billion.

CSP plant area = 195 x 10/640 = 3.04 square miles.


NOTE: The above 55.2 million metric ton of steel would need the equivalent of 55.2 million/1.445 million = 38 such CSP plants.





Almost all modern electrical systems have three categories of generating plants: base-loaded, intermediate, and peaking. The base-loaded plants produce at least 65% of all energy, are run 24/7/365, and have the lowest unit energy cost, about $40 - $45/MWh, included are the “must-run” plants. The intermediate plants produce about 30% of all energy, are run as needed to satisfy the daily variations of demand, and have higher unit energy costs, about $55/MWh. The peaking plants produce the remaining 5% of all energy, are run a few hours per day, and have the highest unit energy costs, about $100/MWh. Annual wholesale market prices average about $50/MWh.


German Renewable Energy: In 2016, gross electricity generation was 648.4 TWh, of which 460.1 TWh was from conventional generators and 188.3 TWh was from renewables, i.e., about 188.3/648.4 = 29% of gross electricity generation was from renewable sources, such as wind, solar, hydro, bio, etc.


Of the 188.3 TWh, about 77.4 TWh was from wind, about 38.2 TWh from solar, for a total of 115.6 TWh. About 21 TWh was from hydro and 51.7 from bio, etc. On an annual basis, wind and solar (stochastic sources) was 115.6/648.4 = 17.8% of electricity generation.


In 2016, domestic electricity consumption was gross generation (648.4), less self-use (30), less net exports (53.7), less transmission and distribution (30), less pumped storage and misc. (19.4), or about 515.3 TWh at user meters. 


Germany generated 648.4 - 77.4, wind, - 38.2, solar - 21, hydro = 511.8 TWh of electricity from CO2-emitting sources (fossil, bio, etc.) at about 560 g of CO2/kWh in 2016. France generated 530 TWh of electricity at about 58 g of CO2/kWh in 2016. Germany’s electricity generation has 511.8 x 560/530 x 58 = 9.32 times more CO2 emissions than France, which gets about 80% of its generation from nuclear.


Germany has been replacing nuclear (near-zero CO2) with mostly coal and natural gas, and some solar and wind; regarding CO2, bio energy does not count, as it emits CO2.


German CO2 Emissions: Germany’s CO2 emissions are about the same as in 2009. The increase in RE over this period did not have the desired effect. The electricity sector contributes only about 45% of Germany’s total emissions. The 100% decarbonizing of the electricity sector, which is already about 45% decarbonized, if we add nuclear, would reduce total emissions by about another 25%. Yet Germany’s efforts to cut emissions continue to concentrate on the electricity sector. Germany likely will not meet its 2020 and 2030 emissions reduction targets.


German Economic Growth: Germany’s economy is in near-zero growth mode, because so much of its resources are diverted to expensive wind and solar energy systems that produce expensive energy. About 50% of German household bills appear as taxes, fees and surcharges, most of them due to the ENERGIEWENDE, which started around 2000. Germany’s subsidized RE production has led to high household energy bills and millions of “energy-poor” households.


German Household Electric Rates: German household electric rates are the SECOND highest in Europe, about 28.69 eurocent/kWh in 2015; Denmark is the leader with about 30 eurocent/kWh. Both are RE mavens. France, about 80% nuclear generation, has one of the lowest. See line items on German household electric bills in this URL.


Wind and Solar Adversely Affect Electric Grids: In Europe, variable, intermittent wind and solar are adversely affecting electric grids; the higher the wind and solar energy on a nation’s grid, the higher are that nation’s household electric bills. See URL.


Intermittent Renewables Cannot Favorably Transform Grid Electricity: Is it really feasible for intermittent renewables to generate a large share of grid electricity? The answer is: “No, the costs are too great, and the return on investment would be too low.” Major grid problems occur, even with low penetrations of intermittent renewable electricity of 2015 electricity consumption, such as the US, 5.4%, China, 3.9%; Germany, 19.5%; Australia, 6.6%


The German Electrical System: The base-loaded category of the German system, mostly consisting of nuclear, coal, hydro and bio plants, operates at some constant percent of rated capacity. Most of that capacity has low ramp rates, MW/minute. The system’s intermediate category, primarily consisting of gas turbine plants, has higher ramp rates, i.e., is “flexible”. The system’s peaking category primarily consists of open cycle gas turbine plants with greater ramp rates.


Wind and Solar Energy Quantity and Cost: When German annual wind and solar energy quantities were minor, say less than 5%, the system’s inherent flexibility was able to accommodate that energy, which is variable and intermittent, due to the influences of variable solar, variable winds, variable weather/cloudiness and the seasons.


When those energy quantities became greater than 5% (the actual percentage depends on the system), more and more of various measures are required to accommodate that energy. Here is a partial list: grid build-outs; wind energy curtailments; connections to foreign grids to get rid of excess production; flexible reserve capacity (usually gas turbines); management of scheduling units; weather prediction; more elaborate grid connection requirements; energy storage systems; administrators; report writing; government, academia, and other folks involved in "energy", etc.


The extra unit cost of all these measures, $/MWh, which increase as more and more wind and solar energy is added, typically are not charged to owners of wind and solar systems, thereby making their unit energy costs, $/MWh, appear more “competitive” compared with traditional unit costs. That “competitiveness” is significantly at variance with reality, as has become increasingly apparent, to more and more people, in recent years. Here is a report, which explains in detail much of the number fudging.


“Socializing” Wind and Solar Costs: As the growing presence of wind and solar energy requires much enlarged and elaborate additions to the energy system, as above described, it imposes a variety of additional costs on the electrical system and the German economy, which adversely affect Germany’s future living standards and its competitive position on world markets; the same is true for the US and other nations.


Politicians/bureaucrats, “working” with RE pressure groups, and using the mantra of saving the world from evil fossil fuels, etc., typically find ways to “socialize” these additional costs, by means of taxes, fees and surcharges, or allocating them to various budgets, i.e., not charge them to wind turbine and solar system owners, to make the cost of wind and solar energy, $/MWh, appear to be “competitive”.


Inadequate Flexible Capacity: The sum of German variable wind and solar energy has become a large percentage of all energy on the grid during windy and sunny periods, and the base-loaded and flexible capacity has become inadequate for balancing that variable energy supply with demand. An example of the rural wind turbine impact is shown in this URL.


Curtailments and Exports: Curtailing wind turbine output, by feathering the rotor blades, would reduce some of the excess energy, however, it likely would attract unfavorable media attention; curtailments were 0.1% in 2009, 1.2% in 2014. The leftover excess energy is exported to nearby foreign grids, usually at near-zero or negative wholesale prices, i.e., Germany is PAYING countries to import its excess energy. Curtailed energy is shown in this URL.


“Must Run” Plants: The German system is constrained by a somewhat fixed capacity of “must-run” plants for essential services, such as hospitals, trains, street and traffic lights, various 3-shift industries, etc. Those plants cannot be reduced in output below about 55% of rated capacity, to prevent them from being unstable, i.e., they cannot sufficiently and fast enough “get out of the way” of the larger surges of wind and solar energy.


Base-Loaded and Intermediate Plants: As a result of “getting out of the way”, base-loaded and intermediate plants produce less energy, MWh/y, over which to spread their annual costs, i.e., their levelized costs, $/MWh, increase to adversely affect their economic prospects, and yet, they are needed for “must run” and other demand, and they are required to operate in a market with wholesale energy prices often below their break-even points; clearly an untenable situation that must be dealt with by.... politicians, who, unthinkingly, were largely responsible for creating these outcomes.


German Grid Stability Issues: As asynchronous-wind turbine and PV solar system-generator energy becomes a greater percentage, and synchronous-generator energy a lesser percentage on the German grid, grid stability issues arise, i.e., excessive frequency variations, which often are exported to foreign grids.


Irish Grid Stability Issues: The below URL shows excessive grid frequency variations, when asynchronous-wind turbine energy becomes a greater percentage, and synchronous-generator energy a lesser percentage on the Irish grid during high wind conditions. See figure 2. Wind energy generation had to be curtailed by 40% to “make room” for additional energy from traditional synchronous generators, likely gas-fired CCGTs, to stabilize grid frequency variations within the required range. See figure 3.


German Export Energy Disturbing Foreign Grids: Germany’s energy exports have run into some roadblocks. France, Belgium, the Netherlands, the Czech Republic and Poland have installed phase shifting transformers, PSTs, to protect their grids from unwanted, grid-disturbing surges of German energy exports, and it’s only 2016. This implies, Germany will need to increase curtailments of wind and solar energy, as a near-term fix.


Wind Turbine Energy Quality Standards: Regulatory agencies are increasingly requiring utility-scale wind turbine and PV solar systems to comply with stricter rules regarding connecting to the grid to enhance grid stability. See grid connection in URL.


Older wind turbines consume reactive power from the grid, etc., instead of providing it to the grid, as do all synchronous generators. Germany, etc., are developing grid connection standards for wind and solar systems. Here is a relevant URL.


In the US, the FERC finally issued an order regarding reactive power requirements for non-synchronous generators (wind, PV solar) on 16 June 2016. Prior to that date, wind turbines were legally exempt from that requirement. It was up to the local grid operator, such as ISO-NE in New England, to determine safe grid connection requirements. For example, Green Mountain Power in Vermont, per ISO-NE order, had to install a $10.5 million, 62-ton, synchronous-condenser system to prevent the Lowell Mountain wind energy from excessively disturbing the NEK grid.


German Money-Losing Energy Trading: Foreign countries, such as the Netherlands, France, Denmark, Norway, Poland, the Czech Republic, etc., usually welcome Germany’s low-cost energy. They export energy to Germany, usually at higher wholesale prices, when Germany’s wind and solar energy is insufficient. As Germany is closing its nuclear plants, and continuing its ENERGIEWENDE-2050 wind and solar build-outs, Germany’s money-loosing energy trading, during high wind and solar periods, likely will increase in future years. The much-heralded energy trading profit, based on wholesale prices, is meaningless, because there is a significant energy trading loss on a cost basis.


The Fraunhofer Institute, an RE-boosting government website, periodically issues reports showing an energy trade surplus. The reports show, the revenue of a large quantity of export energy (85.2 TWh in 2015), generally sold at low export wholesale prices/kWh, exceeding the expense of a small quantity of import energy (33.5 TWh in 2015) bought at generally higher import wholesale prices/kWh, i.e., an energy trading surplus, which attracts much media attention. However, that surplus is a deception, because, the SUBSIDIZED COST/kWh of energy exports is much higher than the export wholesale prices/kWh, which often are near zero or negative, i.e., an energy trading deficit, which usually is not mentioned at all. See below Cost of Energiewende Energy.


Examples of Negative Wholesale Prices: On May 8, 2016, based on EPEX spot data,


- The lowest export price was  -178.01 euro/MWh, with a weighted average of  -144.78 eur/MWh, between 12:30 and 12:45

- Later in the day, prices went down even further to  -374.00 eur/MWh, between 14:30 and 14:45


On May 15, 2016, Germany met all but 300 MW of its energy demand with renewable energy (mostly wind and solar) for a few hours. At that time, mostly fossil, nuclear, hydro and bio plants, with a total capacity of about 12,800 MW, operating at about 60% of capacity, had an output of about 7,700 MW. The resulting excess energy was sold at negative prices, per EPEX spot data.


Cost of Energiewende Energy: The Energiewende does not cover all German RE; some of it existed prior to the Energiewende. The 24 billion-euro EEG surcharge, shown on electric bills in 2015, is just one RE subsidy. There are other subsidies, taxes, fees and surcharges on electric bills, due to implementing the Energiewende, plus there are subsidies, such as for extra grid build-outs due to the Energiewende, that are not shown on electric bills.


If all such costs are added to base energy costs and then divided by the Energiewende energy quantity, the total cost is about 19 eurocent/kWh. In past years, that cost was much higher, but it has been declining, due to various reductions of feed-in tariffs, and other, recent measures, such as auctioning a fixed MW of wind, and a fixed MW of solar, etc., to be added for a year.


The legacy cost of Germany’s traditional energy is about 5 eurocent/kWh. For example, with, say 95% renewable energy on the grid, and total energy generation at about 105% of demand, the COST of that energy mix would be (5c x 10%, traditional + 19c x 95%, renewable)/1.05 = 17.67 eurocent/kWh, of which about 5% would be exported at significantly negative prices.


Future Energiewende CO2 Goals: German CO2 emission reduction has been near zero since 2009, due to various reasons, such as closing near-CO2-free nuclear plants and adding CO2-emitting coal plants. Based on official government data, Germany likely will NOT meet its CO2 reduction targets. See first and third graphs of this URL and END NOTES.


Going Forward to 2050: As part of adjustments to the Energiewende program, Germany has been reining in excessive wind and solar build-outs, due to increased curtailments, complaints from and blockages by nearby countries, and losing money on energy exports.


With energy exports partially blocked by the PSTs, Germany could respond by:


- Curtailing wind and solar energy production during windy and sunny periods, but that would attract adverse media attention.

- Adding quick-starting, flexible, gas-fired, plant capacity, MW, but that would “lock-in” CO2 emitting fossil fuels and gas imports.

- Building more north-south HVDC transmission grid, but that has been constrained due to NIMBY for more than 15 years.

- Adding battery-based energy storage, but that would be expensive and take many years, because economically viable, utility-scale storage, suitable for seasonal variations, has not yet been invented. See END NOTES.


Germany is very rich in money and technology, unlike many other countries, and likely will find a way to make it work. It will be interesting to see how it all will turn out.




NOTE: A recent report issued by Bloomberg New Energy Finance found, if currently unprofitable US nuclear plants were to shut down and were replaced with gas-fired plants, there would be about 200 million metric ton/y of additional CO2 in the US.


New York’s nuclear plants provide 61 percent of the state’s CO2-free electricity and avoid 26 Mt ton/y of CO2 emissions, equating to a societal value of almost $1.2 billion/y, based on federal methods of estimating.


Vermont Yankee, capacity 620 MW, CF 0.90, closed in December 2014. The plant’s output was replaced by mostly gas-fired plants, which produced an additional 3.1 Mt ton/y of CO2 in New England in 2015.


NOTE: Regarding future energy storage systems, recently, Musk, CEO of Tesla, stated: “We have almost reached the theoretical limit of li-ion batteries.” Hence, not much can be expected, other than some mass production price reductions. This article has various examples of installed battery systems, and the cost of battery systems and their operation.




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CMP Transmission Rate Skyrockets 19.6% Due to Wind Power


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Maine Center For Public Interest Reporting – Three Part Series: A CRITICAL LOOK AT MAINE’S WIND ACT


(excerpts) From Part 1 – On Maine’s Wind Law “Once the committee passed the wind energy bill on to the full House and Senate, lawmakers there didn’t even debate it. They passed it unanimously and with no discussion. House Majority Leader Hannah Pingree, a Democrat from North Haven, says legislators probably didn’t know how many turbines would be constructed in Maine if the law’s goals were met." . – Maine Center for Public Interest Reporting, August 2010 Part 2 – On Wind and Oil Yet using wind energy doesn’t lower dependence on imported foreign oil. That’s because the majority of imported oil in Maine is used for heating and transportation. And switching our dependence from foreign oil to Maine-produced electricity isn’t likely to happen very soon, says Bartlett. “Right now, people can’t switch to electric cars and heating – if they did, we’d be in trouble.” So was one of the fundamental premises of the task force false, or at least misleading?" Part 3 – On Wind-Required New Transmission Lines Finally, the building of enormous, high-voltage transmission lines that the regional electricity system operator says are required to move substantial amounts of wind power to markets south of Maine was never even discussed by the task force – an omission that Mills said will come to haunt the state.“If you try to put 2,500 or 3,000 megawatts in northern or eastern Maine – oh, my god, try to build the transmission!” said Mills. “It’s not just the towers, it’s the lines – that’s when I begin to think that the goal is a little farfetched.”

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Hannah Pingree on the Maine expedited wind law

Hannah Pingree - Director of Maine's Office of Innovation and the Future

"Once the committee passed the wind energy bill on to the full House and Senate, lawmakers there didn’t even debate it. They passed it unanimously and with no discussion. House Majority Leader Hannah Pingree, a Democrat from North Haven, says legislators probably didn’t know how many turbines would be constructed in Maine."

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