This group brings together the best thinkers on energy and climate. Join us for smart, insightful posts and conversations about where the energy industry is and where it is going.


Base-Power Alternatives to Replace Base-Loaded Coal Plants

Willem Post's picture
President Willem Post Energy Consuling

Willem Post, BSME'63 New Jersey Institute of Technology, MSME'66 Rensselaer Polytechnic Institute, MBA'75, University of Connecticut. P.E. Connecticut. Consulting Engineer and Project Manager....

  • Member since 2018
  • 613 items added with 210,508 views
  • Nov 22, 2010


The purpose of this study is create “ballpark” estimates of the capital costs of deploying three base-power alternatives to replace East Coast base-power coal plants and to compare these alternatives regarding capital cost and the quantity and cost of CO2 reduction. The three alternatives considered are Gas, Wind and Nuclear.


The below table shows GDP and emissions for several major industrialized economies; China’s lbs of CO2/$ of GDP is high because its currency undervalues its GDP in dollars. Its purchasing power parity GDP is about $6,122 billion dollars.


                        GDP, $billions    CO2 Emissions, billion metric tons/yr     lbs CO2/$ of GDP


China                  2,658                         6.54                                                 5.06

US                    13,178                         5.84                                                 0.96

Japan                  4,363                        1.25                                                  0.65

Germany             2,914                         0.79                                                 0.61

France                2,271                         0.37                                                 0.37


US 2009 power production: 3,957 TWh; coal 44.9%, gas 23.4%, nuclear 20.2%, hydro 7%, wind 1.8%, biomass 1.35%, oil 1%,, geo 0.37%, solar 0.07% 

France 2009 power production: 486 TWh; nuclear 75%, hydro 12%, fossil 11%, wind 1.5%, other renewables (mainly biomass) 0.8%.


At the end of 2009, the US had about: 


310,000 MW of coal plants which produced 1,774 TWh and emitted about 1.61 billion metric tons of CO2.

440,000 MW of gas plants which produced 926.4 TWh and emitted about  0.43 billion metric tons of CO2.

101,000 MW of nuclear plants which produced 799 TWh 

35,159 MW of wind farms which produced 70.8 TWh


Because of new drilling techniques, the US is able to extract vast quantities of gas from shale formations. As a result, the US is estimated to have about a 100-year supply of gas at current consumption rates. The plentiful gas supply has kept gas prices around $4/million Btu; future oil prices will be lower than they would be without the plentiful gas.


The percentage of power production from gas has been rising for more than 25 years. Utilities have moved away from adding new coal plants to adding new gas plants which have low capital costs per MW, are quick to build (less financing cost), have low owning and operating costs, require minimal air quality control systems and have emissions of less than 1.0 lb of CO2 per kWh vs about 2.25 lb of CO2 per kWh from older base-loaded coal plants. The low price of gas is a boon for these utilities. It confirms their decision.


The utility build-out of gas capacity largely is economics driven. The recent build-out of wind capacity is largely legislative mandate-driven and subsidy-driven.


The federal subsidies for renewables move power production into uneconomical directions which will increase electricity prices and divert scarce resources from more productive uses. This will adversely impact US competitiveness and standard of living at exactly the time it needs to become more competitive to reduce its trade and budget deficits and to create the savings to invest in restructuring its economy.


Reference: The Eastern Wind Integration and Transmission Study


EWITS considers four scenarios, three are for 20% wind penetration, Scenario 4 is for 30% penetration of the US portion of the Eastern Interconnect by 2024. Scenario 4 assumes all wind power will be from the Great Plains, East Coast land-based, and East Coast offshore wind farms, a total of 258,608 MW land-based (103,443 units @ 2.5 MW), plus 79,100 MW offshore (21,972 units @ 3.6 MW) equaling 337,708 MW (125,415 units). Scenario 4 wind power production is 337,708 MW x 8,760 hr/yr x average capacity factor 0.377 = 1,116 TWh in 2024. See EWITS pg. 79. 


The Great Plains, East Coast and offshore wind farms would all be connected to three new grid “overlays” to minimize power variation. The power from the Great Plains grid overlay would be transmitted to the East Coast grid overlay via several HVDC lines. The power from the offshore grid overlay would be transmitted to the East Coast grid overlay via several HV lines. 


By interconnecting all the wind farms the resulting geographical area would cover at least two moderate-size weather systems and the variability of the wind power would be reduced. The long string of offshore wind farms, about 1,000 miles from North Carolina to Massachusetts, would by itself cover at least two moderate-size weather systems. The thinking is the wind strength will vary on the Great Plains, on the East Coast and offshore, but the wind will blow somewhere. 


EWITS estimates minimum wind power, on rare occasions, may be as low as 20% of installed capacity. Average wind power is at 37.7% of installed capacity. Peak wind power, on rare occasions, may be as high as 50% of installed capacity, as sometimes happens in Spain. 


Weather extremes, such as snow, rain and ice storms, hurricanes and tornadoes may require the idling of many wind farms thereby increasing power variability on the overlay grids to unacceptable levels. This means an adequate percentage of wind power capacity must be available from other sources, likely CO2 producing, to avoid brownouts or blackouts.


Scenario 4 capital cost of the new overlay systems and the modifications to the existing East Coast grids is estimated at $92.5 billion from the present to 2024. See EWITS pg. 39.  


Scenario 4 reserve requirements would need to increase from 4,022 MW (Base Case) to 22,134 MW to integrate the wind power. 


For example: If Scenario 4 (30% wind) of the EWITS study were applied to the ISO-NE grid conditions during 2006, CO2 producing spinning reserves would have to increase from 202 MW to 1,789 MW. Other grids of the Eastern Interconnect would have similar increases. See EWITS pgs. 40 and 42.


Note: The New England Wind Integration Study, NEWIS, estimates ISO-NE total reserve requirements, TOR, of 2,250 MW at no wind; 2,270 MW at 2.5%; 2,600 MW at 14%; 2,780 MW at 20% and about 3,100 MW at 30% wind.


EWITS did not state that It would take 125,415 /(250 days/yr x 6/day) = 84 yrs to produce the wind turbines at current GE and Vestas production rates of 3 units each per day. The entire GE and Vestas production would need to be dedicated to the US Eastern Interconnect AND production rates would need to increase 6 times over a 14-year period to provide the 125,415 wind turbines by 2024.


EWITS did not provide a time schedule of major activities to implement the wind turbines and transmission systems by 2024.


EWITS did not provide a time schedule of capital expenditures to implement the project which impacts the methods and costs of long-term financing.


Study Methodology and Assumptions


For this study each of the three alternatives is assumed to generate 1,000 TWh/yr which will yield sufficient data for comparisons.


All alternatives are assumed to be implemented overnight to simplify the analysis and to avoid the complexities of financing.


The 1,000 TWh/yr is based on EWITS Scenario 4 that provides 30% of the US share of the Eastern Interconnect as wind power by 2024. This wind power would have been 944 TWh in 2006 and is estimated to be 1,116 TWh in 2024. See EWITS pgs. 46, 66 and 72


CCGT plant data:


Efficiency is assumed at 60% (Lower Heating Value), or about 54% (Higher Heating Value) 

Capacity factor, CF, is assumed at 0.85

Capital costs are assumed at $1,250/kW

Heat rate = (3,413 Btu/kWh)/efficiency 0.60 = 5,688 Btu/kWh

CO2 emissions/kWh = 117 lb of CO2/(million Btu x 1kWh/5,688 Btu) = 0.67 lb of CO2/kWh 


In western Maine, an area with good winds, are located nine wind farms on ridge lines. Their average capital cost is about $2,500. The average CF of the five operating wind farms and the four under-construction wind farms is about 0.25-30. It is likely other East Coast ridge line wind farms in good wind locations will have similar CFs.


In the Great Plains, wind farms with good winds, such as in Kansas, have CFs of about 0.36-0.42. Offshore wind farms with good winds, such as in Nantucket Sound, have CFs of about 0.39.


For this study the wind CF is assumed at 0.377 = 1,116 TWh/(8,760 hr/yr x 337,708 MW), as calculated from EWITS pg. 79. 


For this study wind capital costs is assumed at $2,500/kW for Great Plains and East Coast land-based wind farms, and $3,921/kW for East Coast offshore wind farms. See pg. 110 of NREL website.


Nuclear CF is assumed at 0.90

Nuclear capital costs are assumed at $7,000/kW




Replacing most of the older coal plants with a mix of base-loaded gas, wind and nuclear plants would significantly reduce CO2 emissions and other pollutants.


The below table indicates a combination of gas and nuclear plants would have the lowest capital cost, would remove up to 0.90 billion metric tons of CO2/yr and would reduce CO2 emissions at the lowest cost per metric ton of CO2/yr. 


Wind plants should be built at only the locations with the most favorable conditions, i.e., excellent winds and relatively close to population centers, to maximize their economics. If wind farms are built in marginal locations because of subsidies and legislative mandates, their owners will likely press legislatures for long-term or permanent subsidies; an undesirable policy outcome.                 


           New Capacity(1)   Capital  Cost (2)  CO2 Emissions Reduction (3)      (2)/(3)                 Plant Life                                           

                                              $trillion           billion metric tons/yr        $/metric ton of CO2/yr  Years                                    


Case -1  134,300 MW CCGT      0.22                        0.64                                 344                      30-35

Case -2  302,610 MW Wind       0.95+                     1.029                                923                      20-25 

Case -3  126,840 MW Nuclear   0.89                       1.036                                859                      50-60 


+ Annual cost of wind power regulation is $4.54 billion/yr. Annual cost of wind power O&M is $2.58 billion/yr. 


After about 30-35 years, Case-1 will require a major investment for new gas turbines to about equal the life of Case-3.    

After about 20-25 years, Case-2 will require a major investment for new wind turbines to about equal the life of Case-3.


A levelized cost of energy, LCOE, analysis is required to determine the most economical alternative. The LCOE, $/kWh, for an alternative is the total costs over the life of the project, such as capital investment and the costs of capital, O&M, power regulation, fuel, etc., divided by the total power production over the life of the project. Such analyses have shown offshore wind is about twice as expensive as land-based wind, which currently costs about 5-8 c/kWh in very good wind areas, such as Kansas where capacity factors are about 0.40, or greater. See pgs. 115 – 118 of NREL website.




Base-Loaded Natural Gas Replacing Base-Loaded Coal is Better


Natural gas from a well is a mixture of CH4 and CO2. The CO2 is removed and released to the atmosphere.

For comparison: Land fill gas may be 50% CH4 and 50% CO2. 


The production, processing, transmission and storage, and distribution of natural gas creates CH4 (leakage) and CO2 emissions (processing).


Natural gas industry emissions in 2006, million metric tons of CO2 equiv: CH4  261.00   CO2    28.50 

Petroleum industry emissions in 2006, million metric tons of CO2 equiv:   CH4    27.74   CO2      0.29


The US EPA calculates conversion factors at standard temperature (32F) and pressure (14.7 psia).

Per EPA, combustion of 1,000 standard cf of CH4 yields 122 lb of CO2.

The US petroleum industry calculates conversion factors at 60F and 14.7 psia. 

Per US petroleum industry, combustion of 1,000 UPI cf of CH4 yields 115 lb of CO2

Adjustment factor is 115/122 = 0.9426


Natural gas industry leakage rate of CH4 in 2006 was about {261 MMT CO2e/(Adjustment factor 0.9426 x 0.4045 MMT CO2e/bcf)}/19,410 bcf production in 2006 = 3.52% 

Value of leakage in 2006 was about 3.52% x 19,410 bcf x $4.00/million Btu = $2.74 billion.


CH4 + 2 O2 –> CO2 + 2 H2O; as a green house gas CH4 is about 21 times more potent than CO2. 

16 lb + 64 lb –> 44 lb + 36 lb; 1 lb of CH4 becomes 44/16 = 2.75 lb of CO2. 

It is 21/2.75 = 7.64 times worse for CH4 to be leaked than combusted. 


Additional CO2 equivalent emissions due to CH4 leakage and processing is {(261 + 28.5)/261)} x 3.52% x 7.64 = 29.8%


The emissions of mining, transporting, storing and pulverizing of coal is about (1,700 grams of CH4/MWh)/(454 gr/lb) = 3.75 lbs of CH4/MWh, almost all of it during mining, which is equivalent to 7.64 x 3.75 = 28.65 lbs of CO2e/MWh. 

For comparison: combustion of coal yields about 2,250 lbs of CO2/MWh. 


Additional CO2 equivalent emissions due to CH4 and CO2 leakage is (2,250 + 28.65)/2,250 = 1.27%


Base-loaded coal plants emit about 2.25 lb of CO2/kWh, higher than any other power source. Older coal plants, with lower efficiencies and higher emissions than newer coal plants, will likely be replaced with new CCGT plants. 


High efficiency, base-loaded CCGT plants have: 


– low capital costs, short construction times (less interest during construction, earlier revenue streams). 

– much less visible impact than 20-30% wind penetration scenarios that require highly visible and costly grid overlay systems.  

– reduce CO2 emissions quicker (a global warming plus), albeit by not as much as wind and nuclear which would take much longer to implement.


Coal plant boilers have solid waste emissions of bottom ash and gaseous emissions that contain SOx, NOX and flyash. The bottom ash and flyash emissions are toxic and contain heavy metals and radioactive compounds. The radioactive flyash emissions, about 2-3 times greater than from an equivalent nuclear plant, are spread over large areas and harm the fauna and flora. In just the US, these emissions cause various diseases in millions of people and 20,000 to 25,000 deaths each year.


For comparison: One aboveground, medium-size, nuclear bomb test released more radioactivity than the combined emissions of all nuclear plants, including Three Mile Island, during the past 50 years. There have been about 2,000 aboveground nuclear tests. The radioactive fallout was spread over large areas and harmed the fauna and flora. This fallout causes diseases in people and deaths each year.


The following three cases are analyzed regarding capital costs and the quantity and cost of CO2 reduction. 




The latest gas-fired CCGT generator sets have capacities up to about 570 MW (Siemens) and electrical efficiencies up to about 60%, produce steady, 24/7/365, low-cost power, and emit about 0.67 lb of CO2 per kWh, or 0.67 billion lb of CO2 per TWh. CCGT plants can have overall efficiencies up to about 85%, if combined with district heating and cooling, as is widely practiced in Europe and Japan.


Adding  gas-fired CCGT capacity will require upgrading and expansion of the existing gas distribution systems. For this study the capital cost of the upgrading and expansion is assumed at $50 billion, about half of the capital costs of the transmission systems of Case 2.


– The new CCGT plants would be mostly located at existing coal plant sites. 

– Relative to Case-2, minor transmission system changes would be required.

– Visuals of existing coal power plants would be improved, as unsightly coal plants are replaced by new CCGT plants.

– Regulatory issues will be minimal, as pollution and CO2 from gas plants is much less than from the retired coal plants.




Production: 134,300 MW x 1 TW/1,000,000 MW x 8,760 hr/yr x capacity factor 0.85 = 1,000 TWh/yr 


Capital cost: 134,300 MW x $1,250,000/MW = $0.17 trillion

Capital cost of gas distribution system: $50 billion

Total capital cost: 0.17 + 0.05 = $0.22 trillion


CO2 Emissions: 1.298 CH4 leakage factor x 0.67 billion lb of CO2/TWh x 1,000 TWh/yr = 870 billion lb of CO2/yr, or 0.395 billion metric tons of CO2/yr 


The US has about 310,000 MW of coal plants. They are about 30% efficient, emit pollutants and CO2. 

Production in 2009: 310,000 MW x 8,760 hr/yr x CF 0.653 = 1,774 TWh  

CO2 emissions in 2009: 1.0127 CH4 leakage factor x 2.25 billion lb of CO2/TWh x 1,774 TWh/yr = 4,042 billion lb of CO2 in 2009, or 1.837 billion metric tons of CO2/yr


The new CCGT plants would enable retiring 1,000/1,774 x 310,000 MW  = 174,700 MW of coal plants. 

CO2 emissions of 174,700 MW of coal plants: 1,000/1,774 x 4,042 billion lb of CO2/yr/(2,200 lb/metric ton) = 1.036 billion metric tons of CO2/yr. 


Net CO2 emissions reduction: (1.036 – 0.395) = 0.64 billion metric tons of CO2/yr, would require a capital cost of $0.22 trillion, or 220/.64 = $344/(metric ton of CO2/yr)




Land-based wind power is the lowest cost, CO2-free renewable, if one looks at only the wind farm. If one looks at the wind farm as part of a system, then the economics and CO2 emission reduction becomes less favorable. As most of the windy places are sparsely populated, transmission facilities are needed to bring power to the populations on the East Coast. This is a visual and economic negative for wind power.


The capital costs per MW of offshore wind farms are 1.5-2.0 times the costs of land-based wind farms. Offshore wind farms have about three times the variable O & M costs/MWh of land-based wind farms. See EWITS pg. 67. 


Many state legislatures passed laws requiring utilities to have a significant percentage, usually 20% or more, of their power from renewables by a certain date. Wind power is variable and intermittent; it is absent at times when wind speeds are too high or too low, and varies at all other times. As this power is fed into the grids, operators of the grids are expected to deal with it. Wind power penetrations of less than 5% usually are not a big problem. Higher wind power penetrations are a problem in Germany (6.4% wind in 2009) and in Texas (4.9% wind in 2009). 


Denmark, Portugal, Spain, the Bonneville Power Authority and Hydro-Quebec use pumped storage hydro plants to smooth incoming wind power. Currently, it is the most economical method of integrating wind power. The Bonneville Power Authority charges about $5.7/MWh to integrate wind power by using its hydro plants. The EWITS estimate for Scenario 4 is $4.54/MWh. See EWITS pg. 46


Cape Wind and Other Offshore Wind Farms 


Cape Wind Associates, LLC, plans to build and operate a wind farm on the Outer Continental Shelf offshore of Massachusetts. The wind farm would have a rated capacity of 468 MW consisting of 130 Siemens AG turbines each 3.6 MW, maximum blade height 440 feet, to be arranged in a grid pattern in 25 square miles of Nantucket Sound in federal waters off Cape Cod, Martha’s Vineyard, and Nantucket Island. 


The Massachusetts Department of Public Utilities approved a 15-yr power purchase agreement, PPA, between the utility National Grid and Cape Wind Associates, LLC. National Grid agreed to buy 50% of Cape Wind’s power starting at $0.187/kWh in 2013 (base year), escalating at 3.5%/yr which means the 2028 price to the utility will be $0.313/kWh. NSTAR has a PPA with Cape Wind, approved by the state, for 50% of Cape Wind’s power, at a similar rate. 


A household using 618 kWh/month will see an average wind power surcharge of about $1.50 on its monthly electric bill over the 15 year life of the contract; if the other 50% of power is sold on the same basis, it may add another $1.50 to that monthly bill.

Power production is estimated at 468 MW x 8,760 hr/yr x CF 0.39 = 1.6 GWh/yr. 

The capital cost is estimated at $2.0 billion, or $4,274/kW. Federal subsidies would be 30% as a grant.


The 28.4 MW Block Island Offshore Wind Project has a 20-yr PPA starting at $0.235/kWh in 2007 (base year), escalating at 3.5%/yr which means the 2027 price to the utility will be $0.468/kWh. A State of Rhode Island suit is pending to overturn the contract; the aim is to negotiate to obtain a lower price.

Power production is estimated at 28.4 MW x 8,760 hr/yr x CF 0.39 = 0.097 GWh/yr.

Capital cost is estimated at $121 million, or $4,274/kW. Federal subsidies would be 30% as a grant.  


The 200 MW Delaware Offshore Wind Project has a 25-year PPA starting at $0.0999/kWh in 2007 (base year), escalating at 2.5%/yr which means the 2032 price to the utility will be $0.185/kWh.

Power production is estimated at 200 MW x 8,760 hr/yr x CF 0.39 = 0.68 GWh/yr.

Capital cost is estimated at $855 million, or $4,274/kW. Federal subsidies would be 30% as a grant. 


For comparison: TransCanada Power which owns the 132 MW Kibby Mountain Wind Facility in Maine has a 10-yr PPA with NStar, an electric utility, at a flat $0.105/kWh, plus the associated renewable energy certificates.

Power production is estimated at 132 MW x 8,760 hr/yr x CF 0.31 = 0.357 GWh/yr.

Capital cost is estimated at $320 million, or $2,424/kW. 


The above PPA prices cannot be directly compared because they are influenced by factors other than generating costs. See pg 119 of the NREL website. 


The 1,000 MW Deep Water Wind Project with 500 ft tall wind turbines @ 5-6 MW each is proposed to be located in Long Island Sound. Power is expected to be sold “in the mid teens”, i.e., at about $0.15/kWh.

Production is estimated at 1,000 MW x 1,000 kW/MW x 8,760 hr/yr x CF 0.40 = 3.5 GWh/yr. 

Capital cost, with interconnects to existing grids, is estimated at 4.5-5.5 billion dollars.


For comparison: Production by 471 MW of 60% efficient CCGTs: 471 MW x 1,000 kW/MW x 8,760 hr/yr x CF 0.85 = 3.5 billion kWh/yr, the same as the 1,000 MW Deep Water facility.


Capital cost: 471 MW x $1,250/kW = $589 million, about 9 times less costly, AND no grid re-enforcement is required, AND no balancing gas turbines are required.




Production : 302,610 MW x 1 TW/1,000,000 MW x 8,760 hr/yr x CF 0.377 = 1,000 TWh/yr,


Capital cost of land-based wind farms: 231,730 MW x $2,500,000/MW = $0.58 trillion.

Capital cost of offshore wind farms: 70,880 MW x $3,921,000/MW = $0.28 trillion.

Capital cost of transmission systems: $92.5 billion. See EWITS pg. 39

Total capital cost: 0.58 + 0.28 + 0.093 = $0.95 trillion.


The CO2 emission reduction would be less because about (22,134 – 4,022) MW = 18,112 MW of additional CO2-producing spinning power plants are required to regulate the variability and intermittency of wind power. Such plants usually are gas-fired, simple-cycle, gas-turbine generators. Their efficiency at rated output is about 35%, or about 9,750 Btu/kWh, and at 50% rated output about 30%, or about 11,375 Btu/kWh. The spinning power plants usually operate at about 50% of rated output otherwise they cannot modulate as needed by demand. 


Annual CO2 emissions of power regulation: (22,134 – 4,022) MW x 1,000 kW/MW x 8,760 hr/yr x (11,375 – 9,750) Btu/kWh x 50% rated output x 1.2 lb CO2/9,750 Btu = 15.5 billion lbs of CO2/yr, or 0.0072 billion metric ton/yr


Annual cost of power regulation: 1000 TWh/yr x 1,000,000 MWh/TWh x $4.54/MWh = $4.54 billion/yr. See EWITS pg 46.  

Annual cost of offshore O&M: 70,880/302,610 x 1,000 TWh/yr x 1,000,000 MWh/TWh x $2.56/MWh = $0.60 billion/yr. 

Annual cost of land-based O&M: 231,730/302,610 x 1,000 TWh/yr x 1,000,000 MWh/TWh x $1.28/MWh = $0.98 billion/yr. 

See pg 118 of NREL website. 


Net CO2 emissions reduction: (1.036 – 0.0072) billion metric tons of CO2/yr = 1.029 billion metric tons of CO2/yr, requires a capital cost of $0.95 trillion, or 950/1.029 = $923/(metric ton of CO2/yr)




– The new nuclear plants would be mostly located at existing nuclear and coal plant sites. 

– Relative to Case-2, minor transmission system changes would be required.

– Visuals of existing coal power plant sites would be improved, as unsightly coal plants are replaced by new nuclear plants.


Modular Nuclear Reactor Alternative to Large-Capacity Nuclear Reactors


B&W has about 50 years of experience building small nuclear reactors for the US Navy and big reactors for power companies. Utility nuclear power plants take about 8 years to build; their reactors usually are 1,000 MW, or greater. 


B&W has developed a 125 MW nuclear power module that will be built in US factories under controlled conditions to reduce costs and ensure quality. Several modules can be combined to create power plants of 1,000 MW, or greater. The plant can be arranged for water or air cooling of the condenser. The modules use standard 5% enriched U-235 uranium and have a 4.5-year operating cycle between refueling. The modules are fully-assembled and rail/barge-transportable to a plant site. Refueling of the modules would be at the factory. One module of a plant would be refueled, while others would continue to produce energy.


B&W, seeing the benefits of modularity, is planning to supplement its nuclear module with a fully-assembled, steam turbine-generator module that is rail/barge-transportable to a plant site. It will likely partner with GE for the T-G module


B&W calculates over the 60-yr life of the reactor, each module would avoid about 125 MW x 1,000 kW/MW x 8,760 hr/yr x CF 0.90 x 60 yr x 2.12 lb of CO2/kWh x 1 metric ton/2,204.6 lb = 57 million metric tons of CO2 that would have been emitted by a coal plant. 


B&W and Bechtel have formed a joint venture Generation mPower to build the modular power plants. Such standardized plants will be much quicker to license and build and less costly to own and operate. 


In June 2011, B&W announced TVA has signed a letter of intent with Generation mPower to build up to six of B&W’s modular nuclear reactors at TVA’s Clinch River power plant site in Tennessee. TVA is seeking approvals from the NRC.


Going modular is a unique opportunity for the US to be in the front of other nuclear industry powers. The sooner the Clinch River plants gets going, the better.


If Boeing can build about thirty $150 million planes per month, then B&W/GE/Bechtel could build about ten $375 million modules per month.




Production: 126,840 MW x 8,760 hr/yr x CF 0.90 = 1,000 TWh/yr 


Capital cost: 126,840 MW x $7,000,000/MW = $0.89 trillion


CO2 emissions reduction: 1.036 billion metric tons of CO2/yr, requires a capital cost of $0.89 trillion, or 890/1.036 = $859/(metric ton of CO2/yr).




France made a wise decision to go nuclear about 50 years ago. While France will be enjoying low electric rates, its competitors, such as Germany, the US, etc., will be increasing their electric rates, because they need to invest trillions of dollars over several decades to get to France’s low CO2 intensity; a major competitive advantage for France.


– France produces about 570 TWh/yr, exports about 70 TWh/yr, consumes about 447 TWh/yr, T&D losses are about 53 TW/yr. 

– France has about 79% of its power from 19 nuclear plants with 58 reactors, and about 12% hydro. Some of its PWR nuclear plants are designed to be partially load-following, its hydro plants and other plants do the rest.  

– France has leading global nuclear companies, such as Areva, GDF-Suez and EDF.

– France reprocesses its “spent” fuel, and that of a few other nations, to make new fuel for nuclear reactors, thereby much better utilizing the uranium and greatly reducing waste. The nuclear fuel burnup is about 5% at the end of a 300-500 day refueling cycle. The other 95% is available for reprocessing. 

– France has among the lowest electric rates in Europe. 

– France has the lowest CO2 intensity, 0.37 lb of CO2/$ of GDP, of all industrialized nations.

– France built a national, 180-mph rail system that runs on nuclear power.  

– France is developing EVs to boost nighttime electric demand to better utilize its nuclear plants.

– Denmark, paragon of renewables, 0.43 lb of CO2/$ of GDP; highest electric rates in Europe; Germany is second.


Willem Post's picture
Thank Willem for the Post!
Energy Central contributors share their experience and insights for the benefit of other Members (like you). Please show them your appreciation by leaving a comment, 'liking' this post, or following this Member.
More posts from this member
Spell checking: Press the CTRL or COMMAND key then click on the underlined misspelled word.
Stephen Gloor's picture
Stephen Gloor on Nov 23, 2010

Willem Post – you may need to correct this:

Scenario 4 reserve requirements would need to increase from 4,022 MW  (Base Case) to 22,134 MW to integrate the wind power.  For example: If Scenario 4 of the EWITS study were applied to the ISO-NE grid conditions during 2006, CO2 producing spinning reserves would have to increase from 202 MW to 1,789 MW. Other grids of the Eastern Interconnect would have similar increases. See EWITS pgs. 40 and 42.”

On page 42 of the reference, Figure 9 refers to the Regulating Reserve not the Spinning Reserve which are two quite different things.  As I understand it Regulating Reserves can be fast start up gas turbines and do not have to be fossil fuel generators spinning and synced to the grid.  In this case the larger reserves are offline when not needed and therefore not producing CO2.  This actually is almost exactly what the research of Mark Diesendorf et al showed in the 1980s.  It is good to see it confirmed in 2010 by better research.

You really should amend your CO2 figures for wind as the regulating reserve could have a CF of lower than 20% in well dispersed wind.

Stephen Gloor's picture
Stephen Gloor on Nov 23, 2010

willem Post – “EWITS, pg. 42, Fig. 9: The Y axis is AVERAGE variable spinning reserves in MW.”

You are correct however the actual diagram is confusing as the Y axis is labelled spinning reserve however the caption says regulating reserve.

In the sidebar explanation of the types of reserves the report makes it clear that they are two seperate things.  One is to cope with the sudden loss of any one or even two generators within milliseconds and the other is primarily a frequency control.  Wind generally ramps in and out relatively slowly and with advanced weather forecasting is quite predictable so it does not need spinning reserve so much, however it does need AGC controlled regulating reserve. An example of this is the wind/gas system at Esperance where the gas turbine is controlled by an advanced controller connecting the wind farm to the turbine.

Anyway it may be a typo in EWITS however as you had the reserves working at 50% anyway it will not make much difference.  I thought wrongly that you had the spinning reserve going all the time to back up the wind.

Charles Barton's picture
Charles Barton on Nov 23, 2010

William Post, I intend to work over your estimates, but it will take a while since I am getting married on Friday.  However, some observation is in order.  Since future energy costs are speculative, it is more appropriate to consider a range of possible costs, than to peg a single figure.  The future cost of natural gas is unknown.  The cost picture is complicated by added cost of fracking due to increased environmental regulation of the method, and uncertainty about how long wells will produce.  In addition the actual carbon mitigation from natural gas needs a lot more research before we can be certain about its benefits.  Your cost estimates for nuclear power appear high.  For example, SCANA is building 2 AP-1000 reactors.  Their estimated cost is $9.1 billion for the project, or $4136 per kW. Further these are the first two of a significant number of AP-1000s.  Even assuming a very modest learning curve cost reduction of 20%, it is reasonable to believe that the unit cost of serial produced AP-1000 could run as low as $3309 per kW.  Your estimate of the cost of offshore wind is questionable.  Recent offshore wind projects are probably considerably more expensive than your cost estimates.  I will not assert this definitively until I review recent cost data.  

In short, future energy costs involve significant uncertainties.  Cost projections are at best problematic.

John Englert's picture
John Englert on Nov 23, 2010

By interconnecting the wind farms the variability and indeterminacy of their power will be reduced. It is estimated that wind power of at least 20% of installed capacity will be available at all times.

The problem I have with various wind studies, especially those that look at linking multiple wind farms together is they treat each wind “site” independently, estimating capacity factors by sampling from a wind speed distribution.  The truth is, even though the sites are spread over a large geographic area, they all share the same atmosphere and can be impacted by large weather systems.  I also think that saying, “…at least 20% of installed capacity will be available at all times,” is probably not correct.  Typically there’s some statement of probability like, “20% of capacity will be available with a reliability of 85% [typical coal plant reliability].”  Also, there needs to be a confidence interval included. 

Robin Carey's picture
Robin Carey on Nov 23, 2010

Congratulations, Charles and best wishes!

Charles Barton's picture
Charles Barton on Nov 23, 2010

John the capacity factor problem is further complicated by the problems of wind day-night, and seasonal variability.  Wind almost always gives higher capacity when you don’t want capacity, while the wind is likely to stop blowing exactly when you need it the most.  Thus the missing 20% comes at periods of peak wind demand.  Baseload capacity should be highly reliable, nd wind simply is not.  

Charles Barton's picture
Charles Barton on Nov 23, 2010

Thank you Robin.

Bill Woods's picture
Bill Woods on Nov 23, 2010

By interconnecting the wind farms the variability and indeterminacy of their power will be reduced.

Sometimes this trick works well, e.g. ,

Sometimes not so much: ,

Geoffrey Styles's picture
Geoffrey Styles on Dec 13, 2010


I looked at this again today, after your comment on my posting on methane emissions from natural gas production and distribution.  

I see you’ve adjusted for the gas temp. and that looks fine.  The surprising point in your calculations is that while CCGT reduces emissions at a lower cost than the other options you looked at, $300/ton is hardly cheap.  When I tried to figure out why, I saw two concerns: 1.  This assumes that the CCGTs are being built entirely to reduce emissions, without accounting for their lower-cost output relative to other options–at least in the absence of a price on CO2–if not necessarily versus the coal plants they’d replace.  How does the cost of power factor into the analysis?  2.  This also assumes that every MW of CCGT for displacing coal must be newbuild, rather than under-utilized existing capacity.  I know a lot of that 440 GW of existing gas-fired capacity consists of simple-cycle and peakers, but wouldn’t some degree of substitution be feasible with existing capacity at much lower cost/ton?

Get Published - Build a Following

The Energy Central Power Industry Network is based on one core idea - power industry professionals helping each other and advancing the industry by sharing and learning from each other.

If you have an experience or insight to share or have learned something from a conference or seminar, your peers and colleagues on Energy Central want to hear about it. It's also easy to share a link to an article you've liked or an industry resource that you think would be helpful.

                 Learn more about posting on Energy Central »