CapeCodToday Blog Chowder

Wind Power Always Replaces Fossil Fuels

 Some people challenge the fact that wind power will reduce the use of fossil fuels to generate electricity. Allow me to make the case that every megawatt-hour of wind generated power will indeed replace the equivalent electricity generated from oil, natural gas or coal, and in that order. Importantly, wind power will avoid the environmentally harmful and unhealthful emissions resulting from those fossil fuel replacements. And the use of wind power will decrease the import of oil and natural gas consequently easing a national security concern and national trade deficit.

Wind is a variable resource by nature. So wind power may not replace any particular fossil plant per se. However wind is considered a replacement source of fuel as it cuts back (offsets) the generation of electricity by conventional fossil fueled plants. And by design, wind power is dispatched at all times when it is available thereby avoiding the consumption of an equivalent amount of fossil fuel in a conventional power plant or combination of such plants. In the case of offshore wind, it will make significant contributions during peak load hours on hot summer days and especially in the winter.

This is a somewhat complex subject to present. It may require an investment of your time to understand the technical principles behind the conclusions.  But bear with me. I will try to keep it factual and concise. Footnotes are provided for the persistent.

 Let's cut to the chase, a base load unit

Take for example the base load generating Unit #1 at Mirant's Canal Plant. It is representative of the most efficient fossil fueled plants of the 1970 era. It's an oil fueled supercritical steam unit optimally designed to best operate between half load and full load. Boiler steam is produced at 3,600 psi at 1,000 degrees fahrenheit to drive the nominally rated 560 megawatt (MW) capacity Westinghouse turbine/generator [1].

Let's look at two different operating points.

 In one of its finest hours, on January 1, 2006 at hour 18 (i.e., between 6:00 PM and 7:00 PM) the electrical output peaked at 576 MWh. From EPA data records [2] the heat energy input for that hour was 5,322 mmBTU (that's a million British Thermal Units [3]).

Considering the fact that one barrel of residual fuel oil produces 6.287 mmBTU, this means 846 barrels of oil were consumed during this hour to produce that amount of heat energy (for steam to turn the generator's turbine). At 42 gallons per barrel, that's equivalent to 35,553 gallons of oil to produce the 576 MWh. Calculations show that the "heat rate" a performance measurement, was 9,240 BTU/kWh for an efficiency of 36.9%. [4]

A few hours later at hour 23, around midnight when the electrical dispatch was decreased (backed off) due to a smaller consumer load, the generator output was only 357 MWh, about half of the full load capacity. The heat input during that hour was reduced to 3,375 mmBTU. During this hour 22,554 gallons of oil were consumed [5]. The heat rate was 9,455 BTU/kWh for an efficiency of 36.1%.

That's a very small reduction in efficiency for operating at about half load. It is the foundation of the claim that every MWh of wind energy will reduce (displace) a MWh of fossil fueled electrical generation on a linear i.e., a proportional basis with little loss of efficiency while consuming only the minimum of fuel required to maintain the power output at that moment in time.

 This example reduction of 219 MWh (from 576 MWh to 357 MWh) for an hour, be it because lots of people turned off their lights or if wind power produced 219 MWh (had it been built at the time), the wind power would have saved 13,000 gallons of oil during hour 23 on that date [6]. Data at every other hour would show a proportional reduction in fuel consumption if wind power was providing electricity at the hour under consideration.

In terms of emissions, the Canal plant emits somewhat over 1,800 pounds of CO2 per MWh produced [7]. In this example for hour 23, the reduction of 219 MWh if generated from wind would have meant an avoidance of 394,200 pounds or 197 tons of carbon dioxide for that hour. In addition the unit's sulfur dioxide emissions at the rate of 3 pounds per MWh [8] would have been reduced by 657 pounds and nitrogen oxides at 1.5 pounds/MWh [9] would have been reduced by 438 pounds.

This is a significant linear reduction in fuel consumption and avoidance of emissions when wind is available as a replacement fuel. It illustrates exactly how much oil would have been saved and emissions avoided during this example hour. The point illustrated here is that a fossil fueled plant does not burn any more fuel than required to turn the generator at its instantaneous operating load.

Therefore to say when wind power comes on line it will not reduce fossil fuel consumption is simply erroneous.

A second example, an intermediate (cycling) unit

For a second example, consider generating Unit #2 at Mirant's Canal Plant. Again it's an oil fueled unit with a capacity of 560 MW. It is called an "intermediate" or "cycling" unit meaning that it is designed to operate over a wide range from 20% of full load to full load to better match the daily power cycling of users. Operating at a reduced steam pressure of 2,400 psi, it is less efficient than a base load unit because of design compromises to accommodate the wide operating range.

On Jan. 19, 2006 at hour 18 its output was 459 MWh. The heat input was 4,415 mmBTU resulting in a heat rate of 9,618 BTU/kWh for an efficiency of 35.5%. It consumed 29,494 gallons of oil during that hour.

Later that day at hour 21 the output was 240 MWh, about one third of full load capacity. The heat input was then 2,374 mmBTU and the heat rate was 9,891 BTU/kWh for an efficiency of slightly less at 34.5%. It consumed 15,859 gallons of oil during that hour or 13,635 gallons less than at hour 18.

The reduction in this example for Unit #2 was also 219 MWh (459 MWh minus 240 MWh) for hour 21. Again, be it because lots of people turned off their lights or wind power produced 219 MWh (had it been built then), the wind power would have saved 13,635 gallons of oil at hour 21 on that date [10].

Likewise, in terms of emissions, this reduction in Unit #2 if from wind would have meant a reduction of 197 tons of carbon dioxide for hour 21, and 657 pounds of SO2, and 438 pounds of NOx.

The point of this discussion is that no fossil fueled generating unit consumes more fuel than that which is absolutely necessary to produce the dispatched power allowed under the rules of the ISO. When the wind comes up or air conditions and lights are turned off, less fuel is consumed on a linear basis. 

 

A Brief Background on Price and Who Gets Backed Off. The UCP.

Electricity cannot be stored on the electrical distribution grid. So let's discuss who gets to dispatch their generated electricity. It will fit in with the wind story later.

The mission of the Independent System Operator of New England (ISO NE) is to exquisitely balance the power from about 300 generating plants with the variable consumer load on a minute-by-minute basis, and do it with reasonably priced electricity. ISO is responsible for establishing and overseeing the competitive wholesale electricity markets and making sure that sufficient electricity is reliably dispatched to meet public requirements.

To accomplish this task ISO administers the wholesale electricity market based on a Uniform Clearing Price (UCP) day-ahead auction, as do all wholesale electricity markets in the United States. The ISO dispatches generators in the region from an hourly bid stack that starts from the lowest-priced bids (this includes generators that bid $0, such as [wind], hydro, and nuclear units) and progress to higher-priced bids (i.e., from coal, natural gas, and oil fueled generating units) until there is sufficient generation to meet consumers' demand for each hour of the next day [11].

At the point where the bids meet the expected load for each hour of the next day, a line is drawn, called the uniform clearing price (UPC).    

The UCP auction is one in which each winning bidder below the UPC gets dispatched and receives that same price as the last unit needed to meet the demand for electricity by consumers, regardless of what their individual offer price was. For example, if a coal generator bids 4 cents/kWh and the clearing price is 7 cents/kWh, then the coal generator gets paid 7 cents/kWh.  

A UCP ensures that clean energy sources with no fuel costs, such as wind [and hydro] that are bid in at zero dollars, will always be dispatched and displace (i.e., backoff) plants with higher operating costs and air emissions [12].

Note: even though the price of fuel is zero for wind, solar and hydro, it does not mean that the cost of producing electricity from these renewable sources is zero. None-the-less, according to the rules and intent of ISO NE, wind, solar, and hydro bids are placed at the bottom of the stack and will always be dispatched when available.

 

Whose Electricity is Most Expensive

As a measure of whose electricity is more expensive, consequently reflecting where one is placed on the stack, look at the fuel costs as they are the main driver of electricity prices. The cost of fuel for running power plants makes up more than 80% of the wholesale price of electricity [13].

The pre-recession cost of residual fuel oil (1% sulfur content) in July of 2008 was $117/barrel. Knowing the heat rate of the oil fired steam plant like Canal Unit #2 one can calculate the fuel cost of generating electricity then was about 19 cents/kWh resulting in a wholesale price then of about 24 cents/kWh [14].

Now the cost of residual fuel oil in a world recession is about $80/barrel. This leads to a wholesale price now of oil generated electricity of about 16 cents/kWh. No wonder oil fueled steam generators are all but obsolete and cannot compete with natural gas units.

 

The pre-recession cost of natural gas in New England was about $12/mmBTU yielding a wholesale electricity price then of about 10 cents/kWh [15]. Now with the delivered cost of natural gas [16] at about $5/mmBTU the cost of fuel to generate a kWh is 3.4 cents. So now the wholesale price of natural gas generated electricity is about 4 cents/kWh.

 

The price of coal for generating electricity has stayed relatively low for many years. In 2008 it was $2.11 mmBTU and now $2.31 mmBTU [17] leading to a wholesale price of coal generated electricity of about 2.4 cents/kWh.  

 

The cost of fuel for nuclear plants is about 0.35 cents/kWh [18]. A little uranium goes a long way according to Einstein. This leads to a wholesale cost of nuclear generated electricity of some 2.0 cents/kWh [19]. This is lower than fossil fuels for the existing fleet of old nuclear plants that have been paid off years ago. However this low price is totally unrealistic for new nuclear plants. And that's another story. If you think wind power is expensive, wait till you have to pay for electricity from a new nuclear plant. 

 

It is clear that wind power bid into the stack will replace the most expensive fossil fuel bids starting with oil on top (if any), then natural gas (most likely), finally coal and nuclear (unlikely).

Price Takers

Participants in the UCP auction are known as "price takers." This means each winning unit, be it a hydro, wind, solar, nuclear, coal, natural gas or oil unit that is dispatched, is willing to "take" whatever the clearing price is at that moment in time. The UCP scheme ultimately benefits consumers by bumping higher bidders thus lowering the wholesale cost of power to all users.

About one-quarter of all wholesale electricity sales in New England are traded in this day-ahead spot market. The balance of wholesale electricity sales are administered in private power purchase agreements (PPAs) between a generating company and a retail distribution utility like NStar or National Gird.

The important fact is that the electricity under contract for physical delivery in these PPAs is also placed at the bottom of the bid stack since the price was previously and privately negotiated between the wholesale generator and the retail distributor. Therefore both price takers and PPAs directly affect the spot market by lowering the UCP [20].

For example, a large wind farm like the Cape Wind with a capacity of 468 MW would lead to a forecasted  reduction in New England's wholesale cost of electricity averaging $185 million annually over the 2013-2037 time period, resulting in an aggregate savings (price suppression) of $4.6 billion over 25 years [21].  This price suppression has been vigorously debated and there are differences of opinion as to its assumptions and conclusions.

It should be noted that the long term price of wind power in such a PPA may be somewhat higher than the current wholesale market which is largely dictated by the cost of natural gas. This will result in a slight increase in the retail market price for customers of a distribution utility like National Grid or NStar at this time. 

However the advantage of long term PPA contracts with wind developers is the fixed price (with an inflation factor) can be guaranteed over 15 to 25 years. The extreme volatility of fossil fuels all but prevents PPAs of more than two or three years for fossil fuels. For example, the wholesale price (the generation charge) increased from 3.9 cents/kWh in 2001 to 12.5 cents/kWh in 2008 mostly due to the price increase of oil and natural gas. Currently it is about 8 to 9 cents/kWh.

 

Three Types of Generation Plants

It is important to understand the characteristics of different kinds of generators to better appreciate how power plants interrelate in providing electricity for the grid. This backdrop will lead to an understanding of how wind energy, and intermittent source, will be integrated into the grid system.

There are three basic types of electrical generation units. Each is designed to optimize the production of electricity under different load situations.

But before discussing the details, it is helpful to understand the measure of production for electrical generators. It is called the "capacity factor" abbreviated "CP". (No, I don't know why the acronym is CP rather than CF). The capacity factor is defined as the ratio of the actual electricity generated (in MWh) divided by the theoretical maximum amount of electricity if the unit were running at full rated power for the period under consideration.

For example, if a unit is rated at 600 MW at full load (the nameplate capacity) [22] and produces 600 MWh for 12 hours a day and 300 MWh for the remaining 12 hours, it would have a capacity factor of 450 MWh (the average production over 24 hours) divided by 600 MWh or 75% for that day.

The CP is an average of actual production divided by the maximum production over the period of time of interest, be it a day, a month, or a year.

Base Load Units

First of the three types is the "base load" unit. They are designed to operate very efficiently from about half-full load to full load while serving a continual consumer base throughout the day and night.

Typically these are nuclear, coal, or natural gas fueled plants with lower fuel costs that generally provide the lowest cost electricity. Two decades ago oil fueled base load plants were competitive with coal but they are all but retired or off line now due to the high cost of oil.

Base load units comprise about a third or some 10,000 MW of New England's total generation capacity of 31,000 MW [23]. Nuclear plants run with capacity factors of 90% or more [24]. An outstanding example is the Plymouth Pilgrim nuclear plant that achieved a 98% CP in 2008 [25]. Coal plants like Brayton Point and Salem Harbor, each with three base load coal fired steam units run with yearly CPs of about 75% [26]. During the hay-day of Mirant's oil fueled base load Unit #1 it averaged a CP of 66% from 1997 to 1999. Base load natural gas fired combined cycle combustion turbines run with a CP of about 45% nationwide basis [27]. This is a considerably lower CP than coal or nuclear units due to the higher cost of natural gas on a BTU basis.

Contrary to common perceptions, base load units, other than nuclear plants, do not run anywhere near full load at all times.

Intermediate (Cycling) Units 

The second type of generating unit is called an "Intermediate" or more appropriately a "Cycling" unit. These generating units are used during the transition between base-load and peak-load requirements. They come on line during intermediate load levels and ramp up and down relatively quickly to follow the load that peaks during the day and is lowest in the middle of the night.

Intermediate units are designed to operate over a wide range of power, from about 20% of full power to full power. As such, the tradeoff in engineering design compromises results in a lower efficiency than base load units at all operating points. Because of cycling up and down, their capacity factors are lower than base load units. Typically CPs for intermediate units range from 20% to 50% [28].

In New England well over half of the installed generation capacity consists of intermediate units. They are mostly relatively new, efficient, combined-cycle natural gas combustion turbines. Built over the last 15 years the existing fleet has a heat rate of about 7,500 BTU/kWh, with an efficiency of about 45%. The latest General Electric H-class gas turbines have a heat rate of 6,000 BTU/kWh with an efficiency of 60% [29].

Since intermediate units comprise over half the installed capacity and run at relatively low capacity factors at most times, this means that there is plenty of capacity to back-fill wind turbines as discussed later.

Gas combustion turbines that run as intermediate units are augmented by a diminishing number of oil fueled steam turbines, like Mirant's Unit #2. In its prime of the late 1990s Mirant's Unit #2 had a capacity factor of 50%.

Peaking Units

The least used generators are called "Peaking" units because they are rarely used except for unusually cold winter days or extremely hot summer days when everyone is using their air conditioners. In addition, "peakers" as they're known, can be called on as a generator of last resort to fill a gap if a large power plant drops offline due to a serious mishap. They are usually rather inefficient single cycle gas turbines or more rarely large diesel generators. Some peakers are of the "fast start" variety that can start from a cold state to produce full power within 10 minutes.

As such, the electricity they generated is more expensive that base load or intermediate plants. About 10% of the entire generating fleet in New England consists of peaking or fast-start units. Just a few years ago, there was a shortage of peak load capacity and some new units were constructed. For example the Braintree Electric Light Department (a town owned municipal generation plant) completed last year a two unit 116 MW gas peaker plant powered by two Rolls-Royce Trent 60 single cycle gas turbines with heat rates of 9,500 BTU/kWh (an efficiency of 36%) [30].

Typically peaker plants run at capacity factors of 5% to 40% since they are less efficient than intermediate units.

Pumped storage, one solution to variable wind.

Pumped storage hydro plants operate on the principle of using excess low cost electricity at night to pump water uphill to a reservoir only to be returned during the day in reversible water turbines generating electricity at a premium price during peak needs. Pumped storage hydro plants can operate either as cycling units or peaker plants. Such plants are about 75% efficient. For every 100 MWh used in its electric motors to pump water uphill, about 75 MWh is generated in those motors, now generators, as it flows back. 

In Massachusetts the Bear Swamp plant (625 MW) in Rowe and the Northfield Mountain plant (1,080 MW) were built in the 1970s with the intent of operating as cycling units in conjunction with nuclear plants that are purely base load units. The Rowe Yankee Atomic plant is long gone but these pumped hydro plants still operate profitably as cycling units or peaker plants depending on season and intent of the owner operators.

These two pumped storage units represent 5.4% of the New England's generation capacity. This is equal to the capacity of all conventional hydro plants in New England. As a historical note, the first pumped storage unit in America was the Rocky River plant (31 MW) built in New Milford, Connecticut in 1926. It is still operating today and is a National Historic Engineering Landmark [31].

Although electricity cannot be stored on the transmission grid, energy can be stored in the form of elevated water. This pumped storage is a way not only to provide a peaking function for base load nuclear and coal generators, but also a mature way to store excess energy from windfarms for use in smoothing low wind conditions. Pumped storage units can ramp up to full power in a matter of seconds on demand.

Under development is compressed air storage in underground caverns (as in natural gas storage). It is a concept similar to pumped hydro storage where the compressed air on release powers turbine generators.

And of course there is electrical battery storage. Up until now batteries have been too small to be of commercial use. However, the advent of high capacity batteries for plug-in cars will add to the need for nighttime electricity to power our vehicles instead of gasoline. What better way to use wind power from the grid.

 

Wind Integration Issues

The total capacity of New England's fleet of some 300 electrical generators is about 31,000 MW [32]. The actual electrical production of New England's generators in 2009 was 124,749,000 MWh. This production represents an average utilization of less than half of the total installed generation capacity. In other words, the fleet has a capacity factor (CP) of less than 50% [33].

This means there is an enormous capacity, especially in flexible gas turbine powered intermediate (cycling) plants, at almost all times to back fill wind power as it waxes and wanes. In particular, the Cape Wind project of 468 MW is insignificant (about 1.5%) in size compared to the New England system capacity of 31,225 MW.

Experience has shown that there will be no major impact on the integration of wind until it reaches about 20%. ISO system operators treat a reduction in wind energy the same as they would an increase in energy demand from customers. Since variations in load and wind take place over many minutes the automatic generation control systems that monitor both load and generation every few seconds balance the two by sending signals to cycling power plants to increase or decrease their output.

Large regions like ISO NE with real time 5-minute markets tend to have greatly reduced wind integration issues because they can more quickly access the response capabilities of fast ramping natural gas turbine generation. For example, the GE 7FA frame gas turbines in a 525 MW plant have a ramp rate of up to 55 MW per minute [34].

A study for the Midwest Independent System Operator (MISO) service territory shows wind energy can be readily integrated into the utility system. The total integration cost for up to 25% from wind would be only 0.045¢/kWh [35].

California has found that the current cost of integrating wind energy is essentially zero, in part due to the large number of flexible (gas fueled cycling) generators in the state and the large balancing area [36]. Even at 20% penetration, the cost of regulation related to wind variability is fairly low, less than 0.1 cent/kWh [37].

 

Wind at Peak

Wind is generally considered a replacement fuel used of offset fossil fueled generators. But in the case of offshore wind significant contributions to the grid at peak load times are factual. For example in the winter crisis of January 14-16, 2004 grid controllers were on the verge of initiating rolling blackouts due to the inadequacy of natural gas supply. Over those three days, Cape Wind would have contributed an average of 396 MW per hour [38].

During summer peak load conditions the sea breeze effect is responsible for strong offshore winds during hot afternoons that coincide with the highest electricity demands. In those conditions, Cape Wind would have produced an average of 321 MW per hour at the grid's peak hour during each of the past ten record-setting electric demand days [39].

During those hot days, the oldest marginal power plants with high cost and heavy unhealthy emissions are called up. It is this dirty, expensive power that can be offset at those times with non-polluting offshore wind.

This data points out the benefits of offshore wind with sea breezes compared to land based wind that more often sit idle on hot summer afternoons. 

 

Impact of the Massachusetts Green Communities Act of 2008

Wind is all the more important with the adoption of the Massachusetts Green Communities Act of 2008. The Renewable Portfolio Standard (RPS) section has been updated to minimum percentages for Class I renewables [40] to be 5% in 2010 increasing at 1% a year to 15% in 2020 and then increasing at 1% a year thereafter unless modified by law [41]. The Act also introduced a Class II renewable category that includes waste-to-energy which is a component of conventional municipal solid waste plant technology with a minimum percentage of 5% in 2020 [42].

 As separate and distinct from the RPS, Section 83 of the Act requires each distribution company to twice solicit in a 5 year period (from July 1, 2009) proposals from renewable energy developers, and provided reasonable proposals have been received, enter into cost-effective long-term (10 to 15 years) contracts to facilitate the financing of renewable energy generation. The distribution companies shall not be obligated to enter into contracts that would exceed 3% of the total energy demand of their customers. The Act shall also provide for an annual remuneration for the contracting distribution company equal to 4 per cent of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract [43].

Conclusions

The advance of wind power as a replacement fuel is confirmed in the fact that over one-third of all new generation capacity in the U.S. is from wind turbines. Most of the balance is in the form of low emission natural gas fueled combustion turbines whose fast ramp rates provide a complementary base for near term solutions to our electrical energy needs. Near offshore wind will also contribute significantly to the peak load demands both in winter and hot summer days due to the sea breeze effect.

Integration into the existing grid structures is relatively straightforward at least up to a penetration of 20% or so with minimal impact in cost. This means that the goal of the Green Communities Act can be met with a mix of renewables where wind will be the dominate source. With offshore wind capacity factors near 40% it will take about three windfarms the size of Cape Wind to fulfill the Act's obligation of 15% renewables by the year 2020 [44].

While wind power is more costly this year than fossil fueled electricity one should remember that the wholesale price tripled between 2001 and 2008 went from 3.9 cents/kWh to 12.5 cents/kWh, mostly due to a quadrupling of the price of natural gas. That volatility will not relent in the future.

The benefits of energy independence, pollution avoidance, and long term price stability are all attributes that make wind the most desirable choice for future of electrical energy needs of our society.

The ISO regulations are designed such that wind power will always offset the most expensive fossil fuels. A megawatt-hour from wind replaces a megawatt-hour of fossil fuel. Wind wins.

 

Footnotes

1. "Emission Control Plan, Mirant Canal LLC Canal Station," MA DEP, January 2, 2002.

2. The EPA keeps records on all generation plants in terms of MW of electrical output and heat input (in BTUs) for all 8,760 hours during the year.

3. A British Thermal Unit (BTU) is defined as the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit. By-the-way, the letter "m" stands for the number 1,000 (from the Roman numeral "M"). So "mm" means a million, i.e. a thousand times a thousand. (Don't you love these archaic units of measurement?)

4. The theoretical equivalent of heat energy to electrical energy is 3,412 BTU/kWh. Reference your college physics handbook.  Therefore the efficiency of the plant at that hour was 3,412 divided by 9,240 or 36.9 percent.

5. During this hour 537 barrels of residual oil were consumed which is 22,554 gallons of oil.

6. The change in oil consumption from hour 18 of 35,553 gallons to 22,554 gallons at hour 23. The savings in oil is the difference in oil consumption for those two operating hours which is 13,000 gallons of oil in round numbers.

7. "Emission Control Plan, Mirant Canal LLC Canal Station," MA DEP, January 2, 2002. Table 1, Existing Historical Emission Data, 1997 to 1999.

8. Compliance with Massachusetts emission law 310 CMR 7.29, requires a maximum limit of SO2 at 3 #/MWh.

9. Compliance with Massachusetts emission law 310 CMR 7.29, requires a maximum limit of NOx at 1.5 #/MWh.

10. The difference of 29,494 gal. minus 15,859 gal. is 13,635 gallons.

11. ISO NE, "The Benefits of Uniform Clearing-Price Auctions For Pricing Electricity," March 2006, p. 1.

12. ISO NE, "Electricity Costs and Pricing in New England's Power Market," February 2006. See also ISO NE, "The Benefits of Uniform Clearing-Price Auctions For Pricing Electricity: Why Pay-As-Bid Auctions Do Not Cost Less," March 2006, p. 1.

13. ISO NE, "Electricity Costs and Pricing in New England's Power Market," February 2006.

14. The heat rate of Unit #2 is about 10, 000 BTU/kWh. The heat content of residual oil is 6,287,000 BTU/barrel. This means 628 kWh can be generated from a barrel of oil that costs $117. Hence the cost of fuel per kWh is 18.6 cents representing 80% of the wholesale cost of 24 cents/kWh.

15. The heat rate of a modern combined cycle gas turbine plant is about 7,600 BTU/kWh. A fuel price of $5/mmBTU yields a cost of fuel for a kWh of about 8 cents which represents 80% of the wholesale cost of 10 cents/kWh.

16. The spot market price of natural gas is about $4/mmBTU at the Henry Hub in Louisiana. The pipeline delivery charge is about $1/mmBTU resulting in a delivered price of about $5/mmBTU in Massachusetts.

17. "U.S. Energy Information Administration, Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report."

18. "The Economics of Nuclear Power," Uranium Information Center,  May, 2005.

19. "Record-Low Production Costs, Near-Record Output Mark Stellar Year for U.S. Nuclear Power plants," Business Wire, Feb. 20, 2007.

20. "Analysis of the Impact of Cape Wind on New England Energy Prices," Charles River Associates, February 8, 2010

21. Ibid., Charles River Associates, p. 1.

22. A "nameplate" is attached to every generator declaring the capacity of the unit (in kW or MW) and other specific details such as shaft speed (RPM), output voltage, frequency, etc.

23. "Ensuring Long Term Reliability of New England's Regional Electricity System," Gordon van Welie, President & CEO, ISO New England, Platts Northeast Power Markets Forum, March 30, 2006

24. From the Nuclear Energy Institute. http://www.nei.org/resourcesandstats/nuclear_statistics/usnuclearpowerplants/

25. The Plymouth Pilgrim nuclear plant, rated at 685 MW generated 5,869,000 MWh in 2008. The maximum generation from a 685 MW plant would be 685 MW times 8,760 hours/year = 6,000,600 MWh. The ratio of actual to maximum (the capacity factor) is 0.978 or 97.8%. An outstanding record. Reference: U.S. Energy Information Agency (EIA), http://www.eia.doe.gov/cneaf/nuclear/state_profiles/massachusetts/ma.html

26. Brayton Point data from an interview at the plant for production in 2006. Salem Harbor data from Egan Environmental for the year 2006.

27. From the Nuclear Energy Institute (NEI) and the U.S. Energy Information Agency. Updated May, 2010.

28. "Industrial facility valuation: Electric generating projects," Richard K. Ellsworth, Appraisal Journal, January 200229. "GE Gas Turbine Products,"

30. Braintree Electric Annual Report, 2008. The 58 MW turbines have a heat rate of 9,500 BTU/kWh.

31. "Rocky River Pumped Storage Hydroelectric Station," The American Society of Mechanical Engineers, September 13, 1980.

32. "ISO NE Outlook," May 2009, p. 4. New England plants able to supply about 31,225 MW of electricity. That is a maximum generation of 273,531,000 MWh over 8,760 hours/year.  Therefore the ratio of production in 2009 of 124,749,000 MWh to total capacity is 45.6%. This is the capacity factor of all of New England's generators combined.

33. "ISO NE 2008Generations Emissions Report, Preliminary Results," Helve Saarela, PAC Meeting, May 25, 2010, Slide 9.

34. GE Fact Sheet, "GE Fast Ramp AGC," A 525 megawatt combined-cycle cogeneration plant with 7FA gas turbine generators has a ramp rate of 55 MW/min.

35. "Wind Can Generate 25% of Grid Without Problem," reFocus Magazine, January 5, 2007. Study by EnerNex and WindLogics.

36. "Integrating Wind Power Into the Electrical Grid," National Conference of State Legislatures in cooperation with the National Wind Coordinating Collaborative, 2009. http://www.nationalwind.org/assets/publications/WINDFORMATTED5.pdf

37. "Multi-Year Analysis of Renewable Energy Impacts in California: Results from the Renewable Portfolio Standards Integration Cost Analysis," NREL Report No. CP-500-40058), 2006.

38. "Diversification Analysis - Natural Gas Supply/Wind Production," U.S. Department of Energy, Boston Office, A. Bender, June 6, 2004.

39. "Comparison of Cape Wind Scientific Data Tower Wind Speed Data with ISO New England List of Top Ten Electric Demand Days," Cape Wind Report, July 2, 2007.

40. Class I renewables include: solar PV, wind, ocean thermal, fuel cells using a Class I fuel, landfill methane gas, hydro up to 25 MW, low-emission biomass, marine or hydrokinetic energy, geothermal energy.

41. Renewable Energy Portfolio Standard, 225 CMR 14.00, as of December 29, 2008.

42. "Determination of the Minimum Standards for Massachusetts Class II and APS," DOER, February 5, 2009.

43. "An Act Relative to Green Communities," SENATE, No. 2768, June 23, 2008, Section 83.

44. The total retail load in Massachusetts in 2008 was 50,322,000 MWh. By 2020, 15% of that is an obligation of about 7,500,000 MWh. About 2,000,000 MWh in RECs were available in 2008 without Cape Wind. Remaining is a need for about 5,500,000 MWh of renewables by 2020. Most of that will come from wind. The annual output of Cape Wind is expected to be about 1,500,000 MWh. This means that about three wind farms the size of Cape wind will be required to meet the Green Communities Act in 2020.