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Subsections

CAMPUS ANALYSIS

Data Collection

Several types of data were required to complete an economic analysis for the Georgia Tech campus. First, the electrical data for the main campus meter for the entire year of 1995 was needed to characterize both the nature and magnitude of the campus electrical profile. The data was obtained from the historical records of Georgia Power. In general, electric utilities will be able to provide several years of historical data upon request.

Because the rate structure under which the campus is served contains two distinct parts, TOU and RTP, the CBL used to calculate the campus bill was needed to accurately determine the economic effects of a cogeneration system. The actual CBL used in 1995 was obtained from Georgia Power.

Data concerning the campus gas usage was also required. The data from the two meters that serve the campus central boilers is monitored by Atlanta Gas Light Company, and the historical data was available through the campus representative. The gas flow in MCF was available for each meter for every hour during 1995. The gas data for the centrally located boilers was assumed to represent the steam load of the campus for the entire year. This assumption should prove to be sufficiently accurate for analysis, since the turbine generator is intended to replace only the load served by the central boilers and does not include any of the other incidental heat load at isolated points in the campus system. During times of curtailment, the gas flow for each meter was zero. As mentioned earlier, the regression plot in Figure 10 of Chapter VI was used to estimate a campus steam load of 75,000 pounds per hour during times of gas curtailment, when oil is used.

The cost of the prime movers and heat exchangers was needed to determine the payback period for each operating strategy. Several sources were used in determining a representative cost for each system. First, an Internet site maintained by Turbine Systems Engineering, Inc., of Coweta, Oklahoma was used to supply a list of over 50 gas turbine generator sets. The data is presented in Figure 3 in Chapter 4. Recall that these prices do not include exhaust heat recovery or installation of the equipment. They are intended to provide a dollar per kW amount representative of the industry. Appendix C contains a full list of information from Solar Turbines with quoted prices for generator sets similar to the ones used in the study. The cost of the heat exchangers is also listed. The operational characteristics of the Solar turbines are representative of the assumptions taken to perform the economic analysis. Please refer to Table 1 for a summary.

 
Table 1 - Cost and Performance Data for Gas Turbine Generators Chosen for Study.
 
Turbine
Heat
Cost
Steam
Cost
Total 
Total 
Size
Rate
Generator
Equipment
Installed
(BTU/kW)
(#/hr)
Cost
Cost
10 MW
10550
$3,900,000 
50,000
$800,000 
$4,700,000 
$7,050,000 
7.5 MW
$2,700,000 
40,000
$800,000 
$3,500,000 
$5,250,000 
5 MW
12250
$1,800,000 
25,000
$900,000 
$2,700,000 
$4,050,000 
4 MW
12250
$1,700,000 
25,000
$900,000 
$2,600,000 
$3,900,000 
 

Analysis Discussion

A simple payback was all that was used to determine the economic attractiveness of the turbine generators for several reasons. First, simple payback is the easiest and most straightforward of the economic return methods to calculate. When discussing the results of an economic analysis, simple payback is the most widely understood method. Unpredictable information such as future discount rates, energy escalation rates, and equipment life is not required to determine simple payback. Finally, simple payback can easily be converted to any of the other forms of economic returns such a return-on-investment or discounted payback by someone willing to make assumptions concerning discount rates, energy escalation rates, or equipment life.

Because of the complicated nature of the rate structure, a spreadsheet was used to calculate the economic effects of a cogenerating system with each size of prime mover chosen for the study. First, since the gas data was available only on an hourly basis, the electrical data was converted to hourly readings by averaging the one-half hour data points in order to directly determine the campus heat load coincident with the campus electrical load. The savings associated with operating the differing sizes of prime movers for each operational strategy could then be calculated.

The unit cost for the different fuel sources was taken directly from the Georgia Tech bills. The average cost of fuel for both natural gas and fuel oil was calculated by averaging the weighted average fuel cost for each month of the year for several years to account for the yearly fluctuations due to weather and other factors that affect the fuel market. For natural gas, the price was determined to be $3.50 per MMBTU, and for No. 2 oil the cost was calculated as $4.82 per MMBTU, assuming 0.135 MMBTU/ gallon.16

Base Load Operating Strategy

The base load operating strategy requires that the prime movers be operated at full load for each and every hour of the year. The exhaust generated is used to produce steam. The steam is used to satisfy the campus heat load. During times of low heat demand, during the summer for example, any excess steam is discarded. During times of high heat demand, the steam shortfall is overcome through the use of the currently installed boiler system

There are several hours during the year when the campus electrical demand falls below the 10 MW limit, which is the largest sized prime mover considered in this study. The demand falls below 10 MW infrequently, but the calculations were corrected to account for these hours.

For each hour that a cogenerator is operating, some fuel is consumed and some electricity is generated. The cost of the fuel used to fire the cogenerator above and beyond the fuel that would be required to fire the campus boilers acts against the savings generated through the avoided purchase of electricity. The cost of fuel is simply and directly calculated. During normal hours, the fuel cost is calculated by multiplying the amount of fuel used by the cost of fuel on a per unit basis. The type of fuel used is determined by first establishing whether the cogenerator is operating during a time of curtailment. During non-curtailment hours, the campus cost of natural gas is used. If the campus is curtailed, the cost of No. 2 fuel oil is used.

The fuel required to fire the cogenerator exceeds the amount of fuel that would have been required were the central boilers were used to meet the campus steam load. The amount above the central boiler gas is an incremental fuel cost that offsets the electrical savings to determine the net savings of the cogeneration system.

Determining the savings obtained by generating electricity can be quite complicated and requires a good working knowledge of power company rate structures because each structure treats cogeneration differently. One of the major benefits of the base loading strategy is that it allows for the reduction of the CBL. The net effect of cogeneration on the power company grid is the permanent removal of load, therefore the CBL may be lowered to reflect that fact.

Peaking Operating Strategy

The peaking strategy does not allow a reduction of the CBL. The generator operates only during time of high RTP electrical cost (e.g. during the summer), and only for short periods of time. The cost of fuel is calculated the same as in the base loading strategy. However, since most (if not all) of the hours of operation are in the summer, there is no threat of natural gas curtailment so it will be the fuel used. The incremental cost of fuel is used to offset the savings of the generated electricity. The incremental cost is used since the generator does not operate unless the cost of electricity is above the break even cost. The remainder of the time, the campus steam load is totally met by the current boiler system.

The break even cost was calculated by using the assumed fuel cost and the efficiency of the prime movers to directly calculate the associated cost of 1 kWh of electricity. As mentioned earlier, since most often the prime movers will only operate during the summer months, the price of natural gas was used to determine the break even operating cost. Using the assumptions for the study, a "break even" cost of $0.0398 per kWh was calculated.

Thermal Following Operating Strategy

The thermal following strategy requires that the prime mover be operated in such a manner to meet the campus steam loads when possible. Any electricity that is generated will be used to offset the campus electrical load. During times when the steam load is greater than the turbine can provide, central boilers generate the remaining steam.

Because the amount of electricity being generated is purely a function of the coincident thermal load, the benefits derived from the altering of the electrical rate structure are limited. Most of the generated electricity offsets electricity bought at RTP rates, minimizing savings. Only the electricity generated while meeting the minimum campus heat load of approximately 15,000 pounds per hour (2300 kW) may be deemed as permanently removed from the Georgia Power grid and be removed from the CBL.

As the prime mover size decreases, the economic attractiveness of thermal following strategy should increase, because as a percentage, more of the generating capacity of the prime mover offsets electricity bought at the TOU-4 rate.

Once again, the cost of fuel to fire the prime mover is an incremental cost above and beyond the cost to fire the boilers operating just to satisfy the steam load. The additional cost of the fuel offsets the savings gained from electrical generation. The unit fuel cost is determined both for curtailment and non-curtailment times.