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Subsections

RESULTS

Summary of Economic Results

For each operating strategy and generator size, a simple payback was calculated using the economic data in Chapter VII. The economic analysis could be carried to as great a degree of detail as desired, but ultimately, the attractiveness of each operating strategy relative to each other can easily be shown by using just the simple payback method.

Base Load Operating Strategy

Figure 11 shows the 5 MW generator to be the best choice for a base load strategy, with a payback of 4.1 years. None of the generators has a payback greater than 6 years. Each of the four different sizes return attractive economic results. However, the smaller the system, the higher the percentage of available heat recovered from the exhaust and therefore the better total efficiency of the system. Recall that the minimum steam load for the campus is roughly 15,000 pounds per hour. This would directly translate to a 2.3 MW generator. In other words, a 2.3 MW generator would be fully loaded, both electrically and thermally. It is reasonable then to assume that a 2.3 MW generator would return the best economic results of any of the systems considered. However, recall from Figure 3 in Chapter 4 that as the size of the turbine generator set decreases, the equipment cost per kW increases dramatically. Also, the fuel-to-electrical efficiency of operation suffers. These factors tend to push the optimum sized turbine generator to a slightly larger size.
Figure 11 - Simple Payback for the Base Loading Operational Strategy.

The base loading strategy returned the best economic results of the three operating strategies considered. Because of the nature of the rate structure that serves the campus, the electrical generating capacity of the systems considered directly offsets the electricity purchased under the TOU-4 portion of the structure. This is by far the most expensive electricity the campus buys, so the economic benefits of eliminating the purchase of this expensive electricity are considerable. Also, the prime movers under this operating strategy operate at full load at all times. This maximizes the efficiency of operation, longevity of machinery, and minimizes the control and monitoring of the system.

Peaking Operating Strategy

Figure 12 shows the economic results of the peaking strategy. The larger the turbine generator, the quicker the payback. But even with the largest turbine, the payback is approximately 28 years. Obviously this is unacceptable when considering a project on the basis of economics. The 10 MW unit offsets the largest amount of expensive electricity and has the best payback of the four turbine sizes studied. The smallest turbine, the 4000 kW unit, has the highest cost per kW and offsets the lowest amount of expensive RTP electricity. Therefore the smallest turbine has the worst payback.
Figure 12 - Simple Payback for the Peaking Operational Strategy.

The peaking strategy returned poor economic results. The major factor contributing to this is the electrical rate structure. In order to remove load from the TOU-4 rate structure, the generator must operate continuously. With the peaking strategy this is not the case. Since no permanent removal of load from the power company can be guaranteed, no adjustment to the CBL may be made, and all electricity generated offsets RTP electricity. While the cost of the electricity that the turbines are offsetting is high on average (~ $0.469 per kWh), the RTP price is only above the break even cost for 370 hours during the year. This means that although the savings are large while the turbine is on, the lack of operating hours requires many years before the initial capital investment can be recovered. Furthermore, the highest cost for electricity occurs during the summer months, times when the thermal load is low, and the amount of recoverable heat is minimal.

Thermal Following Operating Strategy

Figure 13 shows that the thermal following strategy displays an economic trend exactly opposite of the peaking strategy. The 4 MW turbine has a payback of 6.8 years, which increases to 15.1 years for the 10 MW turbine. As the prime mover size decreases, the economic attractiveness increases. This is due to the utilization of the gas turbine. As the turbine size decreases, the turbine operates at nearer full load operation for a greater portion of the time, increasing fuel-to-electrical efficiency. Remember that as the gas turbine size approaches 2.3 MW, the gas turbines approach a fully loaded operational condition, as in the base load operational strategy discussed earlier. The 10 MW turbine only operates at 40% load on average, an extremely low value for a gas turbine. Since gas turbines do not respond well to changing loads or less than full load operation, it is undesirable to operate a gas turbine at such low load factors.
Figure 13 - Simple Payback for the Thermal Following Operational Strategy.

The thermal following strategy produces some avoided electrical cost at the TOU-4 rates, but not to the extent that the base loading strategy does. The thermal following strategy only offsets the amount of TOU-4 electricity that directly coincides with the minimum campus steam load. As mentioned earlier, this is approximately 2300 kW. The remaining electricity generated above the 2300 kW threshold offsets electricity at RTP prices. During the winter months when the thermal load is high and the gas turbines are more fully utilized, a larger portion of the electricity generated by the turbine comes off the less valuable RTP portion of electric service. The summer months are exactly opposite. The gas turbines are operating at less than full load and therefore produce less electricity during times when electricity is most expensive. The seasonal dependence of the campus thermal load is one of the main factors making the thermal following strategy less than ideal.