1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour Ending

1 -Actual Usage —Old CBL--New CBL -----Generation |

Fig. 23-16 Single-Day Power Usage Profile Showing Hourly kW of Actual Demand, Old and New CBL, and On-Site Generation System Output.

Fig. 23-16 Single-Day Power Usage Profile Showing Hourly kW of Actual Demand, Old and New CBL, and On-Site Generation System Output.

important considerations.

If the local utility has reasonable QF rate options or demonstrates support of self-generators through cooperation or incentive programs, the choices of rates and system configuration are made easier. Some utilities offer customized rates equal to the project's cost of power to avoid bypass. If power is available from sellers other than the local utility via retail wheeling, prices for supplementary and standby power may be more attractive than in cases in which the local utility is the only retail seller. Even with retail wheeling options, utility rate options for T&D services remain a key factor.

The situation is more difficult if the utility offers either standard firm service rate options or a somewhat economically unattractive QF rate option. For instance, when supplementary or backup power is provided under typical demand/commodity rates, potential demand charges must be weighed against the cost of providing required reliability. Three strategies are commonly used to mitigate the impact of supplemental electricity cost:

1. Multiple generating units. In a single-unit system, an outage could bring financial exposure to the full impact of demand charges and penalties. The probability of multiple units experiencing simultaneous outages is less likely, hence providing a strong measure of security. An effective strategy is to purchase utility standby rate insurance for the capacity of only one of the units, with the confidence that the probabilities of more than one unit being down in a peak setting period is unlikely. Service and overhaul scheduling is also easier.

2. Redundant generating capacity. If, for example, an operating strategy is developed for a 6 MW load, this strategy might call for the installation of three 3-MW units. Standby insurance would likely not be required and project life would be extended because run-time is reduced on each of the units. Alternatively, redundancy can be provided by a lower cost backup unit. The prime units would then always be used except during an outage or maintenance interval when the standby generator is brought into service. In some cases, the standby units could also be operated for electric peak-shaving or export power duty.

3. Electric load-shedding programs. These may be automatically triggered in the event of a generator outage. Non-critical loads that can be shed to reduce the peak demand that would be incurred during a generator outage are identified. These loads can be tied into a single circuit under automatic control.

The various strategies, including purchase of standby insurance from the utility for a portion of the connected generator load (if available), take into account the probability of an outage and the potential financial exposure it represents. If demand charges are not high relative to energy (or commodity) charges, the impact of an outage will generally not be great. The project feasibility analysis should include a loss of savings resulting from the predicted number of outages.

With the availability of real-time pricing (RTP) or the ability to purchase NUG power, host facility on-site generation strategies are beginning to change. In some cases, RTP can have a detrimental effect on self-generation economics. RTP often lends itself to peak-shaving or more limited use of baseload cogeneration due to extremely low electricity costs in certain off-peak periods.

When operating on a demand sensitive rate, the facility would design the system to eliminate as many peak kW as possible. This includes the kW that may occur for only a few hours per month. With RTP, that incremental kW becomes less important; $0.50/kWh for a few kWh per month, for example, is small compared with $20/kW charged monthly for demand. Because the customer focus shifts away from elimination of peak demand charges and toward elimination of peak purchased kWh, RTP may result in the installation of a somewhat smaller generation system.

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