The Power of Peak Shavingand LifeCycle Costing
Power outages caused by thunderstorms, blackouts and brownouts have always been a cause of financial losses for businesses. The impact of utility deregulation can also be highas the California energy crisis attests.
Power outages caused by thunderstorms, blackouts and brownouts have always been a cause of financial losses for businesses. The impact of utility deregulation can also be highas the California energy crisis attests.
Consulting engineers can help facility owners plan for power interruptions by suggesting appropriate energymanagement options, including:

Peakdemandshaving generators.

Bilevel lighting systems with motion sensors.

Energyefficient equipment.

Energymonitoring systems.

Lifecycle cost analysis of primepowered generators.
By assisting clients with an economic evaluation of the cost ofand potential savings fromrunning onsite power units during peak demand periods, the design professional assures that building owners and operators make wise energy choices. (For a discussion of onsite and backup power strategies, see “Scheming for Power” on page 48.)
Reducing the bill
Today, a few utilities are offering incentives to businesses that install onsite generating equipment and operate it, when directed by the utility, during peak power demand. Some utilities, however, offer obstacles insteadin the form of obsolete rules and regulationsand others are not offering adequate incentives. Businesses can only invest money in the generators if there is a reasonable payback period.
Businesses tend to use the most electric power during business hours and the least during night hours. Power use is also the highest during the summer. These variations in power demand create peaks and valleys in the utility powergeneration cycle. A business that opts for demand control during peak hours allows the utilities to reduce their peak demand and spread power usage more evenly.
With peakdemandcontrolled rates, businesses can realize as much as a 60percent discount on monthly demand charges if they agree to reduce the electric power demand to a predetermined level when the utility imposes a control period. A business can determine its own controllable load and control periods, and the discount is applied over the entire year.
Evaluating the economics
An economic evaluation of these options should take into account the cost of moneyinterest rate and annual inflation rate on fixed and operating costsperiodic utility incentives, the initial cost of the generator system and operation and maintenance costs.
Discounted payback periods for a peakdemandshaving investmentand required utility rebates or discounts to curtail the peak demands during peak hourscan be determined by using the following formulae:

Cost benefit ratio = C/S = a(an1)÷(a1), where:
C = initial cost.
S = annual savings.
I= interest rate.
g = annual inflation rate.
n = duration, i.e., payback period in years.
a = (1+g)÷(1+I).

Discounted Payback Period (n) is given by:
n = log10{[(C/Sa)(a1/a)]+1}÷(log10a).
For example, a 300,000squarefoot public facility in the Midwest that operates 7×24, yearround, needs a standby generator to meet building code requirements to supply power to egress and exit lighting, elevators, smokepurging equipment and foodpreparation equipment. The local utility requires a primepowered generator for the peakshaving discount. The utility agrees to reduce the peakdemand charges for 1,500 kW per month per annum should the facility owner run the generator a minimum of 150 hours per year.
Given these circumstances, assume the following:

Cost of batteryoperated emergency lighting: $85,000.

Installed cost of a generator system: $360,000.

Estimated annual maintenance cost: $4,000.

Estimated annual operating costs: $16,000.

Annual cost of borrowing money (I): 9 percent.

Annual inflation rate (g): 4 percent.

Estimated highest facility peak demand: 1,500 kW.
All the pertinent generator system costs are considered. The initial cost (C) of the prime generatorwith transfer switches and a control systemequals the installed cost of the generator system minus the cost of batteryoperated exit and egress lighting: C = $360,000 – $85,000 = $275,000. If the estimated annual savings from peakdemand control is $92,000, and the annual cost of borrowing at 9 percent for a 30year economic life is $26,600, then the net annual savings (S) from the utility discount is utility peakshaving discount minus the sum of annual maintenance cost, annual operating cost and annual cost of borrowing:
S = $92,000 – ($4,000 + $16,000 + $26,600) = $45,400
C/S = a = (1+g)/(1+I) = 1.04/1.09 = 0.954
C/S = 275,000/45,400 = 6.06
The simple payback period equals the installed cost divided by the annual utility incentive, or $275,000 divided by $72,000 = 3.8 years. The simple payback only considers initial installed cost, the operating and maintenance costs and annual savings. The time value of money and inflation are ignored.
However, the discounted payback period (n) formula yields:
log10[(6.06)(1.0481)(0.9541)+1]÷[log10(0.954)] = 7.3
Thus, it takes 7.3 years to pay back an investment of $275,000 with a peakshaving incentive of $92,000 at an inflation rate of 4 percent and interest rate of 9 percent when the annual costs of borrowing, maintenance and operation are included in the calculation.
A different perspective
In the following analysis, only the incremental cost of the primegenerator system is considered. In this case, the facility is required to have a 1,500kW standby generator to meet building codes and functionality requirementswhether the generator is used for peak shaving or not. The generator requires periodic maintenance and monthly operation; associated costs are not included in this analysis.
The incremental cost of providing a primepowered generator for peak shaving in lieu of a standby generator is $360,000 minus $310,000 or $50,000. The annual cost of borrowing the additional $50,000 for the prime generator is $4,828. The incremental operating cost to run the generator during peak hours equals the difference between the cost of running the generator 150 hours a year and normal maintenance of 12 hours a year.
Estimated incremental annual operating cost to run the prime generator during peak hours is $15,000 and the estimated annual savings from peak demand control is $92,000. The net annual savings (S) from the utility discount is the utility peakshaving discount minus annual operating cost plus annual borrowing costs:
$92,000 – ($16,000 + $4,828) = $71,172
C/S ratio = a = (1+g)/(1+I) = 1.04/1.09 = 0.954
C/S = 50,000/55,172 = 0.70
The discounted payback period (n) is calculated as: log10[(0.70)(1.0481)(0.9541)+1]÷[log10(0.954)] = 0.73. It takes 0.73 yearsnine monthsto pay back an investment of $50,000 with a utility peakshaving annual incentive of $82,000 with a prevailing inflation rate of 4 percent and an interest rate of 9 percent.
The example illustrates that it would be prudent to use the primepowered generator to curtail the peak demand, because the generator would be required to meet building codewhether it was used for peak shaving or not. The facility owner will reduce the annual electric bill by $82,000 with an additional investment of $50,000.
Lifecycle cost analysis can help facility owners understand the various cost elements of the generator system: initial investment, cost of borrowing, inflation, operation and maintenance cost and payback period. Facilities with onsite generation will be able to generate their own power at times of peak hours or high market prices.
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