A small rural electric utility is doing its part to reduce peak system demand at every rate-class level. Pee Dee Electric Cooperative Inc. (PDEC) serves approximately 30,000 customers, or cooperative members, in six counties of northeastern South Carolina. Industrial accounts are encouraged to peak shave by the rate on which they are placed, which bills on coincident peak demand. Residential and commercial members are encouraged to switch to time-of-use (TOU) rates that, if properly used, can save members and the cooperative money on their power bills. Demand in all rate classes is also reduced by peak shaving voltage reduction. PDEC refers to this program in its entirety as the load control program.
PDEC does not generate electricity; therefore, it pays a power bill each month just like its members. The bill paid by the cooperative has an energy component — a simple accumulation of kilowatt-hours — similar to every house on the system. However, there is also a component of the monthly invoice based on the utility's metered demand during the 60-minute interval of the statewide monthly peak, also called the coincident peak demand. Predicting when this peak will occur is not an exact science, but — by keeping up with weather trends and historical temperature data — a great deal of peak-predicting success has been realized. Any load that can be removed from the system during the time of this peak leads to direct savings on PDEC's monthly invoice. As a not-for-profit utility, this cooperative passes any savings on to its members in the form of capital credits.
PDEC's 25 largest members, who account for approximately 20% of the system demand, pay for their electricity on a wholesale rate with a structure identical to the one the cooperative itself pays. Because these members have access to the same coincident peak demand rate savings, any load shedding they practice yields a direct savings on their invoices while reducing burden on the system during peak conditions.
Savings opportunities are not limited to the wholesale rate members. The rest of the system is eligible for a TOU rate. Depending on the size and rate class of the service, two different TOU rates are available. For commercial and large power services, a demand-based rate is available that has a structure similar to that of the wholesale rate. For smaller members (mostly residential), the TOU rate simply charges different prices per kilowatt-hour depending on the time of day and the season.
A plot of system peak hours shows that a large majority of the winter peaks occur during the hours ending 7 a.m. and 8 a.m. A few occurred during the hour ending 9 a.m. For this reason, the peak time on the TOU rate during winter months is from 6 a.m. to 9 a.m. when a premium is charged per kilowatt-hour. For the other 21 hours of the day, members actually get a discount compared to standard rates (not time-based).
Summer peaks are harder to predict. While a great number of them occur in the hour between 4 p.m. and 5 p.m., it is possible to have a summer peak as early as the hour ending 2 p.m. and as late as the hour ending 7 p.m. (Note: In the figure on page 43, the two peaks at the hours ending 8 p.m. and 9 p.m. were winter peaks.) The peak window — when the TOU rate is billed at a premium — during summer months is from 2 p.m. to 7 p.m.
PDEC's system now has 100% automated meter reading (AMR) coverage, using Aclara's TWACS technology, so any rate changes implemented have to be backed up with the appropriate meter/module packages. For these smaller services, Landis+Gyr's FOCUS AX TOU meter is used with Aclara's UMT-R FX module. For the accounts requiring demand monitoring, Landis+Gyr's S4e meter family is used with Aclara's CMT module.
Of course, meters and AMR modules with these capabilities cost more than the average package. PDEC deals with this added cost by increasing its monthly member-owner charge — the cooperative's term for a customer charge or facilities charge — by enough to recover the extra cost in two years. Even with this higher charge, the rates are structured to save members from US$15 (smaller accounts) up to more than $1000 (large power accounts) per month if the member takes part in the advised load shifting and shedding.
In addition to offering rates that encourage members to shave load during peak conditions, PDEC directly reduces system demand by lowering substation feeder and bus voltage. Although PDEC has 34 substations, with an average of three to four circuits each, the cooperative uses very few down-line regulators, with only 10 banks on the entire system. Furthermore, even fewer capacitors are used with only six banks in operation. For these reasons, any voltage reduction implemented at the substation level impacts the entire system.
There are three types of load on the typical grid, and they all have different responses to voltage reduction:
Constant-current loads draw the same amount of amps over a range of operational voltages, within certain limits. For these loads, a 3% reduction in supply voltage — PDEC's normal target — yields a 3% reduction in demand.
Constant power loads draw the same amount of kilowatts and kilovolt-amperes over a range of operational voltages. Reducing the supply voltage of these loads by 3% has no impact on load demand.
Constant impedance loads force current and voltage to maintain a certain ratio (because of Ohm's law: Z = V/I). Therefore, if voltage is reduced by 3%, current also must be reduced by 3%. This reduction is squared in the power equation, yielding nearly a 6% reduction in demand (97% × 97% = 94.09%).
Every utility's system has a mixture of these three load types. The blended average impact of voltage reduction depends on the concentration of each type on a system. PDEC uses supervisory control and data acquisition (SCADA) applications provided by Advanced Control Systems to lower substation bus and feeder voltage and to monitor the impacts these changes have on system demand. PDEC's engineers have written a program using Advanced Control Systems' Applix spreadsheet function that enables them to monitor real (kilowatt) and reactive (kilovolt-ampere-reactive) load for any given time period in 5-minute intervals for any substation or group of substations.
When to Peak Shave
On one particular day, load control was implemented from 3:43 p.m. until 8 p.m. The substation load would have been approximately 9000 kW during the peak without voltage reduction. Reactive load changes are even more evident. One reason it is easier to see the impact on reactive load is because the reactive load has less variation than its real counterpart from each data point to the next. Another reason is the overall reactive load profile has less of a peak, making it easier to see what the load would have been. The third reason is simply because it has a greater amplitude change. Voltage reduction seems to impact kilovolt-ampere-reactive readings more than kilowatt readings. Going back to the three load types, it is possible reactive components of loads have more of a constant impedance nature or less of a constant power nature than real load components.
Once one has accepted that voltage reduction really does reduce peak demand, the logistics of making this whole process work for a utility will need some attention. In the case of PDEC, newer substations are voltage regulated on a feeder level while older ones are still bus regulated. Each regulator bank must be taken on a case-by-case basis to determine how much the source voltage can be reduced without causing low-voltage conditions at the end of the line. For these calculations, PDEC uses Milsoft's WindMil Engineering Analysis software. Given different load settings, PDEC engineers know how much the output voltage of each bank of substation regulators can be lowered during peak conditions.
As previously mentioned, the likely hours of the system peak are somewhat predictable. All morning peaks come between 6 a.m. and 9 a.m., with the great majority of them coming in the first two hours of this window. The afternoon peak window is a little wider but generally during the 4 p.m. to 5 p.m. hour. This would be a time-consuming process if it were necessary every day. However, with historic temperature data, weather forecasts and some advice from its G&T, PDEC is able to reduce the number of control days significantly.
Heating (morning) peaks are expected from November through March. Unless a particularly cold morning is in the forecast for the second or third day of the month, PDEC always implements load control on the first morning of these months. From that point on, the forecasted temperature for the area is compared to the coldest temperature so far that month. The same is true for cooling (afternoon) peaks, except for the obvious fact that high temperatures drive the system during the months of May through September.
An Appreciable Payback
Where does that leave April and October? These shoulder months are just as likely to yield a cooling peak as a heating peak and can be very difficult to predict. An examination of statewide system demand (megawatts) versus temperature in Florence, South Carolina, the approximate center of PDEC's service territory, shows that the shoulder month of April, for example, always begins with heating (morning) peaks. At some point during the month, the inevitable warm-up starts yielding cooling (afternoon) peaks. PDEC's engineers use this information to determine the warm temperature necessary to equal the previous cool temperature peak for the month to date.
October works the same way, except it starts with afternoon peaks and ends with morning peaks. Cooler climates may experience shoulder months in May and September, and warmer areas may need to focus on March and November, but these are the two months that work for this South Carolina utility.
The voltage reduction component of PDEC's load control initiative was implemented in 1985 and was the principle cost justification for the cooperative to spend several million dollars on a SCADA system. That cost has been recovered over and over, at the rate of an average of $40,000 per month, with successful peak shaving through the years. The TOU rates are relatively new programs and not yet widespread. It is the hope of PDEC that the TOU rate programs soon will yield the same kind of results.
Companies mentioned in this article:
Rob Ardis (firstname.lastname@example.org) is the COO of Pee Dee Electric Cooperative Inc. He is a registered professional engineer and a member of the National Society of Professional Engineers, South Carolina Society of Professional Engineers and IEEE. He holds degrees in math, physics and electrical engineering.
Advanced Control Systems www.efacec-acs.com
Pee Dee Electric Cooperative www.peedeeelectric.com