The Adaptive Power Challenge is an SCTE initiative that aims to spur development of new technologies and solutions to help manage energy across broadband networks. This initiative is based on the emerging standard known as APSIS that can help cable operators control and potentially reduce the network’s power consumption. To date, most APSIS applications have been directed at cable facilities, such as Headends and Data Centers, where equipment is centralized in contained environments. However, a frequently overlooked area of the cable infrastructure is the outside plant due to its distributed nature. In fact, the outside plant power supplies and other equipment represent 55-60% of the cable infrastructure’s total power utilization, and 65-70% of total energy cost.
Based on nearly ten years of auditing energy usage of cable networks, we estimate there to be between 600,000 and 700,000 power supplies deployed across the U.S. supporting outside plant cable networks, with an average load of 600W per power supply. Nationwide, this represents a load of 360 to 420 MW. Managing this load more effectively represents a potential energy reduction opportunity for cable operators, particularly since the development and integration of demand response tools and programs has matured over the past decade. However, demand response requirements are generally not established on a nationwide basis, but rather for individual utility territories. Additionally, these require management schemes to ensure that the network devices can be properly controlled, the cost of which may outweigh any cost saving benefits. Therefore, a selective application is necessary.
Time of Use (TOU) Tariff Baseline
As a point of comparison, let’s examine a special “time of use” tariff offered by Pacific Gas & Electric (PGE) in California. Similar programs are available in select markets which attempt to drive a voluntary load curtailment via economic considerations. In the PGE example, the utility operates a program where they can charge significant premiums for peak times. These peak times are announced 24 hours in advance and can occur between 9 and 15 times per year during the summer season, lasting for 4 hours each. In exchange for signing up for this program, customers get a discount for all kWh consumed during the summer (currently $0.0097/kWh for a typical power supply tariff). During the peak pricing events, they then are charged an additional $0.6 for each kWh. Given the flat load of a power supply, a typical 600W load consumes 2628 kWh during the summer tariff season between May and October, translating into savings of $25.49.
If no action is taken, the peak pricing events lead to additional charges between $12.96 (9 events) and
$21.60 (15 events). Thus, even without any active response, savings of $3.89 and $12.58 are realized. Active control can then be used to avoid the surcharges during the peak times. Given that the events last 4 hours, typical battery capacity may not be sufficient to bridge the entire period. At 2 hours of battery operation, savings would be between $6.48 and $10.80. If the 2-hour run time is scheduled at the end of the window, an additional benefit is derived by recharging the batteries at a lower tariff, thus mitigating charger losses. For a population of 10,000 power supplies, the savings using active control will be between $64,800 (9 events, 2 hours of avoided surcharges per event) and $216,000 (15 events, 4 hours of avoided surcharges per event).
There are several challenges:
1. This program requires active management—the XOC will have to monitor peak day announcements and place the plant in standby mode. Additionally, Continuity will need to be updated with most current utility information so that the XOC will know which power supply is serviced by which utility.
2. Any plant issues related to power supply standby functionality or battery degradation will manifest themselves during the events, potentially leading to unscheduled truck rolls.
3. The program is applicable only to metered accounts. Approximately 30% of cable outside plant power supply locations in the U.S. are billed on unmetered rates, and thus would not be eligible. However, existing status monitoring does not include (reliable) information on metering, potentially leading to triggering standby for several unmetered locations, i.e. executing a demand response without compensation. This needs to be resolved before this scheme can be adequately implemented.
Demand Response Option
It may be more beneficial to enter into a separate agreement with a utility for demand response. Many of these are available nationwide, but they are generally (a) geared to larger facilities and (b) require monitoring installations for utility verifications. To establish these for a power supply population, separate agreements will have to be negotiated with the utilities to (a) allow for aggregation of the small loads and (b) provide a status monitoring interface to the utility for monitoring purposes. Staying with the California example, Pacific Gas & Electric operates the "Scheduled Load Reduction Program," which provides an incentive payment for load reductions, but does not charge a penalty for non- compliance (other than loss of incentive). To enroll in this program, a customer selects between one and three four-hour time slots a week and is required to reduce load each time the slot time is reached. The utility pays $0.10 per kWh avoided during the months of June to September. (For simplicity's sake, we will assume recharging of the batteries occurs at a lower part peak rate, mitigating losses for a revenue-neutral charge/discharge cycle). For the assumed population of 10,000 power supplies at 600W, 3 weekly periods of 4 hours each yield 1,224,000 KWh for the 17 weeks of the program or savings of $124,000.
As with the tariff option, we face several challenges for this program to succeed:
1. This program requires active management—XOC will have to monitor peak day announcements and place the plant in standby mode.
2. It is important to ensure the OSP is supported by a consistent Preventive Maintenance program before moving into a Demand Response environment. This would guarantee that the power supplies and batteries are in good working order and that the batteries have the requisite 2 - 4 hours of runtime available.
3. Utility agreements must be negotiated separately for each utility as load reduction programs of this nature do not exist for distributed loads.
4. Using batteries to support the plant for demand response or tariff savings must be weighed against reliability considerations. The batteries should not be discharged completely so that they provide some run time protection against outages occurring during or shortly after the demand response action.
5. Batteries currently deployed in the outside plant are optimize for standby applications. They are optimized for long life at float voltage, with few, utility outage caused deep discharges assumed during their lifetime. Depending on demand response frequency and duration, batteries may have to be upgraded to deep cycle technology.
PGE Peak Day Pricing for A1 Tariff:
PGE Scheduled Load Reduction Program: