With the hottest days of summer approaching, utilities are looking to make sure their demand response resources are ready to be called upon when the temperature spikes. Direct Load Control (DLC) is one key type of demand response used by utilities to reduce residential air conditioning loads, a prime driver of summer peak demand. DLC technology throttles back demand to maintain grid stability and avoid the need to build additional power plants.
The latest figures from the Federal Energy Regulatory Commission (FERC) show that there are 380 DLC programs in the US providing over 8 GW of peak capacity. What you may find surprising is that nearly all of these programs, and their nearly 6 million participants, run on one-way paging networks, a technology that is nearing obsolescence.
Technology obsolescence is not the only issue facing utilities with legacy DLC systems. One-way communications means no information is sent back to the utility from the installed load control devices that cycle off customer appliances. Consequently, it is not only difficult, but also costly for utilities to verify load reductions and pinpoint non-functioning devices for repair or replacement.
In spite of these shortcomings, utilities continue to pay incentives to all participants whether or not load was shed. As legacy DLC systems continue to age and have undetected failures, their benefits decline relative to the money utilities spend to run them.
The adoption of smart grid networks present utilities with a clear opportunity to modernize their DLC infrastructure and address the shortcomings of traditional solutions. Rather than relying on outdated one-way communications infrastructure for load control, utilities can operate DLC over the same robust, two-way smart grid network that supports smart meters and other utility assets.
Utilities can opt for an accelerated replacement timeline, where all legacy devices are upgraded over a two-to-five year period. This approach results in a faster speed to full benefits realization, but also has higher upfront costs. Alternatively, devices can be replaced gradually over time as they fail or as customers churn in and out of the program. This “organic replacement” strategy has lower overall costs but results in the need to run and maintain two systems for a longer period.
Using a hypothetical utility example, let’s demonstrate the business case for a smart grid-based DLC program under an accelerated replacement timeline. Our example utility has one million customers with a 10 percent participation rate in a legacy direct load control program (100,000 DLC participants). As the business case illustrates, even an incremental investment in DLC replacement will yield a significant improvement in program benefits.
Benefits of smart grid DLC replacement
Legacy paging networks have dead spots that prevent DLC devices from receiving and responding to load control events. And since paging networks operate in one direction, they can’t detect when devices fail, which reduces the success rate of load control events over time.
By replacing paging systems with two-way communications, utilities can now cost effectively detect and repair/replace failed devices to reclaim these benefits. And with a well-designed smart grid network, utilities should realistically expect to reach over 99 percent of their DLC devices when they call an event.
In addition to the benefits of a more reliable network, load control devices have gotten more intelligent in recent years, employing better cycling algorithms that can deliver 20 percent greater peak reduction when controlling air conditioners, for example.
When this increased load drop for air conditioners is combined with the higher connection rate provided by a smart grid, a utility can achieve up to 40 percent greater DLC program benefits. For the hypothetical utility example, this improvement adds up to $447 per participant in incremental benefits over a 15-year evaluation period.
Costs of smart grid DLC replacement
The largest costs associated with replacing a legacy DLC system is the new, two-way load control hardware and installation. Smart grid DLC devices cost more than the legacy one-way devices they replace. Other expenses include systems integration to connect the existing Load Management System (LMS) or Demand Response Management System (DRMS) to the smart grid head end software along with project management-related expenses.
Adding up these numbers, the hypothetical utility investing in DLC replacement spends $176 per participant above the cost of continuing to run the legacy system for another 15 years. But, keep in mind that $176 per participant investment leads to $447 per participant in additional benefits over the same time period, which adds up to more than $27 million dollars.
Utilities worldwide, including Oklahoma Gas and Electric (OG&E) and Sacramento Municipal Utility District (SMUD), are already seeing quantifiable beneà¯¬ts from smart grid-based DR programs. By replacing a legacy load control network with one based on a smart grid network, a utility can expect a benefits-to-costs ratio in a range from 1.5 to 2.0, depending on the number of participants, value of peak capacity, amount paid out in incentives, and how quickly the old DLC system is replaced. The benefits-to-costs ratio typically out performs legacy systems, which expands demand response program viability across a broader range of situations and regions.