When you pay your home or business’s electric bill, only roughly half of the money (in NYC) is paying for the generation of the electricity that you have consumed; the coal or natural gas used as fuel to create your electricity, plus money for the investors who built the power plant in the first place. The other half of your money goes to getting the electricity from the power plant to you. All of the wires, transformers, voltage regulators, and capacitors cost a lot to build and to maintain, and that cost must be spread across all of the consumers of electricity. All of these costs combined are called delivery charges, and you can find them on your electricity bill.
So what happens when the electricity demand in an area is predicted to exceed the capacity of the distribution system currently in place? Typically, the answer is to build a new substation to handle the additional load. This can cost hundreds of millions, or even billions, of dollars. However, is this always the best option? What is the load is only going to exceed the capacity by a small amount? Isn’t there a more cost effective way to solve the problem in some cases?
Con Edison created the Brooklyn Queens Demand Management (BQDM) Program as part of the NY REV initiative to explore whether new technologies can be used to upgrade the distribution system in a more cost effective ways than simply building more wires and substations.
 It actually covers the cost for generation and high voltage transmission, but we’ll keep it simple for now.
In the summer of 2014, Con Edison predicted that, due to increasing electricity demand, several of their sub-transmission feeders in Brooklyn and Queens would be overloaded in the next few years. These substations served the neighborhoods of Crown Heights, Ridgewood, and Richmond Hill. The hard infrastructure necessary to service these areas would cost roughly $1 billion dollars, which would then need to be covered by the ratepayers. Con Edison calculated that, in order to delay the $1 billion dollar substation until 2019, 69 MW of load reduction would be needed, out of which 17 MW could be “conventional” utility infrastructure investment. The remaining 52 MW would need to be either non-traditional utility investments or customer-sited investments. The above measures, in combination with a 80 MW load transfer to an adjacent substation, could potentially push the $1 billion investment back to 2026.
In the spirit of the Reforming the Energy Vision process, Con Edison decided to release a request for information (RFI) asking for alternative solutions to solving the impending capacity problem. The RFI allowed project developers and vendors to submit creative ideas and pricing for reducing the electricity load on the grid within the constrained zone. Customer-sited load reduction could take the form of energy efficiency measures, on-site generation technologies such as cogeneration, energy storage, or demand response. In addition, Con Edison calculated how much they could bolster the capacity of their existing substation through utility-sited improvements, such as voltage optimization.
Based on the results of this RFI, Con Edison was able to estimate how much money it would cost to incentivize development over and beyond the incentives that were already available. Armed with this information, they created a preliminary benefit-cost analysis (BCA) comparing the cost to ratepayers for building the conventional substation versus the cost for the portfolio of load reduction measures.
Con Edison estimated that the BQDM program would cost a total of $200 million. $150 million of this $200 million will be for increased incentives for customer-sited solutions, resulting in 41 MW customer sited load reduction measures (or $3.7 million per MW). The BCA showed a positive value of approximately $40mm could be achieved through the load reduction incentives, when compared to the baseline strategy of building the $1 billion dollar substation. This includes a bonus to Con Edison, intended to make the decision between conventional and non-conventional infrastructure close to neutral for Con Edison’s shareholders. The finalized BCA, submitted after all customer-sited load reduction technologies have been selected, will be compared to the initial BCA to inform future efforts to incorporate non-conventional strategies into distribution planning.
The BQDM program is a first attempt at optimizing distribution asset investment, and lowering prices for all ratepayers. With today’s connected grid, technologies such as demand response and energy storage, as well as older technologies such as combined heat and power (CHP), can all be used in tandem to defer or prevent significant “conventional” grid investments. Given the significant potential for infrastructure savings, there should be a way to reward the utilities for creating and enabling these types of programs, while still returning significant value to the ratepayers and customers willing to install distributed generation assets at their sites. Con Edison’s BQDM program should be used as a template for similar plans at other congested areas of the grid, in New York City and across the country.