Distributed Generation and Contract Demand Charges
The majority of commercial and industrial distributed generation customers in Consolidated Edison (ConEd) territory are covered under ConEd’s Service Class 9, Rate V. This electric rate includes a contract demand delivery charge, currently set at over $7/kW each month. Each user’s kW contract demand level is set by determining their historic maximum 30-minute electricity demand. This means that, regardless of the reliability of the distributed generation system, this portion of the customer’s bill is determined as if the system is not running. See the first chart below for a sample site’s electricity import both before and after CHP system installation. ConEd’s justification for the billing methodology is that they need to recover costs for maintaining their infrastructure assuming that customer’s distributed systems may not be online during system-critical times.
Recently, as a result of negotiations between ConEd and various stakeholders, ConEd has tentatively agreed to revise their rate structure in order to allow customers who own distributed generation assets to recover some of their contract demand charges. The performance-based contract demand credit is awarded based on the reliability of the on-site generation system. Credits will be awarded based on the on-site electricity production during the generator’s worst performing on-peak 30-minute period each summer period. On-peak is defined as non-holiday weekdays, between the hours of 10 am and 10 pm. The summer period is defined to be from June 15 through September 15. However, customers will be able to specify three outage events each summer period. Each outage period must be an interval of 24 hours, and the three outage events combined cannot be more than five 24-hour periods. The credit will be calculated by multiplying the lowest 30 minute generating period outside of these outage periods over the previous two summers by the contract demand delivery charge that is in effect October 1st of each year. This implies that if no on-site generation occurs during four separate outage events, then the credit will be zero. Since the summer of 2015 is the first summer that these rules are in effect, only one summer is used for the first year’s calculation.
It is up to the customer to proactively request the contract demand credit, as well as to properly collect and report the pertinent data to ConEd. If adequate data is not collected, then customers will not be eligible for the credit. If you are a ConEd customer, and you have distributed generation assets on site, contact GI Energy as soon as possible to determine whether you are eligible. It may not be too late to receive credit for this summer’s performance.
Contract Demand Credit: Real World Example
GI Energy works with a number of ConEd SC 9 Rate V customers who operate on-site generation equipment. The following data is from one of our customer’s sites in summer, 2014, and has been altered to protect the confidentiality of our customer. It is intended to show the method for calculating a given site’s contract demand credit. Note that this particular site has multiple generators in operation, which means that it is less likely that total CHP electrical output will fall to zero due to a trip of any single generator.
The “outage” periods are highlighted in light yellow, and are not counted when determining the lowest generation. In this case, the outage periods are 7/4 (does not count towards three outage periods, since it is a national holiday), 7/25, 7/28-7/29 (one outage, but two of five 24-hour periods), and 8/6. After excluding these periods, the lowest CHP system generation occurs on 7/3, when the system output measured 705.6 kW. Assuming a contract demand charge of $7.23/kW, this system performance would result in a monthly credit of $5,101 each month, or over $60,000 for the year. It should be noted that in this example, the total CHP system nameplate capacity is 2,000 kW. Therefore, the contract demand credit achieved for this system is based on 35% of nameplate capacity.
Systems with fewer numbers of generators will struggle more than systems with multiple generators since the briefest of individual generator outages risk triggering one of three allowed outage periods. Sites with a single generator would need to avoid four or more 30-minute outages in order to secure any value from the contract demand credit.
GI Energy’s Opinion of Contract Demand Credit
GI Energy applauds ConEd for working with stakeholders to reform their tariffs in order to better value distributed generation systems. However, we do believe that the interim contract demand credit system has some flaws, which we are working with ConEd to address.
First, the variable nature of the credits make it extremely difficult to anticipate the savings on a year-by-year basis. This in turn makes it impossible to include these savings when evaluating the financial viability of proposed distributed generation projects. Rather than choosing the fourth-lowest generation period for the calculation of the entire year’s contract demand credit, GI Energy would recommend using a more statistical representation of on-site generation performance. For example, ConEd could apply the credit based on the average on-peak generation of the distributed generation system over the course of the on-peak summer period. This would allow much more accurate prediction of the credit value. More importantly, it would align the performance credit with a true representation of system performance. Using data from the example above, a contract demand credit based on the average generator output for the summer on-peak period would double from 705 kW to 1,440 kW. We would argue that 1,440 kW is a more accurate performance metric for demand reduction at this site during the peak summer period, and it should be valued accordingly.
Second, the credit system does not take into account total demand reductions attributable to some distributed generation systems, especially combined heat and power (CHP) systems. For example, waste energy captured from CHP systems are often used to offset electric space heating and cooling equipment, and so are decreasing the electricity usage indirectly. For example, a CHP system equipped with an absorption chiller may reliably offset conventional electric chilling at a site. Yet, this demand reduction is not accounted for in the contract demand credit since the credit is based solely on metered electric generator output. Furthermore, these electric-driven heating and cooling systems are included in determination of a customer’s initial contract demand. Therefore, indirect electricity savings from CHP thermal production should be added to the direct electricity savings (as measured by generator output) in order to calculate the true electric demand reduction attributable to the CHP system.
Finally, and most importantly, using the fourth lowest amount of energy produced by the CHP system during the summer guarantees that the credit received will be much lower than the contract demand charge. In fact, even a site which imported zero electricity from ConEd over the course of the summer would receive a relatively small percentage of their contact demand charges back as a credit. Defining the peak period as between 10 am and 10 pm disadvantages certain distributed generation customers. For example, at sites such as commercial buildings, electric demand decreases dramatically at the conclusion of normal business hours after most of the office workers leave for the day. In some cases, the 9:30 pm – 10:00 pm building load may be less than half of the peak load. Although the CHP system might be performing as intended during this period, generator output is limited due to decreased building demand in the evening hours. In this case, the contract demand credit would be based on generator output that is suppressed due to building load, not poor CHP performance. GI Energy suggests that the contract demand credit be tied to maximum electricity import from ConEd, not minimum electricity CHP production. If this is not an option, GI Energy suggests that the peak time period is revised to better line up with the true periods of system peak demand, or that customers receive credit for the full generation capacity of their systems for periods when they are importing no electricity from ConEd.