Guest Blog: Reliability of Combined Heat & Power (CHP) Highlighted in DTE Rate Case

By Jamie Scripps, Hunterston Consulting LLC

Jamie Scripps is a principal with Hunterston Consulting LLC, where she offers advanced energy policy expertise to clients across the Midwest. Jamie’s standby rate research has been featured in a number of proceedings throughout the country, and she is a recognized expert on policies related to cogeneration. In 2016, Jamie was featured as a Midwest Energy News “40 under 40” awardee. Prior to founding Hunterston Consulting LLC, Jamie was a partner with 5 Lakes Energy LLC.


Reliability of Combined Heat & Power (CHP) Highlighted in DTE Rate Case

On May 2, 2019, the Michigan Public Service Commission (MPSC) issued its order in DTE’s most recent general rate case no. U-20162. The order covered a range of issues, including the design of DTE’s Rider 3 for standby service and the fair apportionment of power supply demand costs for standby customers. The order re-affirmed two significant positive steps previously taken by the MPSC in the 2017 DTE rate case no. U-18255 concerning forced outage rates (FOR) in reservation fees and fairly pro-rated power supply demand charges.

Reservation Fees

Many utilities charge standby customers a fixed per kW fee each month in order to reserve standby service, even in a “no outage” month, or a month in which the customer’s combined heat and power (CHP) system works perfectly and there is no need for actual use of standby service.  CHP systems are known for being extremely reliable, with average forced outage rates on the order of less than 5%.[1] Many customers choose to install a CHP system because they desire increased reliability of electric service over that available from the utility. In fact, utility outage rates can exceed 10%.[2] In order to fairly reflect the reliability of CHP in standby rate design, a CHP system’s forced outage rate (FOR) should be used in the calculation of a customer’s reservation fee.

By focusing on the probability of a CHP system forced outage, the risk to a utility of having to serve a standby customer unexpectedly can be expressed through the reservation fee that a standby customer pays to the utility in months when the CHP system does not experience such an outage. This practice also creates an incentive for standby customers to limit their use of unscheduled standby (backup) service and strengthens the link between use of standby service to the price paid by customers to reserve such service, creating a strong price signal for customers to run more efficiently overall.[3]

Standby tariffs can make use of a variety of mechanisms to charge customers for actual use of standby service during an outage, but the reservation fee should be geared toward the likelihood of unexpected use, which is captured by a CHP system’s FOR. This approach was first adopted by the MPSC in case no. U-18255: “The Commission finds that it is reasonable to approve an R3 standby tariff that sets a monthly power supply reservation charge based on the forced outage rates of the best performing generators.”[4] The use of FOR in calculating reservation fees was recently re-affirmed by the MPSC in case U-20162: “The Commission agrees that the company’s proposal fails to recognize that the generation reservation fee is not related to actual use of R3 standby service but rather reflects a minimum required contribution toward fixed power supply costs.”[5]


Power Supply Demand Charges

Another topic where utilities and regulators have taken positive action has been around power supply demand charges for standby customers. In 2018, Dayton Power & Light in Ohio eliminated altogether the power supply demand charges in its standard service offer for standby generation service, significantly reducing monthly charges for standby service. While power supply demand charges have not been completely eliminated in Michigan, the MPSC has provided direction that these charges should be fairly pro-rated to reflect standby service customers’ partial and infrequent use of generation resources.

In its order in case no. U-18255 the MPSC stated “that it is reasonable to approve an R3 standby tariff that sets … an on-peak daily power supply demand charge based on a proration of the full service D11 monthly power supply demand charge, and a maintenance on-peak demand charge of 50% of the on-peak daily power supply demand charge.”[6] This recommendation represents an improvement over the previous design because it explicitly reflects a proration (set at 1/10) of the full service rate, and was recently re-affirmed in the MPSC’s order in case no. U-20162: “The Commission agrees with the Staff, MEIBC/IEI, ABATE, and the ALJ and finds that the current method for allocating power supply capacity costs to R3 customers should be retained.”[7]

In Minnesota, Xcel Energy provides an alternative model for demand charge pro-ration, dealing with unscheduled standby use during on-peak times by charging customers a per kWh “Peak Period Energy Surcharge” in lieu of a per kW on-peak demand charge.[8] In its 2016 filing, Xcel Energy stated: “An advantage of this energy based approach is that it functions very similarly to a daily as-used demand charge for backup service. By replacing the standby usage demand charge with an excess peak period energy usage charge … we believe standby service would more clearly and equitably recover the costs of providing standby service.”[9]

Whether eliminating or pro-rating demand charges for standby customers, fair demand charges begin with fair cost allocation in the utility’s cost of service study; this issue came to the fore in the most recent DTE rate case no. U-20162, in which the MPSC affirmed that both full service D11 power supply capacity costs and partial requirements R3 power supply capacity costs should be allocated with reference to 4CP, which is calculated based upon customer demand coinciding with the system peak demands during the summer months. This method of power supply capacity cost allocation aligns with cost causation principles for standby service customers because it reflects customers’ actual contribution to system peaks, which drive company investments in common, shared facilities. Standby customers do not hit the 4CP system peaks very often, which makes sense in light of the overall reliability of CHP systems.


[1] Energy and Environmental Analysis, Inc., Final Report: Distributed Generation Operational Reliability and Availability Database (January 2004), prepared for Oakridge National Laboratory, available at

[2] See Xcel Energy, Minnesota PUC Docket CI-15-115, May 19, 2016, p. 7 (“Company generation on average is available to service customer load 89 percent of the time, and 11 percent of the time is unavailable for either scheduled or forced outages.”)

[3] See Energy Resources Center, p. 11.

[4] Michigan Public Service Commission, Order, U-18255, April 18, 2018, p. 77

[5] Michigan Public Service Commission, Order, U-20162, May 2, 2018, p. 152

[6] Michigan Public Service Commission, Order, U-18255, April 18, 2018, p. 77

[7] Michigan Public Service Commission, Order, U-20162, May 2, 2018, p. 150

[8] See Xcel Energy Rate Book, available at

[9] See Xcel Energy, Minnesota PUC Docket CI-15-115, May 19, 2016, p. 16