Recent regulatory decisions in Michigan and other Midwestern states indicate a growing recognition of combined heat and power (CHP) facilities’ demonstrated reliability. The decisions impact the rates and fees charged to CHP systems due to their potential need for standby service (i.e., backup service) and are important steps toward increased financial viability of CHP facilities in the region. As other states look to encourage CHP facilities, these recent actions can provide examples of aligning rates and fees more closely to actual CHP performance.
The design of fees and charges for CHP facilities is important to their financial viability. CHP facilities are charged various fees for standby service, which they may or may not use, for the potential need to use the utility’s services as a backup during planned or forced outages. As described in detail in a previous GPI blog about why improved standby rates are important for CHP facilities, these customers:
“pay standby charges to a utility even when their systems work perfectly and don’t need standby power…Depending on the size of a customer’s CHP system, standby charges can run in the thousands (or tens of thousands) of dollars per month, which can significantly impact the economic viability of distributed energy options[such as CHP]for industrial facilities.”
While it is important for CHP facilities to pay their fair share for these services, a poorly designed fee or charge can create an economic barrier to development of these projects.
The regulatory decisions in the Midwest can create an environment of greater financial certainty for the development of CHP projects in the region, which can bring significant benefits for industries, businesses, and for the electric system as a whole. The benefits include an increase in system reliability and energy efficiency along with cost savings and emissions reductions for businesses, industries, and communities.
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 percent.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 percent.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 in 2017 by the Michigan Public Service Commission (MPSC) in case 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
Earlier this month, the Michigan Public Service Commission (MPSC) issued its order in DTE’s most recent general rate case (U-20162) and 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 use of FOR in calculating reservation fees was 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. Recent actions across the Midwest show varying approaches and models that could be instructive for other states tackling similar issues.
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.
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.6 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.”7
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 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.”8 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 reaffirmed in the MPSC’s order in case 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.”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 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 (Four Coincident Peak), which is calculated based upon customer demand coinciding with the four highest 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.
Economic viability of CHP is important for achieving its potential benefits
The recent decisions in the Midwest are an encouraging sign of greater support for CHP as part of a strategy to reduce emissions and save money for businesses and industries in the region. As states look to encourage greater efficiency and decarbonization of their electricity system, it will be important to design policies that promote deployment of strategies like CHP that can make the electricity system more resilient for the future.
About Jamie Scripps, guest author: Jamie Scripps is a principal with Hunterston Consulting LLC, where she offers advanced energy policy expertise to clients across the Midwest. Prior to founding Hunterston Consulting LLC, Jamie was a partner with 5 Lakes Energy LLC.
Jamie has provided technical support to the Great Plains Institute’s industrial energy efficiency projects since 2015.
¹Energy and Environmental Analysis, Inc., Final Report: Distributed Generation Operational Reliability and Availability Database (January 2004), prepared for Oakridge National Laboratory, available at https://www.energy.gov/sites/prod/files/2013/11/f4/dg_operational_final_report.pdf
²See 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.”)
³See Energy Resources Center, p. 11.
4Michigan Public Service Commission, Order, U-18255, April 18, 2018, p. 77
5Michigan Public Service Commission, Order, U-20162, May 2, 2018, p. 152
6See Xcel Energy Rate Book, available at https://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/rates/MN/Me_Section_5.pdf
7See Xcel Energy, Minnesota PUC Docket CI-15-115, May 19, 2016, p. 16
8Michigan Public Service Commission, Order, U-18255, April 18, 2018, p. 77
9Michigan Public Service Commission, Order, U-20162, May 2, 2018, p. 150