MidAmerican’s New Standby Rate benefits Iowa CHP Customers
December 1, 2014
In October 2014, the Iowa Utilities Board gave final approval on MidAmerican Energy’s new rate book including their revised standby rate for distributed generation (DG) technologies, including combined heat and power (CHP). This docket, RPU-2013-0004, began in 2013 with MidAmerican looking to consolidate and update their three Iowa tariffs books into one unified rate book. Last updated in 1995, MidAmerican’s previous standby rates reflected an energy market and regulatory environment that no longer exists.
As interveners, the Iowa Environmental Council (IEC) and the Environmental Law and Policy Center (ELPC) called the Energy Resources Center (ERC) to be an expert witness on standby rate issues in this docket. Through expert testimony and several meetings with MidAmerican staff the ERC was able to provide educational assistance on updating the standby rate in ways that would be less prohibitive towar44s future CHP development. The new standby rate, Rider SPS, incorporates many of the successful approaches to standby power as presented in the SEE Action’s “Guide to the Successful Implementation of State Combined Heat and Power Policies” published by the U.S. Department of Energy. Rider SPS is a significant improvement over MidAmerican’s previous standby rates and will help current and future CHP projects throughout MidAmerican’s territory achieve financial viability.
Before this docket consolidated MidAmerican’s three Iowa pricing zones under one rate book, there were three separate rate books, including three separate and disparate standby rates. Though these three rate books – from the Eastern, Northern and Southern pricing zones – were radically different from one another they all still managed to erect financial barriers to otherwise technically feasible CHP projects.
In order to gauge the financial impact of standby rates, the ERC analyzed the avoided rate as the primary metric. The avoided rate is a ratio between the price per kWh that a customer does not pay the utility when generating electricity and the fully burdened kWh price the customer pays when taking service. Because a utility must provide backup and maintenance service for onsite generation, a CHP customer will almost always be assessed monthly reservation charges even though that customer might not take any electric service in a given period. Therefore a standby customer can rarely, if ever, avoid 100% of the fully burdened electric rate. According to the U.S EPA CHP Partnership, however, standby rates that avoided at least 90% of the fully burdened electric rate are not considered financial barriers towards project implementation.
The ERC found that MidAmerican’s previous standby rates had an avoided rate not greater than 80%. Such a low avoided rate signified that standby rates posed a financial barrier towards CHP implementation in MidAmerican’s territory.
Notable Features of Rider SPS
Over the course of several productive meetings with MidAmerican staff, the ERC outlined the burdensome rate mechanics within current standby rates while providing input on possible modifications. Using the SEE Action guide as well as examples of successful standby rates throughout the U.S., the IEC, ELPC and ERC were able to reach an agreement with MidAmerican in how the new standby rate could be structured.
The most notable differences were the incorporation of a 1) dynamic reservation rate, 2) a daily demand charge and 3) the use of clear and precise mechanics.
The reservation rate separately prices the generation, transmission, substation and distribution components in order to accurately reflect the cost to provide service. In addition, the generation and transmission components are calculated using a customer’s forced outage rate (FOR). This provides financial incentive for a customer to reduce their FOR in order to decrease their monthly reservation charge.
The demand charge for maintenance events is now priced on a daily basis. This means that the standby customer pays a $/kW daily rate for capacity instead of the previous monthly demand rate. The daily demand rate is calculated by dividing the monthly supplemental demand rate by 30 and subtracting out the distribution and substation components already included in the monthly reservation rate. Using a daily demand rate allows customers to save money if they can reduce the duration of a maintenance outage event to fewer than 30 days. Standby customers are able to save a greater amount of money by further reducing the outrage duration. An example is show in the table below the article.
Lastly, unlike the rate mechanics in MidAmerican’s previous standby tariffs – most notably in the Eastern pricing zone – that were difficult to understand and model accurately, the rate mechanics in Rider SPS are clearly delineated and stipulated. This allows any potential standby customers to more accurately determine what their bill will look like before the installation of a CHP project.
As modeled by the ERC, Rider SPS averaged an avoided rate of ~89%, far greater than the previous standby rates. As it now stands, the ERC no longer views standby rates as a significant regulatory barrier for CHP customers within MidAmerican’s Iowa service territory.
For more information, contact Graeme Miller (312-996-3711, firstname.lastname@example.org).
Table 1: Standby Rate Demand Charge Comparison
This example uses the summer demand charge of $7.07/kW from the General Demand Service Rate (Rate GD) and subtracts out the sub-station and distribution components ($0.93 and $1.77, respectively) within the standby reservation charge to arrive at $4.37 for the monthly rate. Divide by 30 to arrive at $0.146 for the daily rate.
Table 2: MidAmerican Avoided Rate Comparison of Standby Rates