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4.1. ERMUSR 10-13-15 Elk River Municipal Utilities UTILITIES COMMISSION MEETING TO: FROM: Elk River Municipal Utilities Commission Tom Sagstetter—Conservation and Key Accounts John Dietz—Chair Manager Al Nadeau—Vice Chair Daryl Thompson—Trustee MEETING DATE: AGENDA ITEM NUMBER: October 13,2015 4.1 SUBJECT: Electric Service Territory Update BACKGROUND: Updates relating to the electric service territory transfer from Connexus Energy. DISCUSSION: • Area 1a Recap -On September 22, approximately 300 customers were transferred from Connexus to ERMU. The outage was minimal and went extremely well. Meters were changed out within the week. Meter reading was done in October and the data migration and meter reading data looks to very accurate. • Electric Rates—Dave Berg of Dave Berg Consulting, LLC worked with staff to analyze ERMU's options to address differences from Connexus Energy in the demand tariff philosophies. ERMU's rate is more demand focused and Connexus' rate is more energy focus. Dave Berg and staff developed a short term solution and a long term plan. Staff looks to discuss the proposed short and long term plan and have commission approval for action. • Area lb Update—This area is scheduled to be acquired on October 13 at 9:00am. Approximately 600 customers will be transferred. ACTION REQUESTED: Staff requests discussion and action on the proposed temporary demand reduction. ATTACHMENTS: • Retail Demand Rate Credit Report—Dave Berg Consulting, LLC. —September 22, 2015 NI■ PDMIEBED BY r3 , Page 1 of 1 NATURE Reliable Public Power Provider P O W E R E D T o S E R V E 56 September 22, 2015 To: Elk River Municipal Utilities From: Dave Berg Consulting Subject: Retail Demand Rate Credit Background Elk River Municipal Utilities (ERMU) is undertaking a series of service territory acquisitions from the surrounding rural electric cooperative. ERMU charges a retail demand and energy rate to all retail customers larger than 50 kW. The cooperative charges retail demand and energy rates to all customers greater than 25 kW. Both ERMU and the cooperative bill demand on a seasonal basis with higher demand rates in the summer. The effective ERMU demand rate based on total demand revenue and retail demand billing units is $13.50/kW. The cooperative's effective total demand rate is estimated to be $9.00/kW. ERMU is interested in addressing this demand rate differential as these customers transition to becoming ERMU customers. Any rate adjustments made for these new customers would also apply to ERMU's existing demand and large demand customers. ERMU's retail demand charge is approximately $4.50/kW higher than the cooperative's. However, including power cost adjustments, ERMU's energy rate for demand customers is$0.006/kWh lower than the cooperative's. This lower energy rate partially compensates for the higher demand rate. An average ERMU demand customer has a 60% monthly load factor. A 60% load factor customer uses 438 kWh per month for each 1 kW of demand. The lower ERMU energy rate would save an average demand customer $2.63 (438 kWh x 0.006) per kW of demand. This reduces the average demand difference between ERMU and the cooperative to$1.87/kW ($4.50 less$2.63). There are two other drivers that need to be considered when determining the rate impacts on the demand billed customers that are being acquired. The first is that ERMU does not charge for power factor correction. The cooperative charges the applicable monthly demand rate on billed kW and not measured kW. The billed kW is used when the customer's average power factor is less than 90 percent. For customers with a power factor less than 90 percent, their bill under the cooperative's rate will be adjusted higher but this adjustment does not occur under the ERMU rate. The second driver is some smaller customers will experience a change from the Demand Electric Service customer class to the Non-Demand Electric Service customer class. Customers that have demand between 25 kW and 49 kW will, in general, see energy cost benefits as a result of not having to pay demand or power factor correction charges. ERMU is considering temporarily lowering the demand portion of the demand and large demand retail rates. For example, a $2.00 reduction in the retail demand rate for 2016 would make the effective retail rates for ERMU and the cooperative more comparable for most demand billed customers. Based on current ERMU demand customers, this demand reduction would result in a reduction in annual revenue of approximately $761,500, or 2.4% of ERMU's total annual revenues. ERMU plans to cover this deficit 57 from existing reserve funds. Any reductions after 2016 would be dependent on overall ERMU financials, continued discrepancies between ERMU and cooperative rates and ERMU sales growth. ERMU currently purchases its wholesale power requirements from Great River Energy (GRE). In 2018, ERMU is transitioning to a new wholesale supplier, the Minnesota Municipal Power Agency (MMPA). MMPA's wholesale rate structure is different than GRE's relative to overall demand and energy rates. ERMU is anticipating that overall wholesale costs will be lower and fixed (demand) wholesale costs will also be lower under MMPA service. ERMU is also planning to conduct an electric cost-of-service and rate design study in the near future. The results of a cost-of-service study will help address rate design considerations for all ERMU customers including the demand billed customers. It is anticipated that a cost-of-service analysis will consider both the existing GRE wholesale structure and the planned MMPA wholesale structure to examine how the cost basis for ERMU customers will change with the transition of wholesale providers. The cost-of-service results will also provide useful information relative to continued adjustments to the retail demand rates. Recommendations Elk River Municipal Utilities (ERMU) is evaluating a demand rate adjustment rate mechanism which will utilize a monthly demand adjustment (either a credit or charge) for the demand billed customer class. The demand adjustment mechanism will allow ERMU to make any additional future adjustments that may be warranted without having to change the Demand Electric Service tariff repeatedly to respond to changing conditions. The monthly demand adjustment would be very similar to the Power Cost Adjustment(PCA) mechanism that is currently charged or credited per kWh of energy. The nature of the adjustments and the impact on bills will need to be communicated to existing and acquired ERMU customers in the Demand Electric Service customer classes. It will be important that the customers understand that the demand adjustment will be temporary in nature and part of the transition in the acquisition of service territory and the change to a new wholesale power supplier in 2018. Customers will also need to understand that the rates will be further adjusted as necessary in the future to maintain ERMU's financial standing and reflect ERMU's cost basis. David A. Berg, PE Principal Dave Berg Consulting, LLC 58 illi IN . b® .IYAI _ I E_ ),,.... ,- ... --al im = ram = " ' n 1 , . - .. . . ._ , _ d ril ���11� • 18 I I , � ���l ■r�'' Y -.; , , d0G9 f .a.%<1.7;),,,,-*. po 611 ;Qo �flo �m E �I �•�. ..,0 I t o ►g ood 47%,:z7..°4 p — dq 0 INI _ . 1 ILII -r _D Q a► G'I -�� - Ilr p i _ 8 •-: ' Milill '' 11 -lidif I -,�; - as= _ A o" o L r Nil' .t'O. . 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