4.1. ERMUSR 11-15-2016 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:
November 15, 2016 4.1
SUBJECT:
Cost of Service and Rate Design Study
BACKGROUND:
ERMU staff is has been working with Dave Berg Consulting, LLC on a cost-of-service and rate
design study. The work was done to evaluate possible changes to rates and services that are a
result of changing conditions, including but not limited to; additional customers and energy sales
from the transfer of territory from Connexus Energy to ERMU, and the transition from our
current wholesale power supplier to Minnesota Municipal Power Agency in October of 2018.
DISCUSSION:
Mr. Berg will present the findings of the final report and answer any questions the Commission
may have.
ACTIONS REQUESTED:
Receive the Final Electric Cost of Service and Rate Design Study prepared by Dave Berg
Consulting, LLC.
ATTACHMENT:
• Final Report—Electric Cost of Service and Rate Design Study
POWERED BY
1.1
Page 1 of NACURE
Reliable Public
Power Provider P w A a.E o T o SERVE
Elk River
Municipas
ELECTRIC COST OF SERVICE AND
RATE DESIGN STUDY
Final Report
November 15, 2016
UfIUE BERG COfSULTIfG. LLC
54
REPORT OUTLINE
Cover Letter
Section 1 - Introduction
Section 2 — Projected Operating Results — Existing Rates
Section 3 — Cost of Service
Section 4 — Proposed Rates
55
DRUE BERG CDf15ULTIRC. LLC
November 15, 2016
Elk River Municipal Utilities Commission
13069 Orono Parkway
PO Box 430
Elk River, MN 55330
Subject: Electric Rate Study
Commission Members:
Dave Berg Consulting, LLC has undertaken a study of the retail rates Elk River Municipal Utilities (ERMU)
charges its customers for electric service. This report summarizes the analyses undertaken and the
resulting recommendations for changes to the existing rates.
The recommended rate adjustments have been made based on overall revenue and cash reserve needs
of the utility and the results of a cost-of-service analysis. As a result of the study undertaken an overall
rate increase of 2.8% has been recommended. This adjustment has been designed to help ensure the
continued financial strength of ERMU. The increases will not affect all customers equally and specific
rate design recommendations are included for each retail rate class.
Thank you for the opportunity to be of service to ERMU through the conduct of this study. I wish to
express my appreciation for the valuable assistance I received from ERMU staff relative to the execution
of this study.
Sincerely,
Dave Berg Consulting, LLC
i
David A. Berg, P
Principal
Dedicated to providing personal service to consumer-owned utilities
Dave Berg Consulting, LLC I 15213 Danbury Ave W, Rosemount, MN 55068 1612-850-2305
www.daveberronsulting.com
Section 1
Introduction
The City of Elk River, MN owns a municipal utility providing service to
approximately 10,826 retail electric customers. The electric utility is operated by
Elk River Municipal Utilities (ERMU) and is under the direction of the Elk River
Municipal Utilities Commission. This report has been prepared by Dave Berg
Consulting, LLC to examine the rates and charges for electric service in Elk River.
The study includes an examination of the allocated cost of service based on actual
2015 utility operations with adjustments (Test Year). It also includes projected
operating results for 2016-2020 (Study Period). As a result of the analyses
undertaken and reported on herein, electric rate recommendations have been
developed for consideration by ERMU.
113 C
OFIUE BERG COnSULTirC.LLC
57
Section 2
Projected Operating Results
Existing Rates
The rates charged for electric service by ERMU, combined with other operating and non-
operating revenues, must be sufficient to meet the cost of providing services to ERMU's
retail customers. This is necessary in order to ensure the long-term financial health of
ERMU. The cost of providing electric service consists of normal operating expenses such
as production and purchased power, transmission and distribution functions, customer
and administrative functions, system depreciation expenses, capital improvements,
payments on outstanding debt and contributions to the City of Elk River and other non-
operating expenses.
An analysis of the operating results for ERMU during the 2016-2020 Study Period has
been performed assuming the current retail rates and charges remain in effect for the
electric utility through the Study Period. This analysis has been done to determine the
overall need, if any, for additional revenue through rates to meet projected revenue
requirements. The analyses and assumptions utilized in these projections are explained
below.
Estimated Revenues — Existing Rates
Retail Sales
ERMU sells retail power and energy to residential, commercial and industrial customers.
ERMU has recently been experiencing steady growth in total retail sales to its electric
customers; since 2007 annual growth in sales has averaged 3.7% per year. ERMU is
expecting an increase in sales growth for the Study Period, primarily associated with the
acquisition of additional electric service territory. During the Study Period, ERMU
anticipates acquiring 8 new service territory areas. The Study Period sales analysis
EI
DflUC UHC ConSULTIflG.LLC
58
Section 2
includes the estimated impact of the first two areas. The remaining areas are not included
at this time due to uncertainty about the customer makeup in those areas. It is estimated
that sales will increase 8% in 2016, 3 % in 2017 and 2% per year thereafter.
Exhibit 2-A is a summarized listing of ERMU's historical and projected electric operating
results at existing rates. The historical and projected revenues from retail sales of power
and energy to different groups of customers are included at the beginning of the exhibit
under Operating Revenues.
Other Operating Revenues
ERMU also receives revenue from other normal operating procedures. These revenues
are shown in Exhibit 2-A below the charges for services. These include security system
sales, landfill gas generation sales, reduced revenues due to retail customer generation
credits, connection charges and customer penalties. ERMU has recently sold its security
system business, revenues from this endeavor are removed after 2016. The generation
credits are related to a program from Great River Energy. ERMU, as will be discussed
below, is changing power supply providers in the fall of 2018. It is assumed that the
generation credit program will be discontinued following this change.
Utility Revenues combined with Other Operating Revenues results in ERMU's Total
Operating Revenues.
Revenue Requirements
Generation and Purchased Power
ERMU currently meets its wholesale power requirements through purchases from
Connexus Energy/Great River Energy (Connexus/GRE). ERMU will be switching power
supply providers in October 2018 when it will begin a new contract with the Minnesota
Municipal Power Agency (MMPA). Projections of wholesale power expenses are based
on anticipated Connexus/GRE rates through September 2018 and MMPA rates
thereafter.
- 2 -
52
Projected Operating Results — Existing Rates
ERMU's actual retail sales and wholesale requirements for the 2015 Test Year are shown
in Table 2-1.
Table 2-1
Retail Sales
And Wholesale Requirements
Item 2015
Metered Retail Sales 282,265,268 kWh
Distribution Losses 4.1 °Yo
Wholesale Energy 294,441,957 kWh
Wholesale Peak 54,188 kW
Other Operating Expenses
ERMU incurs other operating expenses associated with local electric system operations.
Transmission and distribution operating and maintenance expenses are related to the
substations, overhead and underground lines and customer facilities located in ERMU.
Operating expenses also include production related expenses for the landfill gas
generation project and the local peaking power plant. ERMU also has customer account
expenses related to serving retail electric customers. Administrative and general
expenses are required for utility management, employee benefits, training and other
administrative costs. Projected operating costs have been adjusted to reflect the sale of
the security business and the reduction in free utility services to the City. This is
represented by the reduction in distribution operating expenses from 2016 to 2017. Non-
wholesale power related expenses are based on 2015 values, the 2016 and 2017 budgets
and are generally estimated to increase by 3% per year after 2017.
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6n
Section 2
Depreciation
ERMU has annual depreciation costs based on its system investments. Depreciation
during the Study Period is based on budgeted ERMU amounts and future capital
improvements. Depreciation is a funded non-cash expense that generates monies
available for annual capital improvements and reserves.
Non-operating Revenue (Expenses)
ERMU's non-operating revenue is primarily associated with investment income and
miscellaneous revenues. Non-operating expenses are related to interest expense for
existing debt and the planned 2018 bonding. There is also a one-time non-operating
revenue in 2016 related to the sale of the security system.
City Transfer
ERMU makes an annual operational transfer to the City's general fund. The transfer is
assumed to be 4% of electric retail sales revenue, not including revenue from sales in
other cities and the acquisition areas that are part of the 2015 Territory Transfer
Agreement with Connexus Energy.
Capital Improvements
ERMU makes annual normal capital investments in its electric system. Annual electric
capital improvements for the Study Period, as budgeted by ERMU, are shown in Table 2-
2 below.
Table 2-2
Capital Improvements (1)
Capital Item 2016 2017 2018 2019 2020
Capital Fee Projects $13,756,468 $2,531,100 $11,901,122 $3,961,144 $3,731,167
(1) Includes territory transfer costs associated with Areas 1 and 2.
- 4 -
Al
Projected Operating Results — Existing Rates
Debt Service
ERMU has current debt service on outstanding debt including the recent 2016 bond issue.
ERMU is also planning a new$10,000,000 bond issue in 2018 to support budgeted capital
improvements. ERMU also makes annual payments on a note associated with the landfill
gas project.
Projected Operating Results — Existing Rates
Based on the assumptions outlined above, the resulting projected operating results
assuming continued application of the existing retail rates are summarized in Table 2-3
for the electric utility. A summary presentation of the operating results is shown in Exhibit
2-A. The results below are provided as an indication of revenue needs in the future, they
do not represent ERMU policy or historical practice regarding allowable negative results.
Table 2-3
Projected Operating Results
Existing Rates
Year 2016 2017 2018 2019 2020
Operating Revenues $34,709,120 $36,368,407 $37,805,232 $39,196,921 $40,012,175
Less Operating (33,898,794) (35,363,866) (37,481,037) (39,992,043) (41,865,483)
Expenses
Plus Non Operating 427,832 (185,885) (156,113) (532,743) (501,787)
Revenues (Expenses)
Less City Transfers (1,168,366) (1,213,507) (1,259,039) (1,288,239) (1,317,507)
Change in Net Position $69,791 $(394,850) $(1,090,957) $(2,616,103) $(3,672,601)
Net Position as
0.2% -1.1% -2.9% -6.7% -9.2%
Percent of Revenues
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R9
Section 2
Cash Reserves
A summary of the impact of the projected operating results on ERMU's cash reserves for
the Study Period is shown at the end of Exhibit 2-A and in Table 2-4 below.
As shown below, under existing retail rates and estimated revenue requirements over the
Study Period, the cash reserves for the electric utility are projected to decrease from
approximately $12.7 million at the end of 2015 to approximately negative $5.1 million by
the end of 2020. Also shown in Table 2-4 is the reserve balance goal based on ERMU
policy. The end of year reserve balance is projected to decrease from 167% of reserve
goal to negative 64% of reserve goal.
Table 2-4
Projected Cash Reserves
Existing Rates
Year 2016 2017 2018 2019 2020
Beginning Balance $12,685,126 $10,810,388 $8,985,031 $7,033,784 $1,383,933
Plus Change in Net Position 69,791 (394,850) (1,090,957) (2,616,103) (3,672,601)
Plus Depreciation 2,325,000 2,375,000 2,425,000 2,497,750 2,572,683
Plus Bond Proceeds 10,000,000 10,000,000
Less Capital Improvements (13,756,468) (2,531,100) (11,901,122) (3,961,144) (3,731,167)
Less Loss of Revenue Pmts (31,754) (373,191) (465,916) (476,136) (486,356)
Less Debt Principal P (481,307) (901,216) (918,252) (1,094,217) (1,138,385)
Ending Balance $10,810,388 $8,985,031 $7,033,784 $1,383,933 $(5,071,894)
Reserve Goal $6,460,731 $6,568,436 $7,410,265 $7,673,218 $7,927,883
Reserves as %of Goal 167% 137% 95% 18% -64%
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Section 3
Cost-of-Service
A cost-of-service analysis was performed to determine the allocated cost to serve
each of ERMU's customer classes within the electric utility. Customer classes
exist, in part, because the cost to serve various kinds of customers varies. The
cost-of-service analysis has been performed on a 2015 'Test Year' based on actual
2015 financials (with certain adjustments), operations and sales. The results of
the cost-of-service study give an indication of the degree of revenue recovery
warranted for each class of customers. A comparison of the allocated cost to serve
a class of customers and the actual revenues received from that class is taken into
consideration during rate design.
Test Year Adjustments
The following adjustments were made to the 2015 Test Year financials to modify
the test year and make the Test Year more indicative of ERMU's future operating
profile. These adjustments are shown in Exhibit 3-A.
• Power supply expenses have been adjusted to represent the transition from
Connexus/GRE wholesale power to MMPA.
• Revenues and expenses associated with the security business have been
eliminated to reflect the sale of that entity by ERM U.
• Utilities and labor donated have been reduced to reflect the full retail sale
of electricity to City accounts.
• The dispersed generation credit program tied to GRE has been eliminated.
• The transfer to the City has been increased to reflect the revised policy.
• The margin has been adjusted to reflect the combined adjustments listed
above.
13 110
OflUE BERG COt15ULTU1C.LLC
65
Section 3
Classification of Costs
ERMU's Test Year electric revenue requirements have been divided into six
distinct cost classifications. These cost classifications are described below.
Demand Related — demand related costs are fixed costs that do not vary with
hourly consumption. Demand related costs are required to meet the overall
demand of the system as expressed in kW. For ERMU, demand related costs
include the demand portion of wholesale power and production expenses, certain
transmission and distribution system expenses and a portion of administrative and
general expenses.
Energy Related —energy related costs vary based on hourly consumption in kWh.
ERMU's primary energy related costs are the energy portion of wholesale power
and production expenses, and a share of administrative and general expenses.
Customer Facilities — these costs are fixed costs associated with the service
facilities utilized to deliver electric power and energy directly to customers.
Customer Service — these costs vary by the number and type of customers and
include items such as meter reading, billing, collections and dealing with customers
by customer service representatives.
Direct — these costs are certain system related costs directly attributable to
ERMU's street light services provided to the City of Elk River.
Revenue Related — revenue related costs vary by the amount of revenue received
by the utility or are associated with other and non-operating revenues. For ERMU,
this includes transfers to the City and other operating and non-operating income.
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FF
Cost-of-Service
Table 3-1 below summarizes the classified electric costs for the 2015 Test Year.
The detailed cost classifications are shown in Exhibit 3-A and Exhibit 3-B shows
the classification of the plant-in-service.
Table 3-1
Classified Electric Costs
2015 Test Year
Revenue
Component Requirement
Demand $9,022,019
Energy 18,874,892
Customer Facility 1,833,527
Customer Service 1,173,513
Direct 213,437
Revenue 511,743
Total $31,629,131
Allocation of Costs
Based on an analysis of customer class service characteristics, the classified costs
summarized above were allocated to the major ERMU customer classes.
Allocation of costs was performed on a fully-distributed, embedded cost allocation
basis. Specific allocation factors were utilized in each of the cost classification
categories as described below. Exhibit 3-C contains a summary of the
development of the various allocation factors.
Demand Allocations
Customer class demands on a system can be reflected in various ways. Three
primary demand allocation types were utilized in this analysis. Coincident peaks
(`CP') represent a class' share of the overall system peak. A 12 CP method,
reflecting each class' estimated contribution to each month's system peak, was
- 3 -
R7
Section 3
employed for allocating the power supply demand portion of the wholesale
purchased power and production expenses. A 1 CP method was utilized for
transmission expenses. Non-coincident peaks reflect a class maximum demand
regardless of when it occurs. The non-coincident peak is an indication of the
amount of fixed local system required to serve individual groups of customers. A
1 NCP method, an estimate of each class' maximum annual demand on the
system, was utilized for allocating local system demand related costs.
Energy Allocations
Each class' share of energy requirements was used to allocate energy related
costs. The predominant energy related costs are the energy portions of the
purchased power expenses. These costs were allocated based on each classes'
estimated share of wholesale energy purchases. Other local energy related costs
were allocated based on retail energy sales.
Customer Allocations
Two separate customer allocators were utilized. The customer facilities allocator
was used to allocate costs associated with the physical facilities required to serve
individual customers such as service transformers, service drops and meters. The
customer service allocator is for allocation of costs associated with customer
service — meter reading, billing, collections and customer inquiries. For both the
customer facilities and customer service allocators, a weighted customer allocation
factor is developed. Weighting factors are developed to represent the difference
in service configurations between customer classifications. For instance, a larger
customer facility is required for a single large power customer than for a single
residential customer, or a single large power customer requires more customer
service than a single residential customer.
- 4 -
Cost-of-Service
Direct Allocations
Direct costs for ERMU are associated with certain expenses directly attributable to
street lights. These direct costs were then allocated across customer classes
based on a customer allocator.
Revenue Allocations
Revenue related costs were allocated based on each class' share of total demand,
energy, customer facility, customer service and direct costs.
Cost of Service Results
Based on the classifications and allocations described above, the estimated cost
to serve each major class of customers for the 2015 Adjusted Test Year was
determined. Exhibit 3-D presents this analysis in detail. Table 3-2 below
summarizes the total allocated electric costs for each class compared to the total
electric revenues received from the class during 2015.
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Section 3
Table 3-2
Electric Cost of Service Results
Comparison of Cost and Revenues
2015 Test Year
Customer Allocated Revenues
Classification Cost to Serve
Residential $10,644,237 $11,249,153
Commercial Non-demand 3,166,586 3,350,843
Demand 10,271,205 9,957,797
Large Demand 7,547,103 7,071,338
Total $31,629,131 $31,629,131
The revenue requirements and revenues as allocated to each class and
summarized above are shown on a total dollars basis. Table 3-3 below makes the
comparison based on percentages of total cost to serve and total revenues. The
charts following Table 3-3 show a graphical comparison between allocated cost to
serve and revenues as a percentage of the totals. The percentage
increase/(decrease) in each class' revenue shown in Table 3-3 is the adjustment
necessary to produce revenues from each class in accordance with the allocated
cost to serve. The percentage adjustments do not represent the recommended
change in each class' rates. The cost-of-service results are one item for
consideration in rate design. It is important to note also that the adjustments shown
in the table below would not change the total revenue received by the utility and
are not indicative of overall revenue needs of the utility going forward.
Recommendations regarding rate design are included in Section 4 of this report.
- 6 -
7n
Cost-of-Service
Table 3-3
Electric Cost of Service Results
Comparison of % Cost and Revenues
2015 Test Year
Customer Allocated Increase/
Classification Cost to Serve Revenues (Decrease)
Residential 33.7% 35.6% -5.4%
Commercial Non-demand 10.0% 10.6% -5.5%
Demand 32.5% 31.5% 3.1%
Large Demand 23.9% 22.4% 6.7%
Total 100.0% 100.0% 0.0%
- 7 -
71
Section 3
Allocated Cost to Serve
Large Demand,_,
23.9% `�
r Residential,
A /J 33.7%
Demand,32.5% ,
III
Commercial Non-
demand, 10.0%
Test Year Revenues
Large Demand,_
22.4% Residential,
/ 35.6%
Demand,31.5%
,._Commercial Non-
demand, 10.6%
- 8 -
72
Cost-of-Service
As indicated above, ERMU's existing class revenues do not exactly match the
allocated cost to serve each class. Cost based rates are one of several goals in
establishing rates. The relationship between allocated costs and revenues for
each class should be considered, in addition to other rate related goals, in
developing recommended rates.
Per Unit Costs
Based on the cost-of-service results shown above, the costs have been
summarized on a per unit basis by customer class and class billing data. These
per unit costs resemble rates and represent another piece of information for use in
rate design. The resulting per unit costs by rate class are shown in Table 3-4.
Table 3-4
Per Unit Electric Costs
2015 Test Year
Total
Customer
Classification Dmd Energy Cust
($/kW) ($/kWh) ($/mo)
Residential 7.83 0.0700 17.07
Commercial Non-demand 8.13 0.0698 28.12
Demand 11.95 0.0683 372.90
Large Demand 13.47 0.0678 13,512.20
- 9 -
73
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Exhibit 3-C
Elk River Municipal Utilities
2015 Test Year Allocation Factors
Commercial Large
Total Residential Non-demand Demand Demand
Demand Allocation Factors
12 Coincident Peak(kW) 517,841 161,710 55,223 187,316 113,592
12 CP 100.0% 31.2% 10.7% 36.2% 21.9%
1 Coincident Peak(kW) 54,209 21,692 6,309 16,377 9,830
1 CP 100.0% 40.0% 11.6% 30.2% 18.1%
1 Non-coincident Peak(kW) 64,586 24,103 7,192 22,846 10,446
1 NCP 100.0% 37.3% 11.1% 35.4% 16.2%
Energy Allocation Factors
Retail Energy Req.(kWh) 281,858,667 80,773,471 26,329,449 93,412,847 81,342,900
RE 100.0% 28.7% 9.3% 33.1% 28.9%
Wholesale Energy Req.(kWh) 294,441,957 85,745,296 27,950,582 96,800,878 83,945,201
WE 100.0% 29.1% 9.5% 32.9% 28.5%
Customers
Number of Customers 10,374 9,205 1,018 149 2
C 100.0% 88.7% 9.8% 1.4% 0.0%
Customer Facilities Allocation Factor
Weighted Number of Cust 22,691 9,205 2,036 7,450 4,000
CF 100.0% 40.6% 9.0% 32.8% 17.6%
Customer Service Allocation Factor
Weighted Number of Cust 11,338 9,205 1,527 596 10
CS 100.0% 81.2% 13.5% 5.3% 0.1%
Revenue Allocator
Sum Other Rev Reqs $ 31,117,388 $ 10,472,018 $ 3,115,352 $ 10,105,022 $ 7,424,995
R 100.0% 33.7% 10.0% 32.5% 23.9%
7A
Exhibit 3-D
Elk River Municipal Utilities
2015 Test Year Allocation of Revenue Requirements
Commercial Large Allocation
Total Residential Non-demand Demand Demand Factor
Demand Component
Purchased Power 4,466,929 1,394,922 476,358 1,615,799 979,850 12 CP
Production 726,794 226,961 77,506 262,899 159,427 12 CP
Transmission 5,189 2,076 604 1,568 941 1 CP
Distribution 659,043 245,947 73,384 233,124 106,589 1 NCP
General&Administrative 1,415,066 528,085 157,566 500,552 228,863 1 NCP
Depreciation 1,325,317 494,592 147,572 468,806 214,348 1 NCP
Other Operating Income (838,711) (261,911) (89,441) (303,383) (183,977) 12 CP
Non-Operating Income (6,324) (2,360) (704) (2,237) (1,023) 1 NCP
Margin 1,268,716 473,469 141,270 448,784 205,193 1 NCP
Total Demand $ 9,022,019 $ 3,101,781 $ 984,114 $ 3,225,912 $ 1,710,212
Energy Component
Purchased Power 16,020,115 4,665,264 1,520,746 5,266,781 4,567,324 WE
Production 202,129 58,863 19,188 66,452 57,627 WE
General&Administrative 210,452 60,310 19,659 69,747 60,735 RE
Depreciation 24,437 7,003 2,283 8,099 7,052 RE
Other Operating Income (236,437) (67,757) (22,086) (78,359) (68,234) RE
Non-Operating Income (74) (21) (7) (24) (21) RE
Margin 2,654,269 760,646 247,945 879,671 766,008 RE
Total Energy $ 18,874,892 $ 5,484,308 $ 1,787,728 $ 6,212,366 $ 5,390,491
Customer Facility Component
Distribution 462,220 187,507 41,474 151,758 81,481 CF
General&Administrative 643,198 260,924 57,712 211,177 113,384 CF
Depreciation 472,427 191,648 42,390 155,109 83,280 CF
Non-Operating Income (2,156) (875) (193) (708) (380) CF
Margin 257,839 104,597 23,135 84,655 45,452 CF
Total Customer Facility $ 1,833,527 $ 743,802 $ 164,517 $ 601,991 $ 323,217
Customer Service Component
Distribution 6,064 4,923 817 319 5 CS
Customer Accounts 567,076 460,393 76,374 29,809 500 CS
General&Administrative 366,266 297,361 49,329 19,253 323 CS
Depreciation 69,291 56,255 9,332 3,642 61 CS
Non-Operating Income (209) (169) (28) (11) (0) CS
Margin 165,024 133,979 22,225 8,675 146 CS
Total Customer Service $ 1,173,513 $ 952,742 $ 158,049 $ 61,688 $ 1,035
Direct Lighting Component
Distribution $ 65,211 57,863 6,399 937 13 C
General&Administrative 87,461 77,606 8,583 1,256 17 C
Depreciation 30,887 27,407 3,031 444 6 C
Non-Operating Income (136) (121) (13) (2) (0) C
Margin 30,014 26,632 2,945 431 6 C
Total Direct $ 213,437 $ 189,386 $ 20,945 $ 3,066 $ 41
Revenue Component
Other Operating Income (401,534) (135,129) (40,200) (130,394) (95,811) R
Non-Operating Income (258,344) (86,941) (25,864) (83,894) (61,644) R
Transfer to City 1,099,657 370,071 110,093 357,101 262,392 R
Margin 71,964 24,218 7,205 23,369 17,171 R
Total Revenue $ 511,743 $ 172,218 $ 51,234 $ 166,183 $ 122,108
Total Revenue Requirements $ 31,629,131 $ 10,644,237 $ 3,166,586 $10,271,205 $ 7,547,103
Total Revenues $ 31,629,131 $ 11,249,153 $ 3,350,843 $ 9,957,797 $ 7,071,338
Percent Revenue Requirements 100.0% 33.7% 10.0% 32.5% 23.9%
Percent Revenues 100.0% 35.6% 10.6% 31.5% 22.4%
Percent Change 0.0% -5.4% -5.5% 3.1% 6.7%
Revenue Req/kWh 0.112 0.132 0.120 0.110 0.093
Revenue/kWh 0.112 0.139 0.127 0.107 0.087
8n
Section 4
Proposed Rates
Changes to rates are generally based on the overall need for revenues and results of
the cost-of-service analyses. The projected operating results at existing rates as
presented in Section 2 of this report outlines the overall revenue needs of the electric
utility. Section 3 summarizes the cost-of-service results. These factors have been
considered in developing the proposed rates summarized in this section of the report.
Proposed Rates
Revenue Needs
In Section 2, it shows that ERMU's projected annual change in net position declines
from 0.2% of revenues in 2016 to negative 9.2% of revenues in 2020 assuming existing
rates are maintained through the Study Period (during 2011-2015 this averaged 5.7%).
It also shows that ERMU's projected cash reserves at current rates decline from $12.7
million to negative $5.1 million over the Study Period. The analysis shows ERMU's
reserve levels dropping below the current policy defined level by the end of 2018. In
order to strengthen ERMU's financial position, an overall rate increase of approximately
2.8% is recommended. It is recommended that this rate adjustment be effective
January 1, 2017.
Rate Design Adjustments
The unbundled analysis summarized in Section 3 shows the per unit cost of service for
each class of customers. The results of this analysis have impacted the
recommendation for specific implementation of the rate adjustment. The cost-of-service
analysis summarized in Section 3 was also taken into account in the development of
recommended rate adjustments. The proposed rates would increase estimated
revenues for the residential and commercial non-demand customers by approximately
®BG
ORM OCRC COnSULTI(IG.LLC
RI
Section 4
1.8% and increase the demand and large demand by approximately 3.7%. Specific rate
recommendations for each class to become effective in 2017 are shown in Exhibit 4-A.
ERMU's current residential monthly customer charge is $12.00, no change has been
proposed for this rate component. As a point of reference, the current Connexus
Energy residential customer charge is $13.50 per month. The residential increases
have been applied to the seasonal energy rates as shown in Exhibit 4-A. Increases to
the energy rates for off-peak storage and off-peak dual fuel have been increase,
however the rate for ground source heat pumps has not been increased. For
commercial non-demand customers, the current customer charge is $20.00 per month
is also unchanged and the increases have been applied to the energy charges.
For the commercial and industrial demand billed customers, the increases have been
focused on the energy charges. As ERMU prepares for a transition from
Connexus/GRE wholesale power to MMPA wholesale power, the wholesale cost basis
will be weighted more to energy and less to demand than the current structure. For this
cost based reason, the increases for these customers has been implemented through
the energy charges and the seasonal demand charges are unchanged. It is assumed
that the demand credit policy currently in place for these customers will continue
through 2017 at a level of $1.00/kW-month credit. It is assumed to be discontinued
after 2017.
The rate options explained above are shown as Rate Option 1 in Exhibit 4-A. In Rate
Option 2 in Exhibit 4-A, monthly customer charges are increased in each class and the
other rate component increases are decreased slightly so overall revenues match in
both options.
Exhibit 4-B shows the projected operating results for the electric utility with the proposed
rates. In Exhibit 4-B, it is assumed that the new rates will be effective January 1, 2017.
- 2 -
82
Proposed Rates
Projected Operating Results — Proposed Rates
Based on the assumptions outlined above, the resulting projected operating results with
the proposed rates are summarized in Table 4-1.
Table 4-1
Projected Operating Results
Proposed Rates
Year 2016 2017 (1) 2018 2019 2020
Operating Revenues $34,709,120 $37,357,426 $38,811,536 $40,220,571 $41,053,233
Less Operating (33,898,794) (35,363,866) (37,481,037) (39,992,043) (41,865,483)
Expenses
Plus Non Operating 427,832 (185,885) (156,113) (532,743) (501,787)
Revenues (Expenses)
Less City Transfers (1,168,366) (1,248,831) (1,295,008) (1,324,856) (1,354,773)
Change in Net Position $69,791 $558,845 $(120,623) $(1,629,070) $(2,668,811)
Net Position as 0.2/° 1.5/° -0.3% 4.1 /° 6.5%
Percent of Revenues ° ° - °
(1) Rate increase assumed effective 1/1/2017.
Cash Reserves - Proposed Rates
A summary of the impact of the projected operating results on ERMU's cash reserves
assuming the proposed rate adjustments is shown at the end of Exhibit 4-B and in Table
4-2 below. Assuming the recommended rate adjustments going forward, the projected
cash balance at the end of the Study Period increases by approximately $3.9 million as
compared to the projections at existing rates as contained in Section 2 of this report. It
also extends the time by one year before the reserves fall below the policy goal.
- 3 -
Section 4
Table 4-2
Projected Cash Reserves
Proposed Rates
Year 2016 2017 (1) 2018 2019 2020
Beginning Balance $12,685,126 $10,810,388 $9,663,103 $8,910,410 $4,479,671
Plus Change in Net Position 69,791 558,845 (120,623) (1,629,070) (2,668,811)
Plus Depreciation 2,325,000 2,375,000 2,425,000 2,497,750 2,572,683
Plus Bond Proceeds 10,000,000 10,000,000
Less Capital Improvements (13,756,468) (2,531,100) (11,901,122) (3,961,144) (3,731,167)
Less Loss of Revenue Pmts (31,754) (373,191) (465,916) (476,136) (486,356)
Less Debt Principal (481,307) (901,216) (918,252) (1,094,217) (1,138,385)
Ending Balance $10,810,388 $9,938,726 $8,957,813 $4,294,996 $(1,157,041)
Reserve Goal $6,460,731 $6,568,436 $7,410,265 $7,673,218 $7,927,883
Reserves as %of Goal 167% 151% 121% 56% -15%
(1) Rate increase assumed effective 1/1/2017.
Other Rate Considerations
Demand Billing Threshold
ERMU's current threshold for demand billing commercial customers is 50 kW. Many
utilities demand bill customers with lower demands. Billing for both demand and energy
sends a pricing signal to customer encouraging them to increase their ratio of energy
used per kW of demand. Customers with a high ratio of energy to demand are said to
have a high low factor. The cost to serve these customers on a per kWh basis is lower
because they spread fixed wholesale power and system costs over more energy units.
ERMU has been considering a reduction in the demand billing threshold from 50 kW to
25 kW. The proposed level would extend demand and energy billing to more
- 4 -
R4
Proposed Rates
commercial customers. From a rate design and cost-of-service basis it is a defendable
position. It is important that as this change is made, the utility needs to be aware of the
customers that will be impacted. Some of their bills will naturally increase and some will
decrease. The customers with increasing bills (those with low load factors) should be
apprised of steps they can take to lower their effective demands to minimize the impact
on their bills.
Large Industrial Rate
ERMU currently bills demand and large demand customers utilizing the same rate.
Some utilities have a separate large industrial rate for very large demand customers. A
separate rate for customers larger than a high level (ie. 1000 kW) is generally lower
than a regular demand customer rate. This is done under the theory that large
customers are less expensive to serve on a per unit basis due to larger economies of
scale. This may or may not be the case. Often times, large customers desire a
different level of service for reliability reasons. This scenario could actually result in
more per unit costs to serve large customers. A well designed demand and energy rate
can be fair and equitable for customers of various sizes. If ERMU wishes to consider a
large industrial rate, it may be prudent to establish a new rate class for those customers
even if the rates remain the same for demand and large demand customers. That
would allow ERMU to change the rates for large industrial customers as compared to
demand customers without needing to also establish a separate class at that time.
Net Metering
Net metering is a billing mechanism where customers with distributed generation (like
rooftop solar) are credited for electricity they deliver back to the distribution system. For
example, if a residential customer has a solar system on the home's rooftop, it may
generate more electricity than the home uses during daylight hours. If the home is net-
metered, the utility pays the customer for the excess generation. The rate paid for the
excess generation varies by state and utility.
- 5 -
85
Section 4
The State of Minnesota has a statute governing net metering. Prior to the 2015
legislative session, municipal utilities like ERMU, were required to pay the customer the
'average retail utility energy rate'. In the statute, "Average retail utility energy rate"
means, for any class of utility customer, the quotient of the total annual class revenue
from sales of electricity minus the annual revenue resulting from fixed charges, divided
by the annual class kilowatt-hour sales. For ERMU's residential customers, this would
mean reimbursing customers at the current average annual residential rate of 12.6958
cents/kWh. The customer charge is not part of the calculation and is still paid by the
customer regardless of their net metering situation.
During the 2015 legislative session, the statute was revised to include the following
language: 'A cooperative electric association or municipal utility may charge an
additional fee to recover the fixed costs not already paid for by the customer through the
customer's existing billing arrangement. Any additional charge by the utility must be
reasonable and appropriate for that class of customer based on the most recent cost of
service study. The cost of service study must be made available for review by a
customer of the utility upon request.' It is not clear how this may ultimately be
interpreted, it could mean:
• A higher customer charge to reflect more distribution fixed costs
• A different rate such as a retail demand charge structure
• A separate charge based on solar generating capacity
• Other potential interpretations
The table summarizes calculations performed based on the unbundled cost-of-service
results for the residential class to calculate a cost-based solar access charge for
application to customers installing solar generating capacity at their customer location.
Based on data for the residential class, the average ERMU residential customer has an
average monthly peak demand of 3.6 kW. The solar access charge calculation is based
on allocated fixed local costs divided by the total residential class estimated annual
billing demands. Based on the calculation, it is estimated that the cost of the local
- 6 -
Proposed Rates
system for residential customers is $6.38/kW-month. It is proposed that the access fee
be applied to the kW capacity of a customer's solar generation. This fee would apply to
all capacity in excess of the average residential monthly demand of 3.6 kW. For
instance, if a customer installs a 6 kW solar facility under a net metering arrangement,
they would be charged $6.38/kW for 2.4 kW (the amount in excess of 3.6 kW) of the
solar capacity equal to $15.31 per month. This charge would be in addition to the
regular bills calculated under ERMU's regular rate in a net metering arrangement.
Solar Access Charge
2015 Residential Data
Item Rate
Allocated Distribution Costs $2,525,903
Estimated Demand Billing Units 395,962 kW-mo
Access Fee $6.38/kW-mo
Economic Development Rates
Historically, some utilities have implemented economic development rates as an
incentive to help attract new commercial or industrial customers to locate in their service
territory. Economic development rates are special rates offered to customers that meet
certain criteria (jobs, electrical size, economic classification, etc). These special rates
are lower than a utility's published rates and are generally offered for a limited time (3-5
yrs), after which time the customers rate will revert to the published tariff. These rates
were particularly popular in the 1980s when many utilities had substantial excess
generating capacity and marginal costs to serve were well below average embedded
costs to serve. In today's cost environment, most utilities' offering an economic
development rate are offering a subsidized rate that is supported by the utility's existing
customers. New customers are happy to get an economic development rate, but the
impact on the ability to attract new customers is often debated. If existing customers
have to pay more to subsidize a new customer, many will think that is not a fair practice
- 7 -
87
Section 4
from their perspective as loyal existing customers. ERMU has new infrastructure
(substations) in its capital plans, this would tend to indicate that there is not significant
excess local distribution capacity. As a wholesale purchaser under a tariff, the
wholesale costs to serve new load are the same as the cost to serve existing
customers. If the costs to serve new customers is similar to the costs to serve existing
customers, there is not a cost-of-service justification for an economic development rate.
However, some utilities opt to offer a subsidized rate in order to try stimulate customer
growth in their service territories.
- 8 -
RR
Exhibit 4-A
Elk River Municipal Utilities
Existing and Proposed Rates
Current Rate Rate
Class Rate Option 1 Option 2
Residential
Customer (per month) $ 12.00 $ 12.00 $ 13.50
Summer Energy (per kWh) $ 0.1360 $ 0.1383 $ 0.1364
Non-summer Energy (per kWh) $ 0.1205 $ 0.1233 $ 0.1214
Off Peak Storage
Energy (per kWH) $ 0.0450 $ 0.0458 $ 0.0458
Off Peak Dual Fuel
Energy (per kWh) $ 0.0585 $ 0.0596 $ 0.0596
Ground Heat Pump
Energy (per kWh) $ 0.0900 $ 0.0900 $ 0.0900
Commercial Non-Demand
Customer (per month) $ 20.00 $ 20.00 $ 25.00
Summer Energy (per kWh) $ 0.1304 $ 0.1317 $ 0.1295
Non-summer Energy (per kWh) $ 0.1087 $ 0.1117 $ 0.1095
Commercial/Industrial Demand
Customer (per month) $ 60.00 $ 60.00 $ 150.00
Energy (per kWh) $ 0.0649 $ 0.0681 $ 0.0672
Summer Demand (per kW) $ 16.94 $ 16.94 $ 16.94
Non-summer Demand (per kW) $ 11.99 $ 11.99 $ 11.99
Off-peak Demand (per kW) $ 6.46 $ 6.46 $ 6.46
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