Summary of Impact Fee Study Report by Purpose of … · Impact fees are used to fund capital-related costs (e ... Impact Fee Charges ... A disadvantage of the inductive method is

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Summary of

Impact Fee Study Report by

R.E. Pender, Inc.

A. Purpose of Impact Fees

Impact fees are used to fund capital-related costs (e.g., new buildings) incurred in

providing governmental service to "new" development. The basic philosophy behind impact

fees is that "new" development should bear the additional or "incremental" capital cost incurred

and necessary to provide service to the "new" development. This establishes a cost causation

or "nexus" requirement between the cost incurred in providing the service and those who

benefit from the service. To be clear however, impact fees are not intended to recover annual

operating expenses (e.g., utility costs) or to pay for capital expenditures related to the correction

of an existing deficiency in the service provided.

The Company currently imposes an impact fee on a request for a new connection or

additional service. This impact fee helps the pay a portion of the costs for the new system

improvements required to serve the new development. The Company has retained R.E. Pender,

Inc. to assist in developing an impact fee based on current conditions.

B. Method of Calculating Impact Fees

The Pender Report determines the allowable impact fee based on: (1) the projected

additional demand for electricity from the future growth and (2) the Company's cost of

constructing system improvements required to deliver this electricity to customers.

The additional demand for electricity is based on the Company's projection of future

growth in electricity sales caused by new customers added to the system. This projection is

consistent with the recent historical growth on the HLP system. The Pender Report uses

the Company's growth projections to determine the total, maximum annual demand for

electricity from all classes of customers and to determine that projected increase in demand for

electricity was 4,665.9 kW for the period 2015 through 2019; and 18,842.8 kW for the period

2015 through 2034.

The cost of system improvements required to serve this additional demand was provided

by the Company's Impact Fee Facilities Plan. The Pender Report divides these projected costs

by the projected increase in demand to determine the cost/kW of these system improvements.

This amount was adjusted by a utilization factor to reflect that typical customers typically use

less electric power than the size of a typical connection.

2

C. Range of Impact Fees

The Pender Report recognizes that the Company's Board may not wish to impose the fully

allowable impact fee. It thus calculates three different impact fees based on the extent to which the

impact fees recover the cost of new system improvements. Thus, if the Board wishes the impact

fee to recover all of the costs, then the recovery level is higher and the impact fee is higher as

shown below:

Recovery Level Base Impact Fee

100% of projected cost $104.68/kWa of new demand

75% of projected cost $ 75.37/kWa of new demand

60% of projected cost $ 57.80/kWa of new demand

HEBER LIGHT & POWER

2015 IMPACT FEE STUDY REPORT

BY:

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APRIL 24, 2015

TABLE OF CONTENTS

(i)

Section 1 – Introduction & Background Information ...................................................................... 1-1 1.1 – Introduction ........................................................................................................................ 1-1 1.2 – Impact Fees – General ....................................................................................................... 1-1 1.3 – Impact Fees – Utah ............................................................................................................ 1-3 1.4 – Heber Light & Power ......................................................................................................... 1-4 1.5 – Wasatch County. ................................................................................................................ 1-5 1.6 – R. E. Pender, Inc................................................................................................................. 1-5 1.7 – Electricity Supply & Demand. .......................................................................................... 1-6 1.7.1 – General ............................................................................................................................ 1-6 1.7.2 – Electricity Supply ............................................................................................................ 1-6 1.7.3 – Transmission of Electricity ............................................................................................. 1-8 1.7.4 – Distribution of Electricity ............................................................................................... 1-8

Section 2 – Impact Fee Facilities Plan .............................................................................................. 2-1 2.1 – General ................................................................................................................................ 2-1 2.2 – Level of Service Standards ................................................................................................ 2-1 2.3 – Demands Placed on Existing Facilities ............................................................................. 2-1 2.4 – Capital Projects and Costs ................................................................................................. 2-3 2.5 – Certification of the IFFP .................................................................................................... 2-5

Section 3 – Impact Fee Analysis ....................................................................................................... 3-1 3.1 – General ................................................................................................................................ 3-1 3.2 – Impact Fee Analysis ........................................................................................................... 3-1 3.3 – Impact Fee Charges – Present and Proposed .................................................................... 3-3 3.4 – Certification of the IFA ...................................................................................................... 3-4

Section 4 – Summary and Recommendations .................................................................................. 4-1 4.1 – Summary of Findings ........................................................................................................ 4-1 4.2 – Observations and Recommendations ................................................................................ 4-2

Figures Figure 1-1 – Illustration of a Typical Power Delivery System ................................................. 1-6 Figure 1-2 – Illustration of a Load Duration Curve with Unit Stacking ................................... 1-7

Tables Table 2-1 – Summary of the Increase in CP and NCP Demands ............................................. 2-2 Table 2-2 – General Description and Cost of Projects for New Development ........................ 2-4 Table 2-3 – Schedule of Expenditures for Projects Related to New Development ................. 2-4

Appendices Appendix A – Utah Statute U.C.A. 1953 § 11-36a-102 Appendix B – Impact Fee Facilities Plan, dated April 24, 2015 Appendix C – 2006 Impact Fee Calculation Worksheet

Exhibits Exhibit 1 – Analysis of Forecasted Customer and Load Data Exhibit 2 – Analysis of Impact Fee Projects and Costs Exhibit 3 – Calculation of the Proposed Base Impact Fee Exhibit 4 – Summary of Impact Fee Charges for Residential & Commercial Customers

SECTION 1 INTRODUCTION & BACKGROUND INFORMATION

HLP 2015 Impact Fee Study Report

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1.1 INTRODUCTION

Heber Light & Power (“HLP” or the “Client”) engaged the firm of R. E. Pender, Inc. (hereinafter

“Consultant,” “firm,” “we” or “our”) to conduct certain studies and analyses related to the

development of Electric Power Impact Fees (“Impact Fees”) that will be considered for

implementation by HLP in the near future. The current HLP Impact Fees were implemented in 2005

following an impact fee study conducted by Electric Power Engineering Associates. An impact fee

study was also conducted in 2013 (the “2013 Study”), the results of which were conveyed to the HLP

Board (the “Board”) on September 25, 2013. At that time, the Board, at the recommendation of the

HLP management, voted to keep the then current impact fees in place.1 The work for the immediate

Impact Fee Study (the “2015 Study”) was conducted in accordance with a Consulting Agreement,

dated October 28, 2014 , between HLP and the Consultant ; and Utah Statute U.C.A. 1953 § 11-36a-

102.

In conducting the subject study, we relied on certain publicly available information, data supplied by

HLP and electronic spreadsheets developed specifically for this engagement. In reaching the

conclusions and recommendations discussed herein we made certain assumptions and considerations

regarding future events and circumstances that may affect the ultimate outcome of our findings. We

make no assurances or guarantees as to the actual outcome of any assumption or consideration made

in the development of our studies. However, we believe that all assumptions and considerations made

herein are appropriate and reasonable for purposes of the 2015 Study. In addition, certain information

was obtained by the firm and/or provided to the firm by other sources, all of which are believed to be

reliable and reasonable for the purpose of this undertaking.

1.2 IMPACT FEES - GENERAL

Generally speaking, impact fees are used by government agencies (e.g., city and county governments)

to fund certain capital-related costs (e.g., new buildings) incurred in providing governmental services

to “new” development as mandated by law or ordinance. The basic philosophy behind the

implementation of impact fees is that “new” development should bear the additional or “incremental”

capital cost incurred in order to provide services to the “new” development. This establishes a cost

causation or “nexus” requirement between the cost incurred in providing the service and those who

1 The Board’s action was prompted, in part, by the fact that the results of the 2013 Study showed only a slight increase in the impact fee was warranted, based on a 50 percent impact fee cost recovery scenario.



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benefit from the service. To be clear however, impact fees are not intended to recover annual

operating expenses (e.g., utility costs) or to pay for capital expenditures related to the correction of an

existing deficiency in the service provided.

There are two generally recognized methods for calculating impact fees: the inductive method and the

deductive method.

Under the inductive method, the cost and capacity of a particular facility is identified and used as the

generic model for all future facilities. Take for example the cost of a new electrical substation having

a construction cost of $2,000,000 and sized to serve approximately 5,000 residential dwelling units

and 1,000,000 of commercial square feet. In this very simple example, assuming the capital cost is

recovered evenly (50% each) between residential and commercial loads, the impact fee would be

determined as follows:

Residential = $2,000,000 x .50 / 5,000 = $200 per dwelling unit

Commercial = $2,000,000 x .50 / 1,000,000 = $1.00 per sq. foot.

An advantage to this method is that it is fairly straightforward and easy to implement. It also is not

affected by changes to capital improvement plans or population estimates. The monies needed for the

future capital requirement (like the electrical substation above) will be available as soon as actual

growth reaches the design levels, which may be any number of years down the road. A disadvantage

of the inductive method is that the impact fee calculation is based on a generic model approach and,

therefore, may not address the special needs of the community. It also may fail to capture all of the

capital requirements associated with the project, including, for example the additional facilities that

will be needed to support the primary project (e.g., required increases to the capacity of administrative

support offices).

The deductive approach involves calculating the impact fee based on the anticipated additional

demand (e.g., number of new residential dwelling units) on a facility or infrastructure used in

providing services. Normally, the entity implementing the impact fee usually will have an established

level of service (“LOS”) standard for the particular service (e.g., 1 community park per 5,000

population) or alternatively, the current LOS (1 community park serving an existing population of

4,000) is used as the basis to determine the capital requirements underlying the impact fee calculation.



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In either case, once the LOS standard is known, it is a matter of applying that standard to future

growth projections in population and/or commercial space as reflected in a master plan and/or capital

improvement plan to determine the new capital requirements.

An advantage of using the deductive method is that it will address the specific needs of the

community when determining the future capital requirements. The downside is that this method

requires much more detailed information to perform the calculations and must be updated periodically

as changes in population projections, master plans, etc. occur.

The inductive and deductive methods are both valid and the use of one or the other will depend largely

upon the information available and the specific circumstances of the community. In calculating the

subject impact fees for HLP we have employed only the deductive approach.

1.3 IMPACT FEES - UTAH

Almost all states have some form of impact fees and 26 of those states have statutes authorizing the

use of impact fees. In Utah, impact fees are governed by state statute, specifically U.C.A. 1953 § 11-

36a-102 (the “Statute”). A copy of the Statute is attached hereto as Appendix A.

Very generally, the Statute requires that each political subdivision imposing an impact fee shall, with

some exceptions, (1) prepare an Impact Fee Facilities Plan (§ 11-36a-301), (2) perform an Impact Fee

Analysis (§ 11-36a-303), (3) calculate the Impact Fee(s) (§ 11-36a-305) and (4) certify the Impact Fee

Facilities Plan (§ 11-36a-306).

According to the Statute, the “Impact Fee Facilities Plan (“IFFP”) shall identify (a) demands placed

upon existing public facilities by new development activity; and (b) the proposed means by which the

political subdivision will meet those demands.” The IFFP shall also generally consider all revenue

sources, including impact fees, used to finance impacts on system improvements.

The Impact Fee Analysis (“IFA”) portion of the Statute states that (1) “each local political subdivision

or private entity intending to impose an impact fee shall prepare a written analysis of each impact fee:”

and (2) “shall also prepare a summary of the impact fee analysis designed to be understood by a lay

person.” The requirements of the IFA include identifying the estimated impacts on existing capacity

and system improvements caused by the anticipated development activity. The political subdivision



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must also estimate the proportionate share of (i) the costs of existing capacity that will be recouped

and (ii) the costs of the impacts on system improvements that are reasonably related to the new

development activity.

The calculation of the Impact Fee may include the following:

(a) The construction contract price;

(b) The cost of acquiring land, improvements, materials, and fixtures;

(c) The cost for planning, surveying, and engineering fees for services provided for and

directly related to the construction of the system improvements; and

(d) For a political subdivision, debt service charges, if the political subdivision might use

impact fees as a revenue stream to pay the principal and interest on bonds, notes or other

obligations issued to finance the costs of the system improvements.

Also, the Calculation of the Impact Fee must be based on realistic estimates and the assumptions

underlying such estimates must be disclosed in the IFA.2

Finally, a written certification shall be included in the IFFP and the IFA by the person or entity that

prepared those requirements.

1.4 HEBER LIGHT & POWER

Headquartered in Heber City, Utah, HLP is a municipal-owned electric utility that serves about

10,7003 customers in Wasatch County. The entire service area covers about 120 square miles in what is

referred to as the Heber Valley. The utility's service area spans east to the Uinta National Forest, west

to the entrance of Snake Creek Canyon in Midway City, south to the National Forest boundary and

north to Coyote Lane on Highway 40. Along with its electric distribution system, HLP owns and

operates three hydroelectric generators and three gas/diesel generating plants with an overall

generating capacity of some 17 megawatts. Prior to the current economic slowdown, annual customer

growth averaged a robust 15-25% per year; however, recently, the growth has been a very modest 2-3%

2 The assumptions used in the 2015 Study were based largely on actual historical data for the HLP system and/or industry data obtained from reliable public sources. 3 As of year-end 2014



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per year. The customer base includes approximately 9,300 residential, 1,300 commercial and 100 street light

customers or accounts.

1.5 WASATCH COUNTY

Wasatch County is situated in north-central Utah about 40 miles to the east and south of Salt Lake City.

Heber City, the county seat, is the largest city in the county. Wasatch County is part of the Heber

Micropolitan Statistical Area as well as the Salt Lake City-Ogden-Clearfield Combined Statistical Area.

The total land and water area of the county is 1,209 square miles. As of the 2010 Census,

the county had a total population of 23,530 people and 4,743 households. The population

density in the county was 20 inhabitants per square mile. Geographically speaking, the

county lies between the Great Basin and the Unitah Basin. Elevations range from a low

point of 5,220 where the Provo River crosses the Utah County line to a high point of

nearly 10,800 feet near Murdock Mountain. Except for the Heber, Strawberry and Round valleys, the

county is mostly mountainous. Most county residents are within a 30 to 60 minute commute to a wide

range of employment opportunities. According to the Census, prior to 1970, only about 4 percent of the

work force commuted out of the county for employment. Thanks to improved roadways to Park City, Salt

Lake City and Utah County that number has increased to some 50 percent today. The increase in number of

commuters is partly due to people moving into the county for lifestyle reasons while keeping their jobs

along the Wasatch Front.4

1.6 R. E. PENDER, INC.

Located in the Orlando, Florida area, R. E. Pender, Inc. is solely-owned by Robert E. Pender, ASA.

The firm was founded in 2005 for the purpose of providing consulting services in the areas of

appraisals and valuations; wholesale and retail utility rate studies; impact fee studies; economic

feasibility studies; contract compliance reviews; and litigation support. Mr. Pender began his

consulting career with R. W. Beck, Inc., where he advanced to the position of Principal and Senior

Director. He has been recognized and qualified as an expert before the courts and regulatory

commissions in the areas of utility appraisals and utility rates and regulation. He has testified before

circuit courts, Federal District Court, the Federal Energy Regulatory Commission, arbitration panels

4 Sources: Wasatch County General Plan and en.wikipedia.org.



1-6

and utility regulatory commissions in the District of Columbia, New York, Ohio, New Mexico,

Pennsylvania and Kansas. Mr. Pender received his B.S. degree in Accounting and Business

Administration from Indiana State University in 1977. He has completed several valuation courses

through the American Society of Appraisers and is certified by that organization as an Accredited

Senior Appraiser – Public Utilities. Affiliations include the American Society of Appraisers, the

International Association of Assessing Officers, the American Water Works Association and

Government Finance Officers Association.

1.7 ELECTRICITY SUPPLY AND DEMAND

1.7.1 GENERAL

As illustrated in Figure 1-1 below, an electrical power delivery system is made up of three basic

components or functions: electric generators that produce the power; a transmission system to

deliver the power to the distribution system; and the distribution system which delivers the

power to the end-user.

Figure 1-1 Illustration of a Typical Power Delivery System

Source: en.Wikepedia.org

1.7.2 ELECTRICITY SUPPLY

In any electrical system, electricity (measured in kilowatt-hours) is produced by a number of

generation technologies, powered by a diversity of fuel resources. These generators may include

steam (nuclear, coal and oil); hydroelectric (run-of-river and pumped storage); combined-cycle



1-7

(natural gas and fuel oil); simple-cycle (natural gas and fuel oil) and internal combustion (diesel).

The utility may also utilize generation supplied by others in the form of purchased power

agreements, which can include firm power (long-term, interim and short-term); unit power (a

purchase out of a specific generating unit) and non-firm (usually short-term). The type and

amount of each generating resource that is utilized by the utility in meeting its hourly demand

(measured in megawatts) for electricity at any point in time will depend primarily on the amount

and duration of the demand, the availability of the generating units and the variable operating

cost of the generating unit(s). Very simply, in meeting the daily demand for electricity, each

available generating resource is stacked according to its operating cost (lowest to highest) and

subsequently dispatched to meet the demand for electricity in each hour of the day. This so-

called “merit” stacking/dispatch procedure can be illustrated as follows:

Figure 1-2 Illustration of a Load Duration Curve with Unit Stacking

0

5000

10000

15000

20000

25000

30000

Load Duration (0% - 100%)

Load

(M

W)

Load (MW)

The utility’s peak demand is the highest demand for electricity (measured in megawatts) recorded in

any one hour (based on a 15, 30 or 60 minute interval) and occurring within a specified time period

(day, week, month, year or seasonal (summer, winter). It is during these peak periods that a utility

will utilize its entire portfolio of generating resources including its peaking generating resources such

as combustion turbines. However, because of their relatively high operating costs, combustion



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turbines are usually called upon for only a very short period of time – when the utility’s peak demands

are at the highest levels.

1.7.3 TRANSMISSION OF ELECTRICITY

Immediately after leaving the generator, electricity is transformed (i.e., stepped up to a higher voltage)

for delivery to the utility’s high-voltage (“H-V”) transmission system. Generally, the H-V

transmission system consists of the towers, conductor, substations and other equipment necessary to

deliver power from the various generating stations to the utility’s distribution system or to other

utilities interconnected with the H-V transmission system. H-V transmission system voltages

typically range from 115 kilovolts to 500 kilovolts. A power transmission system is sometimes

referred to colloquially as a "grid." Redundant paths and lines are provided so that power can be

routed from any power plant to any load center, through a variety of routes, based on the economics

and physical characteristics of the transmission path and the cost of power. Much analysis is done by

transmission system owners to determine the maximum reliable capacity of each line, which, due to

system stability considerations, may be less than the physical or thermal limit of the line. The H-V

transmission system is continually monitored for potential “over-loading” conditions and utilities will

sometimes be called upon to reduce/increase output at certain generating plants in order to relieve the

condition. The location of generating plants in relation to the electricity load on the H-V transmission

system is a very important consideration in utility planning. Needless-to-say, because of aesthetic,

environmental, political, regulatory and other factors, generating plants and the transmission lines

making up the “grid” can rarely be placed in the optimum location allowing for the for most efficient

utilization of electric system. Transmission bottlenecks or “constraints” as they are typically

referred to are sometimes created because the transmission grid is not configured or sized correctly to

allow for the uninterrupted flow of power from the generating plant to the load centers experiencing

the highest demand. Moreover, the level and duration of the constraint can vary depending on amount

of load on the system, unit outages, and events affecting the flow of power.

1.7.4 Distribution of Electricity

Electricity distribution is the final stage in the delivery of electricity to end-users. A distribution

system's network carries electricity from the transmission system and delivers it to consumers.

Generally, a typical electric distribution system would include medium-voltage (e.g., 12.46 kV -



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46 kV) power lines, substations, switches, poles, transformers, service drops and metering. The

distribution system begins as the voltage is stepped down (e.g., 69 kV / 12.47 kV), via the

substation transformer(s) and ends as the secondary service enters the customer's meter socket.

Distribution circuits begin at the low-voltage side of the transformer located in the substation.

Conductors for the distribution delivery system are either located overhead on utility poles, or

buried underground in the case of urban, downtown areas or new developments. Urban and

suburban distribution is normally three-phase in order to serve all types of customers; residential,

commercial, and industrial.

Most electric customers are connected to a transformer (pole mounted or ground level protective

enclosure), which reduces the distribution voltage to the relatively low voltage used by lighting

and interior wiring systems. Each customer has an "electrical service" or "service drop"

connection and a meter for billing.

SECTION 2 IMPACT FEE FACILITIES PLAN

HLP 2015 Impact Fee Study Report 2-1

2.1 GENERAL

As discussed above, the Impact Fee Facilities Plan (“IFFP”) shall, in accordance with the Statute,

identify (a) demands placed on existing public utilities by new development activity; and (b) the

proposed means by which the local subdivision will meet those demands. In addition, each local

political subdivision shall generally consider the revenue sources that will be used to finance the

impacts on system improvements.

The IFFP, as discussed herein, is a summary presentation of the “Impact Fee Facilities Plan,” dated

April 24, 2015, prepared internally by the HLP staff. That report is attached hereto as Appendix B

and is incorporated herein by reference.

2.2 LEVEL OF SERVICE STANDARDS

As is the case with most any electric utility system, HLP plans, designs and operates its system based

on certain standards and criteria outlined in industry treatises such as the American National

Standards Institute (“ANSI”) and the Institute of Electrical and Electronics Engineers (“IEEE”)

Standards Association. These standards, which may be supplemented at the local level based on the

specific needs of the utility, typically address such things as:

• Transformer ratings under varying load levels and loading conditions;

• First contingency emergency situations;

• Distribution circuit loading criteria;

• Primary circuit voltage drop; and

• Distribution circuit reinforcement.

Using the above criteria, the utility will determine its future facility needs based on the amount of load

(i.e., demand) placed on the existing system over a pre-determined planning horizon (e.g., five years).

2.3 DEMANDS PLACED ON EXISTING FACILITIES

The demand placed on an electric system is typically measured in kilowatts (kW) or kilovolt-amperes

(kVa) and stated as either coincident-peak (“CP”) demand or non-coincident peak (“NCP”) demand.

The system CP demand is typically the maximum hourly demand for the entire system measured over

some time period (e.g., week, month, year); i.e., the point in time where the sum of all demands placed



on the system are the highest. The NCP demand represents the sum of the maximum demands of

individual customers or customer classes (e.g., residential, commercial, industrial) measured or

estimated for time period (e.g. week, month, year) and the demand(s) may or may not occur the time

of the system peak demand. For purposes of calculating Impact Fees, we believe that NCP represents

the proper measure of demands placed on existing facilities, primarily because the NCP demand is

normally the demand that utility plans for when sizing facilities that will be used to meet future growth

on the system.

The analysis of HLP demands, energy and customers for 2014, and projected separately for the five-

year period ending in 2019 and the twenty-year period ending in 2034, is shown in Exhibit 1 attached

hereto. Page 1 of Exhibit 1 is a summary of the detailed analysis shown on pages 2-5 of the same

exhibit. The analysis of the coincident and non-coincident peak demands are summarized hereunder

in Table 2-1.

Table 2-1 Summary of the Increase in CP and NCP Demands

For the Periods 2014-2019 and 2014-2034

Description Actual 2014

Forecast 2019

5-Year Increase

Forecast 2034

20-Year Increase

Total System CP Demands (kW) 35,573.0 39,275.0 3,702.0 51,509.5 33,352.6

NCP Demands at Meter (kW) Residential Commercial Security Lighting

21,306.8 18,553.9

5.0

23,901.1 20,624.9

5.6

2,594.3 2,071.0

0.6

31,739.0 26,964.5

6.5

10,432.2 8,410.6

0.9

Total System 39,865.7 44,531.6 4,665.9 50,203.5 10,337.8

The demands were analyzed for two distinct periods (5-year and 20-year) because of the nature of the

capital projects to be recovered through Impact Fees (discussed further in Section 2.4 below).

Referring again to Exhibit 1 (pages 2-5), the System CP Demands for the period 2015 through 2025,

shown on line 1 of Exhibit 1, were developed internally by HLP staff and reviewed by the Consultant.

The Consultant developed the System CP Demands for the remainder of the 20-year period (2026 –

2034). The Estimated NCP Demands (measured at the meter) shown on lines 21-24 were computed

based on the Projected Energy Sales (lines 4-7) and the following assumptions and considerations:

• Customer growth (lines 30-32) reflects an approximate growth rate of 2.0 percent over the

entire forecast period, reflecting recent historical trends in population growth for Wasatch

County.



• Growth in Average Annual Usage per Customer (lines 17-19) for all customer classes was

assumed to be nil due to increases in appliance efficiencies and demand side management

programs.

• Estimated NCP Load Factors (lines 32-34) were assumed to be: Residential – 43.2%;

Commercial – 43.0% and Street Lights – 100.0%.

• The System Load Factor (line 3) was assumed to average approximately 53% over the

forecast period.

As discussed later in Section 3, it is the estimated change (i.e., increase) in the Total System NCP

Demand from 2014 to 2019 and 2014 to 2034 that is used as the basis for calculation of the Impact

Fees. As reflected in Table 2.1 above, the total combined increase in NCP Demand for Residential

and Commercial during 2014 – 2019 amounts to 4,465.3 kW; for 2014 – 2034 the combined increase

is 10,336.8 kW.

As noted in the IFFP (Appendix B), given the current demand level and existing capacity of the

system, HLP cannot serve the expected increase demand over the next five or twenty-year planning

horizons without increasing the capacity of the system. As discussed below, the increase in capacity

will be accomplished through a number of capital improvement projects undertaken over the next five

years.

2.4 CAPITAL PROJECTS AND COSTS

The Capital Projects that are needed to meet the increase in demand caused by new development

activity were determined from an internal analysis conducted by the HLP staff. HLP staff identified a

total of nine (9) capital projects that are all or partially related to new development activity. The types

of projects and related costs are summarized in the following Table 2-2.



Table 2-2 General Description and Cost of Projects

Fully or Partially Related to New Development

Description Total Cost

Percent Related to

New Develop.

Cost Assigned to

New Develop.

Partially-related Projects

Reconductor / Rebuild Projects (4) Additional Interconnection Substation (1)

$1,130,000 5,500,000

60% 50%

$678,000 $2,750,000

Fully-related Projects

Additional Circuits and Tie Line (3) Additional Transformer (1)

1,170,000 615,000

100% 100%

1,170,000 615,000

Totals $8,415,000 $5,213,000

All of the above projects are expected to be completed by Year 2019, with expenditures being made

during the period 2015 through 2019, as depicted in the following Table 2-3.

Table 2-3 Schedule of Expenditures

For Projects Related to New Development

Year Annual

Expenditures Percent of

Total Cumulative

Expenditures Percent of

Total

2015 $ 600,000 11.5% $ 600,000 11.5%

2016 1,233,000 23.6% 1,833,000 35.2%

2017 2,662,000 51.1% 4,495,000 86.2%

2018 520,000 10.0% 5,015,000 96.2%

2019 198,000 3.8% $5,213,000 100.0%

Total $5,213,000 100.0%

All of the above-described projects that are fully (100%) related to New Development activity are

expected to be funded fully or partially from the proposed Impact Fees (discussed below).

2.5 CERTIFICATION OF THE IFFP

I certify that the attached Impact Fee Facilities Plan:

1. includes only the costs of public facilities that are:

a. allowed under the Impact Fees Act; and

b. actually incurred; or


c. projected to be incurred or encumbered within six years after the day on which each

impact fee is paid;

2. does not include:

a. costs of operation and maintenance of public facilities;

b. costs for qualifying public facilities that will raise the level of service for facilities,

through impact fees, above the level of service that is supported by existing residents;

c. an expense for overhead, unless the expense is calculated pursuant to a methodology

that is consistent with generally accepted cost accounting practices and the

methodological standards set forth by the federal Office of Management and Budget

for federal grant reimbursement; and

3. complies in each and every relevant respect with the Impact Fees Act.

CERTIFIED By' Signature: ~/~~!:t::~U~JL-======:::::".-=--

Name: Jas --~----------------------

Title: General Manager

Date: April 24, 2015


SECTION 3 IMPACT FEE ANALYSIS


3.1 GENERAL

As discussed in Section 1, the IFA portion of the Statue requires that each local political subdivision

or private entity intending to impose an impact fee prepare a written analysis of each impact fee. It

also requires that IFA include a summary designed to be understood by a lay person. Additional

requirements include identifying the estimated impacts on existing capacity and system improvements

caused by the anticipated development activity. The political subdivision must also estimate the

proportionate share of (i) the costs of existing capacity that will be recouped and (ii) the costs of the

impacts on system improvements that are reasonably related to the new development activity.

3.2 IMPACT FEE ANALYSIS

The IFA is presented in the attached Exhibit 2 and Exhibit 3. Exhibit 2 shows the Impact Fee projects

(discussed above) by type and the year of construction; the Estimated Total Project Cost (column a);

the Percent Related to New Development (column b) and the Impact Fee Project Costs at Various

Recovery Levels (columns c, d and e). Three (3) distinct Impact Fee recovery levels were modeled –

100 percent, 75 percent and 60 percent. The various recovery levels are designed to allow the HLP

Board to consider the appropriate Impact Fee it wishes to implement, taking into account such things

as economic development goals and the residual effect on electric rates (i.e., the portion of project

costs that are not recovered from Impact Fees will need to be recovered through electric rates). The

60 percent recovery level is based on the HLP staff’s recommendation after considering the social and

competitive aspects of both Impact Fees and electric rates and seeking to achieve an appropriate

balance of the sharing of the subject project costs between ratepayers and new development. The

total Impact Fee project costs to be recovered under the three recovery levels are shown on line 11 of

Exhibit 2. Because of the manner in which one of the projects (i.e., the Additional Interconnection

Substation) will be funded, it was necessary to segregate this project from those that will be funded

directly from Impact Fees (see lines 11-13). It is anticipated that the Additional Interconnection

Substation will be funded from new debt that will be issued by HLP in the near future. Therefore, the

cost of this project to be recovered from Impact Fees (and electric rates) must take into account the

total debt service (i.e., principal and interest) that will ultimately be incurred by HLP over the life of

the bond(s) issued. The total costs for the remainder of the projects to be funded directly from Impact

Fees are shown on line 13. These remaining amounts were adjusted to take into account the current



balance in the Impact Fee Fund (i.e., the unspent Impact Fee revenues associated with previously

completed Impact Fee projects). This credit adjustment produces the net balance of project costs to be

funded directly from Impact Fees (line 15).

The calculation of the proposed Impact Fee at various recovery levels is shown in Exhibit 3. As

discussed above, the analysis is bifurcated between two types of Impact Fee projects: (i) the “Direct

Recovery Projects” (see line 1) to be recovered over a 5-year period; and (ii) the single “Bonded

Project” (see line 2) that will be recovered over a 20-year period. The amounts shown for the Direct

Recovery Projects (column a, lines 4 – 6) were carried over from Exhibit 2. The amounts shown for

the Bonded Project (column b, lines 4-6) were separately calculated to reflect the total debt service on

this project that will incurred in the future (see pages 2 – 4 of Exhibit 3). The debt service

computations are based on the following assumptions:

• The term of the debt issue is 25 years;

• Debt issuance costs are 3.0 percent;

• The annual interest rate is 4.50 percent

The resulting amounts at the three assumed recovery levels are carried over to Exhibit 3, page 1.

Once the total cost under the assumed Impact Fee recovery levels was determined (line 2-4), the three

recovery amounts were then divided by the total Increase in Non-Coincident Peak Demand (line 9) to

determine the Base Impact Fee at the Various Recover Levels (lines 10-12). These amounts were

multiplied times an average customer electric panel utilization factor of 15 percent, which produced

the following Impact Fees (see column c, lines 13-15):

Recovery Impact Level Fee

100% $104.68

75% 75.37

60% 57.80

The 15% panel utilization factor was provided by HLP staff and is consistent with the like factor used

in the 2005 Impact Fee Study prepared for HLP. We believe that this factor is reasonable and

appropriate for the development of the subject Impact Fees.

We should note that all of costs to be recovered through the proposed Impact Fees are directly related

to new development activity; that is, none of the costs of existing facilities are proposed to be



recovered through the new Impact Fees. Those costs will be borne by current and future ratepayers.

In addition, the HLP Board will ultimately decide which Impact Fee it wishes to implement. In

contemplation of their decision, we believe the Board will take into consideration the proportionate

sharing of costs between new development and utility ratepayers, as well as the overall effect on the

economic base of the area HLP serves.

3.3 IMPACT FEE CHARGES – PRESENT AND PROPOSED

A summary of Impact Fee charges for the Residential and Commercial customer classes is provided in

the attached Exhibit 4. The estimated charges, shown by the selected electric panel size, have been

calculated under each of the proposed Impact Fees as compared to the current Impact Fee. The

calculation of the Impact Fee charge, as set forth in HLP Service Rule No. 16, is based on the

following formula:

Main Panel Size (Amps)

X line to line voltage (kVa)

X 1 (1.732 for 3 phase service)

X Applied Impact Fee

= Impact Fee Payable

Charges under the currently effective Impact Fee, shown under column (a) of Exhibit 4, are calculated

using a base fee of $41.40. The worksheet that HLP uses to determine impact fees for new

connections is attached as Appendix C. Charges under each proposed impact fee is shown in columns

(b) through (d) of Exhibit 4. For example, based on an Impact Fee of $57.80 (at a 60% recovery

level), a new residential connection having panel rating of 200 amps would incur the following Impact

Fee charge:

200 x 240 / 1000 x $57.80 = $2,774

Similarly, a 3-phase commercial customer with a 2000 amp panel rating would incur the following

charge when a proposed Impact Fee of $57.80 is used:

2,000 x 208 / 1000 x $57.80 = $41,645

While we are of the opinion that the proposed Impact Fees at the 100 percent recovery level are just

and reasonable based on the analyses undertaken, the HLP Board must ultimately decide what level of

recovery is appropriate given proportionate sharing considerations, current socioeconomic conditions

and circumstances of the HLP service area.



3.4 CERTIFICATION OF THE IFA

I certify that the attached Impact Fee Analysis:




c. projected to be incurred or encumbered within six years after the day on which each

impact fee is paid;



b. costs for qualifying public facilities that will raise the level of service for facilities,

through impact fees, above the level of service that is supported by existing residents;

c. an expense for overhead, unless the expense is calculated pursuant to a methodology

that is consistent with generally accepted cost accounting practices and the

methodological standards set forth by the federal Office of Management and Budget

for federal grant reimbursement; and

3. offsets costs with grants or other alternate sources of payment; and

4. complies in each and every relevant respect with the Impact Fees Act.

CERTIFIED BY:

Signature

Name: Robert E. Pender, ASA

Title: President

Company: R. E. Pender, Inc.

Date: April 24, 2013

SUMMARY AND RECOMMENDATIONS


At the request of HLP, the Consultant has reviewed the HLP IFFP and completed an IFA; both

prepared in accordance with applicable Utah Statutes and collectively referred to as the 2015 Impact

Fee Study. In preparing the subject studies and analyses the Consultant has reached the following

findings and conclusions.

4.1 SUMMARY OF FINDINGS

Impact Fee Facilities Plan

• On a non-coincident peak basis, the demand placed on existing facilities is projected to be

44,531.6 kW in Year 2019 and 50,203.5 in Year 2034 (see Table 2-1). This represents an increase

of 4,665.9 kW during the 5-Year Recovery Period (2015 – 2019) and an increase of 10,337.8

during the 20-Year Recovery Period. The increase in demand over these two periods is entirely

due to new development that HLP will be required to serve.

• In order to meet the increase in demand from new development occurring over the 5-year and 20-

year recovery periods, the Consultant, in collaboration with the HLP staff, has identified nine (9)

projects that will need to be completed by year 2018. The total construction cost of these projects,

to be funded fully or partially through Impact Fee charges, amounts to $5,213 thousand.

Impact Fee Analysis

• The analysis of the proposed Impact Fees is shown in Exhibit 3. Proposed Impact Fees were

designed for two (2) distinct recovery periods (5-year and 20-year) at three (3) optional recovery

levels (100%, 75% and 60%) which will allow the HLP Board to consider the appropriate revenue

contribution levels from new development activity, electric rates and other potential funding

sources.

• The proposed base Impact Fees were calculated using (i) the total construction cost that will be

incurred for new development, segregated between eight (8) Direct Recovery Projects (i.e., to be

recovered directly from Impact Fees over a 5-year period) and one (1) Bonded Project to be

recovered through Impact Fees over a 20-year period. The total cost of the Direct Recovery

Projects was adjusted to reflect the current balance in the Impact Fee Fund. The total cost of the

Bonded Project was adjusted to reflect the financing costs associated with a new debt issue to fund

the project. The total adjusted cost for each category of projects was then divided by the total



increase in demand over each recovery period (as previously discussed) and multiplied by an

assumed average electric panel utilization of 15 percent. The proposed Impact Fees so calculated

are:

Recovery Impact Level Fee

100% $104.68

75% 75.37

60% 57.80

4.2 OBSERVATIONS AND RECOMMENDATIONS

In consideration of the above findings and conclusions with respect to the IFFP and IFA, Consultant

makes the following observations and recommendations.

1. In light of the fact that current ratepayers may receive some benefit (e.g., improved reliability)

from the proposed construction projects outlined in the IFFP, we believe it would be

appropriate for the HLP Board to consider setting the Impact Fee at a level that reflects

something less than 100 percent recovery from new development. That is, there should be

some level of sharing between current electric customers and new development customers that

will be added to the system over the next five years.

2. When setting the base Impact Fee, the HLP Board should also consider the economic

development goals of Heber City and Wasatch County in general. That is, the charges

produced by the Impact Fee should not hinder the broadening of the economic base in the

Heber Valley area.

3. HLP’s current base Impact Fee of $41.40 produces charges that are well below several other

municipal electric utilities in Utah and, if left unchanged, would produce recovery level of

roughly 40 percent of the cost of new development projects outlined in the IFFP.

4. In consideration of the foregoing, Consultant recommends that HLP Board adopt an Impact

Fee that will produce at least a 60 percent recovery level ($57.80) which is based on the HLP

staff recommendation.



Respectfully Submitted:

R.E. PENDER, INC.

Robert E. Pender, President

APPENDICES

APPENDIX A

UTAH STATUTE U.C.A. 1953 § 11-36A-102

West's Utah Code Annotated CurrentnessTitle 11. Cities, Counties, and Local Taxing Units

Chapter 36A. Impact Fees ActPart 1. General Provisions

§ 11-36a-102. Definitions

As used in this chapter:

(1)(a) “Affected entity” means each county, municipality, local district under Title 17B, Limited Purpose LocalGovernment Entities--Local Districts, special service district under Title 17D, Chapter 1, Special Service Dis-trict Act, school district, interlocal cooperation entity established under Chapter 13, Interlocal Cooperation Act,and specified public utility:

(i) whose services or facilities are likely to require expansion or significant modification because of the fa-cilities proposed in the proposed impact fee facilities plan; or

(ii) that has filed with the local political subdivision or private entity a copy of the general or long-rangeplan of the county, municipality, local district, special service district, school district, interlocal cooperationentity, or specified public utility.

(b) “Affected entity” does not include the local political subdivision or private entity that is required underSection 11-36a-501 to provide notice.

(2) “Charter school” includes:

(a) an operating charter school;

(b) an applicant for a charter school whose application has been approved by a chartering entity as provided inTitle 53A, Chapter 1a, Part 5, The Utah Charter Schools Act; and

(c) an entity that is working on behalf of a charter school or approved charter applicant to develop or constructa charter school building.

(3) “Development activity” means any construction or expansion of a building, structure, or use, any change inuse of a building or structure, or any changes in the use of land that creates additional demand and need for pub-

U.C.A. 1953 § 11-36a-102 Page 1

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lic facilities.

(4) “Development approval” means:

(a) except as provided in Subsection (4)(b), any written authorization from a local political subdivision thatauthorizes the commencement of development activity;

(b) development activity, for a public entity that may develop without written authorization from a local polit-ical subdivision;

(c) a written authorization from a public water supplier, as defined in Section 73-1-4, or a private water com-pany:

(i) to reserve or provide:

(A) a water right;

(B) a system capacity; or

(C) a distribution facility; or

(ii) to deliver for a development activity:

(A) culinary water; or

(B) irrigation water; or

(d) a written authorization from a sanitary sewer authority, as defined in Section 10-9a-103:

(i) to reserve or provide:

(A) sewer collection capacity; or

(B) treatment capacity; or

(ii) to provide sewer service for a development activity.

U.C.A. 1953 § 11-36a-102 Page 2


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(5) “Enactment” means:

(a) a municipal ordinance, for a municipality;

(b) a county ordinance, for a county; and

(c) a governing board resolution, for a local district, special service district, or private entity.

(6) “Encumber” means:

(a) a pledge to retire a debt; or

(b) an allocation to a current purchase order or contract.

(7) “Hookup fee” means a fee for the installation and inspection of any pipe, line, meter, or appurtenance to con-nect to a gas, water, sewer, storm water, power, or other utility system of a municipality, county, local district,special service district, or private entity.

(8)(a) “Impact fee” means a payment of money imposed upon new development activity as a condition of devel-opment approval to mitigate the impact of the new development on public infrastructure.

(b) “Impact fee” does not mean a tax, a special assessment, a building permit fee, a hookup fee, a fee forproject improvements, or other reasonable permit or application fee.

(9) “Impact fee analysis” means the written analysis of each impact fee required by Section 11-36a-303.

(10) “Impact fee facilities plan” means the plan required by Section 11-36a-301.

(11)(a) “Local political subdivision” means a county, a municipality, a local district under Title 17B, LimitedPurpose Local Government Entities--Local Districts, or a special service district under Title 17D, Chapter 1,Special Service District Act.

(b) “Local political subdivision” does not mean a school district, whose impact fee activity is governed bySection 53A-20-100. 5.

(12) “Private entity” means an entity with private ownership that provides culinary water that is required to beused as a condition of development.

U.C.A. 1953 § 11-36a-102 Page 3




(13)(a) “Project improvements” means site improvements and facilities that are:

(i) planned and designed to provide service for development resulting from a development activity;

(ii) necessary for the use and convenience of the occupants or users of development resulting from a devel-opment activity; and

(iii) not identified or reimbursed as a system improvement.

(b) “Project improvements” does not mean system improvements.

(14) “Proportionate share” means the cost of public facility improvements that are roughly proportionate andreasonably related to the service demands and needs of any development activity.

(15) “Public facilities” means only the following impact fee facilities that have a life expectancy of 10 or moreyears and are owned or operated by or on behalf of a local political subdivision or private entity:

(a) water rights and water supply, treatment, and distribution facilities;

(b) wastewater collection and treatment facilities;

(c) storm water, drainage, and flood control facilities;

(d) municipal power facilities;

(e) roadway facilities;

(f) parks, recreation facilities, open space, and trails;

(g) public safety facilities; or

(h) environmental mitigation as provided in Section 11-36a-205.

(16)(a) “Public safety facility” means:

(i) a building constructed or leased to house police, fire, or other public safety entities; or

U.C.A. 1953 § 11-36a-102 Page 4



(ii) a fire suppression vehicle costing in excess of $500,000.

(b) “Public safety facility” does not mean a jail, prison, or other place of involuntary incarceration.

(17)(a) “Roadway facilities” means a street or road that has been designated on an officially adopted subdivisionplat, roadway plan, or general plan of a political subdivision, together with all necessary appurtenances.

(b) “Roadway facilities” includes associated improvements to a federal or state roadway only when the associ-ated improvements:

(i) are necessitated by the new development; and

(ii) are not funded by the state or federal government.

(c) “Roadway facilities” does not mean federal or state roadways.

(18)(a) “Service area” means a geographic area designated by a local political subdivision on the basis of soundplanning or engineering principles in which a defined set of public facilities provides service within the area.

(b) “Service area” may include the entire local political subdivision.

(19) “Specified public agency” means:

(a) the state;

(b) a school district; or

(c) a charter school.

(20)(a) “System improvements” means:

(i) existing public facilities that are:

(A) identified in the impact fee analysis under Section 11-36a-304; and

(B) designed to provide services to service areas within the community at large; and

U.C.A. 1953 § 11-36a-102 Page 5



(ii) future public facilities identified in the impact fee analysis under Section 11-36a-304 that are intended toprovide services to service areas within the community at large.

(b) “System improvements” does not mean project improvements.

CREDIT(S)

U.C.A. 1953 § 11-36a-102, UT ST § 11-36a-102

Current through 2011 Third Special Session.

(C) 2012 Thomson Reuters. No Claim to Orig. US Gov. Works.

END OF DOCUMENT

U.C.A. 1953 § 11-36a-102 Page 6




Chapter 36A. Impact Fees ActPart 3. Establishing an Impact Fee

§ 11-36a-301. Impact fee facilities plan

(1) Before imposing an impact fee, each local political subdivision or private entity shall, except as provided inSubsection (3), prepare an impact fee facilities plan to determine the public facilities required to serve develop-ment resulting from new development activity.

(2) A municipality or county need not prepare a separate impact fee facilities plan if the general plan required bySection 10-9a-401 or 17-27a-401, respectively, contains the elements required by Section 11-36a-302.

(3)(a) A local political subdivision with a population, or serving a population, of less than 5,000 as of the lastfederal census need not comply with the impact fee facilities plan requirements of this part, but shall ensure that:

(i) the impact fees that the local political subdivision imposes are based upon a reasonable plan; and

(ii) each applicable notice required by this chapter is given.

(b) Subsection (3)(a) does not apply to a private entity.

CREDIT(S)

U.C.A. 1953 § 11-36a-301, UT ST § 11-36a-301



END OF DOCUMENT

U.C.A. 1953 § 11-36a-301 Page 1



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§ 11-36a-302. Impact fee facilities plan requirements--Limitations--School district or charterschool

(1) An impact fee facilities plan shall identify:

(a) demands placed upon existing public facilities by new development activity; and

(b) the proposed means by which the local political subdivision will meet those demands.

(2) In preparing an impact fee facilities plan, each local political subdivision shall generally consider all revenuesources, including impact fees and anticipated dedication of system improvements, to finance the impacts onsystem improvements.

(3) A local political subdivision or private entity may only impose impact fees on development activities whenthe local political subdivision's or private entity's plan for financing system improvements establishes that im-pact fees are necessary to achieve an equitable allocation to the costs borne in the past and to be borne in the fu-ture, in comparison to the benefits already received and yet to be received.

(4)(a) Subject to Subsection (4)(c), the impact fee facilities plan shall include a public facility for which an im-pact fee may be charged or required for a school district or charter school if the local political subdivision isaware of the planned location of the school district facility or charter school:

(i) through the planning process; or

(ii) after receiving a written request from a school district or charter school that the public facility be in-cluded in the impact fee facilities plan.

(b) If necessary, a local political subdivision or private entity shall amend the impact fee facilities plan to re-flect a public facility described in Subsection (4)(a).

(c)(i) In accordance with Subsections 10-9a-305(4) and 17-27a-305(4), a local political subdivision may not

U.C.A. 1953 § 11-36a-302 Page 1




require a school district or charter school to participate in the cost of any roadway or sidewalk.

(ii) Notwithstanding Subsection (4)(c)(i), if a school district or charter school agrees to build a roadway orsidewalk, the roadway or sidewalk shall be included in the impact fee facilities plan if the local jurisdictionhas an impact fee facilities plan for roads and sidewalks.

CREDIT(S)

U.C.A. 1953 § 11-36a-302, UT ST § 11-36a-302



END OF DOCUMENT

U.C.A. 1953 § 11-36a-302 Page 2




§ 11-36a-303. Impact fee analysis

(1) Subject to the notice requirements of Section 11-36a-504, each local political subdivision or private entityintending to impose an impact fee shall prepare a written analysis of each impact fee.

(2) Each local political subdivision or private entity that prepares an impact fee analysis under Subsection (1)shall also prepare a summary of the impact fee analysis designed to be understood by a lay person.

CREDIT(S)

U.C.A. 1953 § 11-36a-303, UT ST § 11-36a-303



END OF DOCUMENT

U.C.A. 1953 § 11-36a-303 Page 1







§ 11-36a-304. Impact fee analysis requirements

(1) An impact fee analysis shall:

(a) identify the anticipated impact on or consumption of any existing capacity of a public facility by the anti-cipated development activity;

(b) identify the anticipated impact on system improvements required by the anticipated development activityto maintain the established level of service for each public facility;

(c) subject to Subsection (2), demonstrate how the anticipated impacts described in Subsections (1)(a) and (b)are reasonably related to the anticipated development activity;

(d) estimate the proportionate share of:

(i) the costs for existing capacity that will be recouped; and

(ii) the costs of impacts on system improvements that are reasonably related to the new development activ-ity; and

(e) based on the requirements of this chapter, identify how the impact fee was calculated.

(2) In analyzing whether or not the proportionate share of the costs of public facilities are reasonably related tothe new development activity, the local political subdivision or private entity, as the case may be, shall identify,if applicable:

(a) the cost of each existing public facility that has excess capacity to serve the anticipated development res-ulting from the new development activity;

(b) the cost of system improvements for each public facility;

U.C.A. 1953 § 11-36a-304 Page 1




(c) other than impact fees, the manner of financing for each public facility, such as user charges, special as-sessments, bonded indebtedness, general taxes, or federal grants;

(d) the relative extent to which development activity will contribute to financing the excess capacity of andsystem improvements for each existing public facility, by such means as user charges, special assessments, orpayment from the proceeds of general taxes;

(e) the relative extent to which development activity will contribute to the cost of existing public facilities andsystem improvements in the future;

(f) the extent to which the development activity is entitled to a credit against impact fees because the develop-ment activity will dedicate system improvements or public facilities that will offset the demand for system im-provements, inside or outside the proposed development;

(g) extraordinary costs, if any, in servicing the newly developed properties; and

(h) the time-price differential inherent in fair comparisons of amounts paid at different times.

CREDIT(S)

U.C.A. 1953 § 11-36a-304, UT ST § 11-36a-304



END OF DOCUMENT

U.C.A. 1953 § 11-36a-304 Page 2




§ 11-36a-305. Calculating impact fees

(1) In calculating an impact fee, a local political subdivision or private entity may include:

(a) the construction contract price;

(b) the cost of acquiring land, improvements, materials, and fixtures;

(c) the cost for planning, surveying, and engineering fees for services provided for and directly related to theconstruction of the system improvements; and

(d) for a political subdivision, debt service charges, if the political subdivision might use impact fees as a rev-enue stream to pay the principal and interest on bonds, notes, or other obligations issued to finance the costsof the system improvements.

(2) In calculating an impact fee, each local political subdivision or private entity shall base amounts calculatedunder Subsection (1) on realistic estimates, and the assumptions underlying those estimates shall be disclosed inthe impact fee analysis.

CREDIT(S)

U.C.A. 1953 § 11-36a-305, UT ST § 11-36a-305



END OF DOCUMENT

U.C.A. 1953 § 11-36a-305 Page 1






§ 11-36a-306. Certification of impact fee analysis

(1) An impact fee facilities plan shall include a written certification from the person or entity that prepares theimpact fee facilities plan that states the following:

“I certify that the attached impact fee facilities plan:




c. projected to be incurred or encumbered within six years after the day on which each impact fee is paid;



b. costs for qualifying public facilities that will raise the level of service for the facilities, through impactfees, above the level of service that is supported by existing residents;

c. an expense for overhead, unless the expense is calculated pursuant to a methodology that is consistentwith generally accepted cost accounting practices and the methodological standards set forth by the federalOffice of Management and Budget for federal grant reimbursement; and

3. complies in each and every relevant respect with the Impact Fees Act.”

(2) An impact fee analysis shall include a written certification from the person or entity that prepares the impactfee analysis which states as follows:

U.C.A. 1953 § 11-36a-306 Page 1




“I certify that the attached impact fee analysis:







b. costs for qualifying public facilities that will raise the level of service for the facilities, through impactfees, above the level of service that is supported by existing residents;

c. an expense for overhead, unless the expense is calculated pursuant to a methodology that is consistentwith generally accepted cost accounting practices and the methodological standards set forth by the federalOffice of Management and Budget for federal grant reimbursement;

3. offsets costs with grants or other alternate sources of payment; and

4. complies in each and every relevant respect with the Impact Fees Act.”

CREDIT(S)

U.C.A. 1953 § 11-36a-306, UT ST § 11-36a-306



END OF DOCUMENT

U.C.A. 1953 § 11-36a-306 Page 2


APPENDIX B

IMPACT FEE FACILITIES PLAN

1

Heber Light & Power Company

Impact Fee Facilities Plan

This Impact Fee Facilities Plan is intended to supplement and provide additional support

for the information found Section 2 of the Impact Fee Study Report by R.E. Pender, Inc., dated

April 2015 (“Pender Report”).

A. Background

Heber Light & Power Company is a Utah energy services interlocal entity created by

Heber City, Charleston, and Midway City. The Company provides service to more than 10,700

customers in a service area covering 120 square miles including most of the Heber Valley. The

Company owns and operates hydroelectric generators and thermal generating plants with an

overall generating capacity of 16.5 megawatts.

B. Need for System Improvements to Serve Demand From New Development

As part of its strategic planning process, the Company annually assesses historic growth

in energy sales and projects future anticipated increases in sales. Section 2 of the Pender Report

contains the Company’s projections and the assumptions on which the Company based its

projections.

In assessing what System Improvements are necessary to serve the demand from New

Development, it is important to recognize that HLP operates a single-integrated system which

must be viewed as a whole. It is not appropriate to view any component of the system in

isolation, for assessing the impact of new development on the system’s capacity. Rather, the

issue is whether the system, as a whole, has the capacity to serve the new development at HLP’s

existing level of service, not whether any isolated circuit within the system has the capacity to

serve the new development

HLP’s analysis of the system’s current load and existing capacity shows that HLP cannot

serve projected load growth without increasing the capacity of the system. Stated in other words,

the projected load growth exceeds the capacity of the facilities required to serve the load and thus

would compromise the Company’s current level of service. Therefore the system does not have

excess capacity to serve projected new load growth.

This conclusion is in part based upon the Electrical System Model Update and Analysis

date October 2011 by Intermountain Consumer Professional Engineers, Inc. (“System

Analysis”), attached hereto as Exhibit A and by the load growth projections on which the System

Analysis is based. It is worth noting that, in 2013-14, actual load growth exceeded these

2

projections. The System Analysis shows the additional facility capacity required to serve new

development at the Company’s current level of service. Although the 2011 System Analysis does

not include the analysis for the Second Point of Delivery, the Transmission System Impact Study

(“Transmission Impact Study”) dated April 2014 states the critical need to increase capacity at

the HLP Delivery Point.

The System Analysis and Transmission Impact Study identify the System Improvements

required to increase the system’s capacity to serve the load from projected new growth. These

system improvements include: (1) increasing capacity by installing additional distribution

feeders and tie circuits, (2) installing, upgrading, or reconductoring existing circuits and feeders

(3) installing additional substation breakers, and (4) installing new or upgraded substation

transformers and protective equipment (5) developing and installing all necessary equipment for

a Second Point of Delivery Substation. Examples of these types of System Improvements and

the cost of these System Improvements are summarized in Exhibit B. The Company’s cost

estimates are based on the Company’s standard method of estimating material and labor costs for

its projects. The Company intends to use impact fees to fund a portion of the cost of these types

of System Improvements; however the specific projects may vary depending on (1) the needs of

the system at the time that the funds are available or (2) the portions of the system most impacted

by new development.

C. Revenue Sources to Fund New System Improvements for Load Growth

HLP funds system improvements through (1) electric power revenues, (2) bonds, and (3)

impact fees. Electric power revenues, in part, cover debt service and system improvements.

Impact fees are used strictly to pay for system improvements for new load growth. Developers

ordinarily pay the costs of project specific improvements and do not pay for or provide system-

wide improvements. HLP has received small grants for street light refitting and emergency

planning but grants do not play a role in HLP’s capital plan. HLP does not receive interfund

transfers or loans from its members.

D. New Customers Future Contributions to System Improvements through Rates

The Company has no existing excess capacity to serve new customers and therefore the

revenue from the proposed Impact Fee does not fund excess capacity through existing System

Improvements. As to existing System Improvements funded through debt, new and existing

customers share equally this debt burden through future rates. These System Improvements

benefit all customers because the Company’s system is an integrated system. In addition, the

Company only recovers, through impact fees, a portion of the cost of the System Improvements

for projected future growth. Thus, existing customers as well as new customers pay for a portion

of these improvements for new development through electric rates.

I certify that the attached impact fee facilities plan:

1. Includes only the costs of public facilities that are:




2. Does not include:

3.


b. costs for qualifying public facilities that will raise the level of service for the facilities, through impact fees, above the level of service that is

supported by existing residents;

c. an expense for overhead, unless the expense is calculated pursuant to a

methodology that is consistent with generally accepted cost accounting practices and the methodological standards set forth by the federal Office of Management and Budget for federal grant reimbursement; and

General Manager Heber Light & Power

3

kschindler

Typewritten Text

EXHIBIT A

kschindler

Typewritten Text

4

Exhibit B

Impact Fee Projected Cost ($1,000)

Upcoming Projects Related % Start Finish Total Impact Fee

Distribution

Distribution Capacitors / VAR Control 0% 2015 2018 $80 $0

CL 401 Rebuild (Charleston Reconductor) 60% 2015 2018 $450 $270

Additional Circuits out of Jailhouse to the East 100% 2015 2018 $560 $560

Underground System Improvements 0% 2015 2019 $194 $0

Tie from 702 up to 500 East in Heber (HB304) 100% 2016 2016 $250 $250

Heber Sub to Cloyes Sub Distribution Rebuild 60% 2016 2017 $350 $210

North Distribution Line Rebuild (RMP Partnership - Phase 2) 0% 2016 2017 $1,240 $0

Heber Substation 2 Additional Circuits (South & West) 100% 2016 2018 $360 $360

Reconductor Center Street to 1200 South 60% 2019 2019 $150 $90

Reconductor Pine Canyon Road - Midway 60% 2019 2019 $180 $108

Substation

Gas Plant 2 Transformer Replacement 0% 2014 2015 $223 $0

Replacement Recloser for Joslyn Reclosers 0% 2015 2015 $25 $0

Heber Substation 2nd Transformer 100% 2015 2016 $615 $615

2nd Point of Interconnect Substation 50% 2015 2017 $5,500 $2,750

Midway Substation - High Side Rebuild 0% 2018 2018 $500 $0

Cloyes LTC Rebuild 0% 2019 2019 $40 $0

Generation

Lower Snake Creek Plant Upgrade 0% 2015 2016 $240 $0

Annual Generation Capital Improvements 0% 2015 2019 $271 $0

Unit Overhauls 0% 2015 2019 $556 $0

New Generator (3-6 MW) 0% 2019 2020 $9,000 $0

Systems & Technology

Annual Systems and Technology Upgrade 0% 2015 2019 $322 $0

Tools & Equipment

Annual Tool & Equipment Purchases 0% 2015 2019 $225 $0

Vehicle

Annual Vehicle Program 0% 2015 2019 $750 $0

Buildings

Operations Asphalt / Curb Improvements 0% 2015 2015 $103 $0

Generator Fire Suppression System 0% 2015 2015 $107 $0

Training Room Furniture 0% 2015 2015 $32 $0

Land Swap Residual Purchase 0% 2015 2015 $145 $0

New Office Building 0% 2018 2018 $1,000 $0

$23,388 $5,213

Project Duration

APPENDIX C

2006 IMPACT FEE CALCULATION

WORKSHEET (READOPTED BY THE HLP BOARD

ON SEPTEMBER 25, 2013)

An Electrical Service Impact Fee is required for all new and expanded electrical services

Calculate or enter service size: = input data

Amperage: 100.00 Main breaker size or differential current for upgrades

Voltage (in volts): 240 [Differential current = New breaker size - Old breaker size]

Single (1) or three (3) phase: 1.00

New kVA/KW Service: 24.00

Calculate Impact Fee:

Estimated Non-diversified Demand With Utilization: 3.60

Impact Fee (Est Demand x Diversified Base Fee): $993.60

Impact Fee Base = $425.00 Per kVA of system capacity

Diversity Factor = 65% Non-coincidental Peak vs. System Peak Demand

Diversified Base Fee = $276.00 Per kVA of Estimated Diversified Capacity (Rounded from $276.25)

Utilization Factor = 15% Actual Demand vs. Installed Service Capacity

(Multiplier applied to requested service size.)

Applied Fee = $41.40

Impact Fee Table:

120/240 120/208 277/4801 PHASE 3 PHASE 3 PHASE

$99 $149 $344

$199 $298 $688

$298 $447 $1,033

$397 $597 $1,377

$497 $746 $1,721

$596 $895 $2,065

$696 $1,044 $2,409

$795 $1,193 $2,754

$894 $1,342 $3,098

$994 $1,492 $3,442

$1,242 $1,864 $4,302

$1,490 $2,237 $5,163

$1,739 $2,610 $6,023

$1,987 $2,983 $6,884

$2,981 $4,475 $10,326

$3,974 $5,966 $13,768

$4,968 $7,458 $17,210

$5,962 $8,949 $20,652

$6,955 $10,441 $24,094

$7,949 $11,932 $27,535

$8,942 $13,424 $30,977

$9,936 $14,915 $34,419

$16,407 $37,861

$17,898 $41,303

$19,390 $44,745

$20,881 $48,187

$22,373 $51,629

$23,864 $55,071

$25,356 $58,513

$26,847 $61,955

$28,339 $65,397

$29,830 $68,839

$37,288 $86,048

$44,745 $103,258

2000

2500

3000

VOLTAGE

1600

1700

1800

1900

1200

1300

1400

1500

800

900

1000

1100

700

EQUAL TO]

500

600

70

80

90

175

50

60

200

300

400

REQUESTED

SERVICE SIZE

[AMPERAGE

100

125

150

10

20

30

40

HEBER LIGHT & POWER

LESS THAN OR

Per kVA of customer requested service increase. Single phase

KVA is based on main breaker ampere size x normal line-to-line

voltage; ie 100a x 240v = 24kVA; Three phase KVA requires a

multiplier of 1.732

2006 IMPACT FEE CALCULATION WORKSHEETMay 2006

The impact fee for all new or expanded electrical services shall be in accordance with the following worksheet. New services are based on

panel breaker size and voltage rating; expanded services are based on the differential current (new minus the existing main breaker size and

the voltage rating. The intent is to use the resultant kVA capacity increase as a measure of system impact.

HLP-10 Year Plan Impact Fees Study, May 2006

2006 Impact Fee Worksheet.15% Large Comm.060508; Impact Fee Calc $425,15%Electric Power Engineering Associates - All Rights Reserved

Printed: 1/29/2013

EXHIBITS

EXHIBIT 1

ANALYSIS OF FORECASTED

CUSTOMER & LOAD DATA

Exhibit 1

Page 1 of 5

Annual

Line Actual Forecast Increase Forecast Increase Growth %

No. 2014 2019 2014-19 2034 2014-34 2014-34

(a) (b) (c) (d) (e) (f)

1 Coincident Peak Demand kW 35,573.0 39,275.0 3,702.0 51,599.5 16,026.5 1.88%

2 System Energy MWh 165,003.2 182,176.8 17,173.7 239,347.1 74,343.9 1.88%

3 System Load Factor % 53.0% 53.0% 53.0%

Non-Coincident Peak Demand

4 At Meter kW 39,865.7 44,531.6 4,665.9 58,711.4 18,845.7 1.95%

5 At Input to Distribution System kW 42,720.2 47,275.9 4,555.7 62,410.0 19,689.7 1.91%

6 System Coincidence Factor % 83.3% 83.1% 82.7%

7 Number of Customers (Avg.) # 10,713 12,004 1,291.0 15,919 5,206 2.00%

Note: Amounts shown include load associated with security lighting.

Description

Analysis of Forecasted Customer and Load DataSummary

2015 Impact Fee AnalysisHeber Light & Power

2015_Impact Fee Analysis_Final (4-9-15) 4/15/2015 eA XA cxÇwxÜ? \ÇvA

EXHIBIT 1

Page 2 of 5

Heber Light & Power

2015 Impact Fee Study

Analysis of Forecasted Customer & Load Data

Line Actual 1 2 3 4 5 6 7 8 9 10 11

No. Description 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

1 System Coincident Peak Demand [1] kW 35,573.0 36,284.0 37,010.0 37,750.0 38,505.0 39,275.0 40,060.0 40,862.0 41,679.0 42,512.0 43,363.0 44,230.0

2 Total System Load (Input to Distribution System) [1]MWh 165,003.2 168,303.2 171,669.3 175,102.7 178,604.7 182,176.8 185,820.4 189,536.8 193,327.5 197,194.1 201,137.9 205,160.7

3 System Load Factor % 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0%

Energy Sales at Meter [2]

4 Residential MWh 80,631.8 82,539.8 84,517.2 86,494.6 88,472.0 90,449.5 92,426.9 94,404.3 96,381.7 98,359.1 100,336.5 102,314.0

5 Commecial MWh 69,889.0 71,321.8 72,913.8 74,505.8 76,097.8 77,689.8 79,281.8 80,873.8 82,465.9 84,057.9 85,649.9 87,241.9

6 Yard / Security Lights MWh 43.4 43.4 44.7 46.0 47.3 48.7 50.0 51.3 52.6 53.9 55.2 56.6

7 Total MWh 150,564.2 153,905.0 157,475.7 161,046.5 164,617.2 168,188.0 171,758.7 175,329.4 178,900.2 182,470.9 186,041.6 189,612.4

Other Energy Usage

8 Donated Street Lights MWh 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5

9 CUWCD MWh 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1

10 Total MWh 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6

11 Total Energy Consumption MWh 153,977.8 157,318.6 160,889.4 164,460.1 168,030.8 171,601.6 175,172.3 178,743.0 182,313.8 185,884.5 189,455.2 193,026.0

12 System Energy Loss Factor % 6.68% 6.53% 6.28% 6.08% 5.92% 5.80% 5.73% 5.69% 5.70% 5.74% 5.81% 5.91%

Estimated Average No. of Customers [3]

13 Residential # 9,297 9,517 9,745 9,973 10,201 10,429 10,657 10,885 11,113 11,341 11,569 11,797

14 Commecial # 1,317 1,344 1,374 1,404 1,434 1,464 1,494 1,524 1,554 1,584 1,614 1,644

15 Yard / Security Lights # 99 99 102 105 108 111 114 117 120 123 126 129

16 Total # 10,713 10,960 11,221 11,482 11,743 12,004 12,265 12,526 12,787 13,048 13,309 13,570

Average Annual Usage Per Customer

17 Residential kWh/Cust. 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9

18 Commecial kWh/Cust. 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8

19 Yard / Security Lights kWh/Cust. 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4

20 Total kWh/Cust. 14,054.3 14,042.4 14,034.0 14,026.0 14,018.3 14,011.0 14,004.0 13,997.2 13,990.8 13,984.6 13,978.6 13,972.9

Estimated NCP Demand at Meter

21 Residential kW 21,306.8 21,811.0 22,333.5 22,856.1 23,378.6 23,901.1 24,423.6 24,946.2 25,468.7 25,991.2 26,513.8 27,036.3

22 Commecial kW 18,553.9 18,934.3 19,357.0 19,779.6 20,202.2 20,624.9 21,047.5 21,470.2 21,892.8 22,315.5 22,738.1 23,160.7

23 Street Lights kW 5.0 5.0 5.1 5.3 5.4 5.6 5.7 5.9 6.0 6.2 6.3 6.5

24 Total kW 39,865.7 40,750.3 41,695.6 42,640.9 43,586.2 44,531.6 45,476.9 46,422.2 47,367.5 48,312.8 49,258.2 50,203.5

25 System Coincidence Factor % 83.3% 83.2% 83.2% 83.1% 83.1% 83.1% 83.0% 83.0% 83.0% 82.9% 82.9% 82.9%

Average NCP Per Customer [4]

26 Residential kW/Cust. 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3

27 Commecial kW/Cust. 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1

28 Street Lights kW/Cust. 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

29 Total kW/Cust. 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7

Forecast Period

2015_Impact Fee Analysis_Final (4-9-15) 2


EXHIBIT 1

Page 3 of 5

Heber Light & Power



Line Actual 1 2 3 4 5 6 7 8 9 10 11

No. Description 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Forecast Period

Projected Avg. Number of Customers Added Per Year

30 Residential [5] 2.0% 220 228 228 228 228 228 228 228 228 228 228

31 Commercial 2.0% 28 30 30 30 30 30 30 30 30 30 30

32 Street Lights 2.0% 2 3 3 3 3 3 3 3 3 3 3

Estimated Increase in Average Usage Per Customer

33 Residential 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

34 Commercial 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

35 Street Lights 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Estimated NCP Load Factor

36 Residential 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20%

37 Commercial 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00%

38 Street Lights 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%

[1] 2015 - 2025 based on forecast provided by HLP. 2026 - 2034 modeled based on growth rate for years 2015 - 2025.

[2] Based on average number of customers and usage per customer.

[3] Based on assumed annual customer additions (lines 30 - 32).

[4] Annual NCP Demand based on kWh sales at meter, assumed NCP load factor and indicated loss factor.

[5] Customer growth assumed to be approximately 2.0 percent over the forecast period.



EXHIBIT 1

Page 4 of 5

Line

No. Description

1 System Coincident Peak Demand [1] kW

2 Total System Load (Input to Distribution System) [1]MWh

3 System Load Factor %

Energy Sales at Meter [2]

4 Residential MWh

5 Commecial MWh

6 Yard / Security Lights MWh

7 Total MWh

Other Energy Usage

8 Donated Street Lights MWh

9 CUWCD MWh

10 Total MWh

11 Total Energy Consumption MWh

12 System Energy Loss Factor %

Estimated Average No. of Customers [3]

13 Residential #

14 Commecial #

15 Yard / Security Lights #

16 Total #

Average Annual Usage Per Customer

17 Residential kWh/Cust.

18 Commecial kWh/Cust.

19 Yard / Security Lights kWh/Cust.

20 Total kWh/Cust.

Estimated NCP Demand at Meter

21 Residential kW

22 Commecial kW

23 Street Lights kW

24 Total kW

25 System Coincidence Factor %

Average NCP Per Customer [4]

26 Residential kW/Cust.

27 Commecial kW/Cust.

28 Street Lights kW/Cust.

29 Total kW/Cust.

Heber Light & Power



2014-34

12 13 14 15 16 17 18 19 20 Growth

2026 2027 2028 2029 2030 2031 2032 2033 2034 Rate

45,053.2 45,871.5 46,689.8 47,508.1 48,326.4 49,144.7 49,963.0 50,781.2 51,599.5 1.88%

208,981.7 212,777.3 216,573.0 220,368.7 224,164.4 227,960.1 231,755.7 235,551.4 239,347.1 1.88%

53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0% 53.0%

104,291.4 106,268.8 108,246.2 110,223.6 112,201.0 114,178.5 116,155.9 118,133.3 120,110.7 2.01%

88,833.9 90,425.9 92,017.9 93,609.9 95,201.9 96,793.9 98,385.9 99,977.9 101,569.9 1.89%

57.9 59.2 60.5 61.8 63.1 64.4 65.8 67.1 68.4 2.30%

193,183.1 196,753.8 200,324.6 203,895.3 207,466.1 211,036.8 214,607.5 218,178.3 221,749.0 1.95%

962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 962.5 0.00%

2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 2,451.1 0.00%

3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 3,413.6 0.00%

196,596.7 200,167.5 203,738.2 207,308.9 210,879.7 214,450.4 218,021.1 221,591.9 225,162.6 1.92%

5.93% 5.93% 5.93% 5.93% 5.93% 5.93% 5.93% 5.93% 5.93%

12,025 12,253 12,481 12,709 12,937 13,165 13,393 13,621 13,849 2.01%

1,674 1,704 1,734 1,764 1,794 1,824 1,854 1,884 1,914 1.89%

132 135 138 141 144 147 150 153 156 2.30%

13,831 14,092 14,353 14,614 14,875 15,136 15,397 15,658 15,919 2.00%

8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 8,672.9 0.00%

53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 53,066.8 0.00%

438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 438.4 0.00%

13,967.4 13,962.1 13,957.0 13,952.1 13,947.3 13,942.7 13,938.3 13,934.0 13,929.8 -0.04%

27,558.8 28,081.3 28,603.9 29,126.4 29,648.9 30,171.5 30,694.0 31,216.5 31,739.0 2.01%

23,583.4 24,006.0 24,428.7 24,851.3 25,273.9 25,696.6 26,119.2 26,541.9 26,964.5 1.89%

6.6 6.8 6.9 7.1 7.2 7.4 7.5 7.7 7.8 2.30%

51,148.8 52,094.1 53,039.4 53,984.8 54,930.1 55,875.4 56,820.7 57,766.0 58,711.4 1.95%

82.9% 82.8% 82.8% 82.8% 82.8% 82.7% 82.7% 82.7% 82.7%

2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3

14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1

0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7

Forecast Period



EXHIBIT 1

Page 5 of 5

Line

No. Description

Projected Avg. Number of Customers Added Per Year

30 Residential [5]

31 Commercial

32 Street Lights

Estimated Increase in Average Usage Per Customer

33 Residential

34 Commercial

35 Street Lights

Estimated NCP Load Factor

36 Residential

37 Commercial

38 Street Lights

Heber Light & Power



2014-34

12 13 14 15 16 17 18 19 20 Growth

2026 2027 2028 2029 2030 2031 2032 2033 2034 Rate

Forecast Period

228 228 228 228 228 228 228 228 228

30 30 30 30 30 30 30 30 30

3 3 3 3 3 3 3 3 3

0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20% 43.20%

43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00% 43.00%

100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%



EXHIBIT 2

IMPACT FEE PROJECTS AND COSTS

EXHIBIT 2

Page 1 of 1

Estimated Percent

Total Related to

Line Project New

No. Cost [1] Development 100% 75% 60%

(a) (b) (c) (d) (e)

2015

1 Reconductor Distribution Circuit 450,000$ 60.00% 270,000$ 202,500$ 162,000$

2 Additional Distribution Circuits 560,000 100.00% 560,000 420,000 336,000

3 Additional Substation Transformer 615,000 100.00% 615,000 461,250 369,000

4 Sub-total 2015 1,625,000 1,445,000 1,083,750 867,000

2016

5 New Distribution Tie Line 250,000 100.00% 250,000 187,500 150,000

6 Distribution Line Rebuild 350,000 60.00% 210,000 157,500 126,000

7 Two Additional Substation Circuits 360,000 100.00% 360,000 270,000 216,000

8 Sub-total 2016 960,000 820,000 615,000 492,000

2017

9 New Interconnection Substation 5,500,000 50.00% 2,750,000 2,062,500 1,650,000

2019

10 Reconductoring Projects (2) 330,000 60.00% 198,000 148,500 118,800

11 Total All Projects to be Recovered through Impact Fees 8,415,000 5,213,000 3,909,750 3,127,800

12 Less: Projects to be Financed through Bond Issue 5,500,000 2,750,000 2,062,500 1,650,000

13 Projects Funded Directly from Impact Fees 2,915,000 2,463,000 1,847,250 1,477,800

14 Less: Net Revenue (Deficit) Balance of Impact Fee Fund 389,828 100.00% 389,828 389,828 389,828

15 Net Balance of Project Funded Directly from Impact Fees 2,525,172$ 2,073,172$ 1,457,422$ 1,087,972$

[1] Per the HLP Capital Improvement Plan.

Denotes Staff Recommendation.

Heber Light & Power

2015 Impact Fee Analysis

Impact Fee Projects / Costs

Impact Fee Project Costs

at Various Recovery LevelsDescription of System Improvements

Related to New Development and Start Date

2015_Impact Fee Analysis_Final (4-9-15) eA XA cxÇwxÜ? \ÇvA

EXHIBIT 3

CALCULATION OF PROPOSED

BASE IMPACT FEE

Exhibit 3

Page 1 of 4

5-year 20-Year

Recovery Recovery

Line Period Period

No. 2015-2019 2015-2034 Totals

(a) (b) (c)

Growth-related Project Cost [1]

1 Direct Recovery Projects $ 2,073,172 - 2,073,172

2 Bonded Projects [2] $ - 4,776,369 4,776,369

3 Total $ 2,073,172 4,776,369 6,849,541

Assumed Impact Fee Recovery Levels

4 100% $ 2,073,172 4,776,369 6,849,541

5 75% $ 1,457,422 3,581,012 5,038,434

6 60% $ 1,087,972 2,866,159 3,954,130

Increase in NCP Demand at Meter [3]

7 Residential kW 2,594.3 10,432.2

8 Commecial kW 2,070.9 8,410.6

9 Total kW 4,665.3 18,842.8

Base Impact Fee at Various Recovery Levels

10 100% $/kW 444.39 253.49 697.87

11 75% $/kW 312.40 190.05 502.45

12 60% $/kW 233.21 152.11 385.32

Impact Fee at 15% Panel Utilization [4]

13 100% $/kVA 66.66 38.02 104.68

14 75% $/kVA 46.86 28.51 75.37

15 60% (Staff Recommendation) $/kVA 34.98 22.82 57.80

[1] Based on HLP's Five-Year Major Project Forecast for System Improvements.

[2] Bonded Projects (i.e., 2nd interconnection with RMP) assumed to be financed with 25-year bond

issue -- see attached analyses.

[3] See attached Analysis of Forecasted Load and Customer Data.

[4] Utilization factor based on 2005 Impact Fee Study.

Description

Heber Light & Power


Impact Fee Cost Analysis

(Includes Bonded Projects)


EXHIBIT 3

Page 2 of 4

1 Total Project Costs (Impact Fee Portion) 2,750,000$

2 Add: Debt Issuance Costs (3.0%) 82,500

3 Total Debt Issue 2,832,500

4 Recovery Level 100%

5 Total Principal Recovery 2,832,500$

6 Principal 2,833,000$

7 Term 25

8 Interest Rate 4.50%

1 2 3 4 5 6 7 8 9 10

Debt Service - Years 1-10

9 Interest Payment 1,129,389$ 127,485$ 124,624$ 121,635$ 118,511$ 115,247$ 111,835$ 108,270$ 104,545$ 100,652$ 96,584$

10 Principal Payment 781,159 63,570 66,430 69,420 72,544 75,808 79,219 82,784 86,510 90,403 94,471

11 Total 1,910,548$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$

11 12 13 14 15 16 17 18 19 20


12 Interest Payment 697,432$ 92,333$ 87,890$ 83,248$ 78,397$ 73,327$ 68,029$ 62,493$ 56,708$ 50,662$ 44,345$

13 Principal Payment 1,213,115 98,722 103,164 107,807 112,658 117,728 123,025 128,562 134,347 140,392 146,710

14 Total 1,910,548$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$

21 22 23 24 25


15 Interest Payment 116,548$ 37,743$ 30,844$ 23,634$ 16,100$ 8,227$

16 Principal Payment 838,726 153,312 160,211 167,421 174,955 182,828

17 Total 955,274$ 191,055$ 191,055$ 191,055$ 191,055$ 191,055$

Total Debt Service

18 Interest Payment 1,943,369$

19 Principal Payment 2,833,000

20 Total 4,776,369$

Heber Light & Power



Estimated Debt Service Requirements

100% Recovery


EXHIBIT 3

Page 3 of 4

Heber Light & Power










7 Term 25


1 2 3 4 5 6 7 8 9 10




11 Total 1,432,405$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$

11 12 13 14 15 16 17 18 19 20




14 Total 1,432,405$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$

21 22 23 24 25




17 Total 716,202$ 143,240$ 143,240$ 143,240$ 143,240$ 143,240$

Total Debt Service



20 Total 3,581,012$

75% Recovery


EXHIBIT 3

Page 4 of 4

Heber Light & Power










7 Term 25


1 2 3 4 5 6 7 8 9 10




11 Total 1,146,463$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$

11 12 13 14 15 16 17 18 19 20




14 Total 1,146,463$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$

21 22 23 24 25




17 Total 573,232$ 114,646$ 114,646$ 114,646$ 114,646$ 114,646$

Total Debt Service



20 Total 2,866,159$

60% Recovery


EXHIBIT 4

SUMMARY OF CHARGES

CURRENT AND PROPOSED IMPACT FEES

EXHIBIT 4

Page 1 of 1

Current

Line Impact 100% 75% 60%

No. Fee Recovery Recovery Recovery

(a) (b) (c) (d)

1 Impact Fees ($ per kVa) 41.40$ 104.68$ 75.37$ 57.80$

Impact Fee Charge for Applicable Panel Size

Residential (120/240, 1 phase)

2 100 Amp 994 2,512 1,809 1,387

3 200 Amp 1,987 5,025 3,618 2,774

4 400 Amp 3,974 10,049 7,235 5,549

Commercial (120/208, 3 phase)

5 100 Amp 1,492 3,771 2,715 2,082

6 200 Amp 2,983 7,542 5,430 4,164

7 400 Amp 5,966 15,085 10,861 8,329


8 2000 Amp 29,830 75,426 54,304 41,645

9 3000 Amp 44,745 113,139 81,456 62,467


10 1000 Amp 34,419 87,027 62,657 48,050

11 2000 Amp 68,839 174,055 125,314 96,101

12 3000 Amp 103,258 261,082 187,971 144,151

Denotes Staff recommendation.

Description / Panel Rating

Heber Light & Power2015 Impact Fee Study

Summary of Charges For Residential & Commercial CustomersCurrent and Proposed Impact Fee Levels

Proposed Impact Fee


Documents

Summary of Impact Fee Study Report by Purpose of … · Impact fees are used to fund capital-related costs (e ... Impact Fee Charges ... A disadvantage of the inductive method is