Download - psc.ky.govpsc.ky.gov/PSCSCF/2011 cases/2011-00163/20110822... · COMMONWEALTH OF KENTUCKY IN THE MATTER OF: e'"-71 3 L BEFORE THE PUBLIC SERVICE COMMISSION AlJG I9 2011 PUBLIC SERVICE

COMMONWEALTH OF KENTUCKY

IN THE MATTER OF:

e'"-71 3 L

BEFORE THE PUBLIC SERVICE COMMISSION AlJG I 9 2011

PUBLIC SERVICE COMMISSION

TAYLOR COUNTY RURAL ELECTRIC ) C 00 P E RATIVE C 0 RP 0 RAT1 0 N FOR CERTIFICATE OF PUBLIC ) 2011-00163 CONVENIENCE AND NECESSITY )

) CASENO.

NOTICE OF COMPLIANCE

Applicant, Taylor County Rural Electric Cooperative Corporation, by counsel,

hereby gives Notice of its compliance with the Commission's Order entered herein on

August 8, 201 1 , by filing an original and seven (7) copies of the documents, including

three (3) copies of maps which are a part of the long-range plan, and information

required by the subject Order.

f4 DATED this /? day of August, 2011

SPRAGENS & HIGDON, P.S.C. Attorneys at Law 15 Court Square - P. 0. Box 681 Lebanon, (270) 692-3141 Telephone: (270) 692-3141

B

AUG 1 9 2012

PUBLIC) SERVICE COMMiSSlON

TAYLOR COUNTY RURAL ELECTRIC COOPERATIVE CORPORATION P 0 BOX 100

CAMPRELLSVILLE, KY 4271 9

RESPONSE TO INFORMATION REQUEST BY ORDER OF THE KENTUCKY PUBLIC SERVICE COMMISSION

DATED ATJGUST 8,201 1 CASE NO. 201 1-00163

ITEM I

TAYLOR COUNTY RECC P 0 BOX 100 CAMPBELLSVILLE KY 4271 9

RESPONSE TO PSC ORDER IN CASE NO 201 1-001 63

ITEM 1

Copies of 2011 Long Range System Study are provided.

Witness available: Mike Skaggs

TAYLOR COUNTY RIJRAL, ELECTRIC COOPERATIVE CORPORATION

KENTUCKY 23 TAYLOR CAMPBEL,LSVILLE, KENTUCKY

201 1 LONG RANGE SYSTEM STUDY

February 2011

Prepared by:

Patterson & Dcwar Enginccrs, Inc. P.O. Box 2808, Norcross, Georgia 30091

850 Center Way, Norcross, Georgia 30071 Phone: 770-453-1410 Fax: 770-453-141 1

Patterson S Dewar Engineers, Inc. Hood 8 Patterson S Dewar, Inc.

February 28, 201 1

Taylor County RECC 625 W. Main Street Campbellsville, Kentucky 427 18

RE: 201 1 Long Range System Study

Gentlemen:

We submit herewith our study of your primary electric distribution system. In this study and report, consideration has been given to future consumers and their power requirements, power source locations, type of distribution line, line capacity, distribution voltage and voltage regulation.

From the conclusions developed in this study the following items are stressed:

- A s with the residential consumers using an average of 1,150 1tWh each, giving a future system peak deinarid of approximately 250 MW. A total of approximately $1203 14,386 of additional capital investment is estimated.

The preferred plan of the future system indicates that six new distribution substations will be required: Pierce, Cantown, Log Church, Sparksville, Saloma 2, and Bloyd's Crossroads. Four existing substations will require cooling fans for increased capacity.

The distribution system will remain 7.2 / 12.47 1tV.

It is recommended that an annual review of this Long Range System Study be made and Construction Work Plans be coordinated to detail new plant required to serve load growth only as it develops.

0

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We believe that adoption of the program recommended in this report will serve adequately as a guide from which to plan the development of your electric distribution system.

Sincerely,

Pnttersoir & Dewar Engiireers, I~Ic .

Gary E. Grubbs, P.E. Client Engineer

,----- -.--*-- ---- -__ ^_x_____- __ -s=--, , , .-- " - PO BOX 2808, NO~CI-OSS, GA 3009 1-2808 P 770-453- I 4 I O F 770-453-141 I www pd-engineers c o i n www hoodpd corn

850 Center Way, Norc ross , GA 30071-4844

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TABLE OF CONTENTS

LETTER OF TRANSMITTAL AND ENGINEERING CERTIFICATION ............................ i

.. GENERAL COOPERATIVE LOCATION MAP ...................................................................... I I

... TABLE OF CONTENTS . TEXT ................................................................................................ 111

TABLE OF CONTENTS . EXHIBITS & APPENDICES .......................................................... iv

I . INTRODUCTION ................................................................................................................. 1

I1 . PURPOSE OF REPORT ....................................................................................................... 2

I l l . SUMMARY OF REPORT AND RECOMMENDATIONS ............................................... 3

IV . ANALYSIS OF EXISTING SYSTEM AND BASIC DATA .............................................. 4

A . INTRODlJCTION ........................................................................................................................ 4 B . c .

PURPOSE OF ANALYSIS ............................................................................................................ 4 SUMMARY, CONCLUSION, AND RECOMMENDATIONS ............................................................. 4 3 y m e k T T ? N s .................................................................................................. 4 n , .

E . F . G . H . I . J . I< . L . M . N . 0 . P . Q . R . S . T . V .

CAPACITY OF EXISTING SYSTEM ............................................................................................. 5

ADEQUACY OF BASIC DATA .................................................................................................... 5 LONG-RANGE DEMAND LEVEL. ............................................................................................... 6 AREA L. OAD DENSITY AND GROWTH POTENTIAL .................................................................... 6 SPECIAL LOADS ....................................................................................................................... 6

ENVIRONMENT ALL,^ SENSITIVE AREAS .................................................................................. 5

SERVICE RELIABILITY ............................................................................................................. 6

OTHER CRITERIA ..................................................................................................................... 7 SYSTEM DESIGN GUIDEL~INES ................................................................................................. 7

FINANCIAL. CRITERIA .............................................................................................................. 8 ASSUMPTIONS .......................................................................................................................... 8

EXPLORATORY PLANS ............................................................................................................. 9 PLAN SELECTION ................................................................................................................... 10

FACIL. ITIES AND EQUIPMENT ................................................................................................... 9

THE RECOMMENDED PLAN ................................................................................................... 1 1 ALTERNATE PL. ANS REVIEWED ............................................................................................. 11

CONCLUSION .................................................................................................................... 12

... 111

TABLE OF CONTENTS

EXHIBITS

EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT EXHIBIT

1 .................................................................................... System Statistical Data 2 ....................................................................................... Substation L,oad Data 3 ....................................................... Ecorioinic Parameters and Cost Estimates 4 ............................................................................ Consumer Outage Summary 5 .......................................................................... RUS Fixed Charge Summary 6 ................................................................ Summary of Total Plant Investment

8 ................... Summary of Estimated System Distribution Improvement Costs 9 ......................................................................... Cost Estimates, New Services 10 ............................................ Cost Estimates, Distribution Line Construction 1 1 ........................................................ Cost Estimates, Transmission Facilities 12 ........................................................................... Cost Estimates, Substations 13 ................................................. Cost Estimates, Up-rating Existing Services 14 ................................ Cost Estimates, Miscellaneous Distribution Equipment 15 ..................................................................................... Cost Estimates, Poles 16 ............................................ Estimated Distribution Plant Investment Charts

7 ...................... Summary of Estimated Capital Additions to Distribution Plant

EXHIBIT EXHIBIT EXHIBIT EXHIBIT

17 .................................................. Economic Comparisons or I lans Keviewed

19 ..................................................................... Conductor Life Cycle Analysis 1 8 ....................................................................................... Sensitivity Analysis

20 ....................................................... System Design arid Operational Criteria

MAPS*

MAP 1 - Existing January 2010 System

MAP 2 - Proposed Winter 203.5-36 System - Load Level .5

* Map provided for Preferred Plan G only.

iv

TAYLOR COUNTY RIJRAL ELECTRIC COOPERATIVE CORPORATION Kentucky 23 Taylor

Campbellsville, Kentucky

2011 LONG RANGE SYSTEM STUDY

February 20 1 1

I. INTRODUCTION

This report details tlie results of an engineering analysis of the future direction of tlie Taylor County

Rural Electric Cooperative (TCRECC) electric distribution system. The study examined the existing load

and growth patterns and projected size, configuration, and characteristics of the system required to serve

tlie anticipated 1.6 times current peak load by 2035. From this projected load tlie needs and configuration

of tlie system were estimated. Various alternative methods of serving this anticipated future load were

developed and compared. A “One Ownel-ship ” present worth aiialysis was made to determine tlie

preferred long-range plan. This report contains a brief discussion of the exploratory plans and a more

detailed analysis of tlie intermediate levels of tlie preferred plan, as well as system maps, cost estimates

ana oriier necessary englneu

Tlie corporate office of Taylor County Rural Electric Cooperative Corporation is located in

Campbellsville. Tlie cooperative provides electric service to a portion of tlie central most part of

Kentucliy. The service area encompasses generally the rural areas around the small towns of

Cainpbellsville, Columbia, and Greensburg. TCRECC provides electric service to rural homes, farms,

villages, and small coininercial and industrial consumers in Adair, Casey, Green, and Taylor Counties.

Tlie area generally consists of significant rolling hills, some rocky, rough terrain and with grazing lands

along small streams and tributaries. The chief sources of income are fiom general farming, timber aiid

paper products, dairy operations, nurseries and varied small industries. Steady growth is being

experienced around the small cities and towns with modest growth in tlie remaining rural areas.

The Coininonwealth of Kentucky has territorial legislation, establishing tlie areas to be served by the

various utility companies.

Electric power is purchased at the wholesale rate from East Kentucky Power Corporation (EKPC) at

7.2h2.47 1cV from 15 substations. EKPC has ownership of all substations.

1

11. PURPOSE OF REPORT

Thc pi-iiicipal objectives of this L,RSS arc two-fold-to detcriiiiiie tlie most economical approach tlie

system slio~ild tale in tlic future and to establish the capital required to accomplish this plan. The existing

system is aiialyzed and load growth patterns are identified by TCRECC personnel which allow a

deteriiiiiiatioii to be made of tlie systeiii load requirements for approximately 25 years in tlie future. Tlicii,

a distribution system with a nuinbcr of alternatives is designed which can adequately serve tlie anticipated

load from an electrical standpoint. The electrically equivalent alternatives are compared on an economic

basis to identify the most cost-effective or “Preferred Plan”. A detailed analysis of this plan is then inade

to determine tlie method by which a sniooth transition can occur fiom the base system to the Preferred

Long-Range system.

When these objectives are fLilfilled, the Study bccoiiies a valuable planning tool in providing a fi-aiiiework

for the construction of the fnture distributioii system. L,oad centers are identified which may not be

obvious in the existing, developing systcni. LJltimatc circuit, substation, aiid transiiiission line loading are

provided against which current coiisti-~ictioii may be measured. Potential load aiid voltage drop problems

can be recognized and corrected before they becoiiie critical. Thus, tlie Cooperative’s niaiiageinent and

eiigiiieeriiig persoiiiiel caii take a proactive role in the system development by implementing

iiiiproveinents that interact together to rcacli a desired goal, as opposed to reacting to present-day

problems. Without this ability the system may experience many isolated iinproveiiients which do not

conipliineiit each other and may evcii be counter-productive.

From this analysis, the most practical and economic line desigiis caii be determined for serviiig future

loads while maintaining liigli quality service to the customer. A goal of this study is to develop a

systematic schedule for developing iiiajor facilities in order to meet anticipated future system

requirements, aiid to provide an idea of future capital that will be needed to serve the future system. This,

in turn, makes this study a valuable inanageinent guide for fiiiancial plaiiiiiiig and decisioii-mal<ing.

2

111. SUMMARY OF REPORT AND RECOMMENDATIONS

This electric distribution system study has pro,jected tlic long-range loads for Taylor County RECC. Input

was solicited from tlie recent 201 0 EIWC L m d Forecast (LF) and TCRECC engineering, operating, and

managenieiit personnel. Tliesc proJectioiis used in this stiidy are based oii tlie 2010 Load Forecast.

Tlie TCRECC electric systeiii is forecast to serve approxiinately 33,064 coiisuiiiers and have a probable

winter non-coincident peak system demaiid of approximately 250,000 1tW for tlie winter 203536. This

represents a 1 .O pcrceiit per year increase in customer growth and about 1.8 percent per year increase in

system demand over tlie previous system lion-coincident peak.

The number of deliveiy poiiits serving TCRECC is expected to increase from 15 to 21 over the study

period. Distribution voltage will remain 7Z12.4'1 1cV. To have adequate plant based on tlie proJections i n

this study, j t is cstimatcd that tlie total electric distribution plant will grow fi-om a presciit value of

$62,234,331 i n 2009 to a ftitui-c value of approximately $182,748,717 in 2035. This results in a

compound growth rate of approximately 4.23 percent per year. A suiniiiaiy of tlie total plaiit investment

showing tlie historical as well as tlie projected year-by-year increases can be found in Exhibit 6. A chart

showing this information on distribution plant iiivestineiit Cali also be found in Exhibit 16.

Exhibit 3 suiiiiiiarizes tlic basis for thc rcpoi t including the basic ccoiioinic critei ia used. Tlic ccoiioinic

results also include a sensitivity analysis (Exhibit 18) varying tlie paraiiieters of load growth, capital and

energy inflation, and presciit worth fi-om tlic study critcria used. Tlie results show that tlie Preferred Plan

will bc the most ccoiioiiiic clioice.

From the iesults, Plan G proved to be the most cconoiiiical plan and was identified as tlie preferred plan

aiiioiig the seven plans coinpared. Exhibit 17 summarizes tlie comparative results.

Exhibits 6 through 1 5 detail the particulars of the preferred plan. Total plant investment is suiiuiiarized

tlicreiii. Cost estimates for substaiioii and other distribution plant are iiicludcd after bciiig allocated by

yeais. Traiisiiiissioii liiie (T/L,) constixction is listed by year with costs estiiiiatcd in this study. EIQC will

build and own all transmission line, and tlie costs are not included towards TCRECC's electric plant.

3

IV. ANALYSIS OF EXISTING SYSTEM AND BASIC DATA

A. Introduction

Thc January 2,010 systciii configuration was used as the basis for tlie LRSS. The distribution peak demand

in .Taliuaiy 20 I O was 135, I54 kW when tlie system served approximately 25,255 consuiiiers on

approximately 3,183 iiiilcs of distribution line. Even though the 2009 peak was higher, the 201 0

configuration was uscd bccausc of recent system upgrades and custoiiier data. This load is curreiitly

scrvcd through 1 5 distributioii substations.

B. Purpose of Analysis

Bascd on this configuration, individual coiisuiiier billiiig infoiiiiatioii was uscd to assigii load to

individual line scctioiis. The load was allocated using Taylor County RECC substation billing data aiid

feeclcr iiieasurcments. Tliesc allocated loads were used to riiii a voltage drop analysis, which was reviewed

with TCRECC eiigiiieeriiig aiid operating personnel to coiifiriii the loading conditions with their

knowledge of the system characteristics. The system model was determined to be an adequate model of

the preseiit systciii and is used as the base system in the study. The geiieral condition of the existing

elcctrical plant is discussed aiid areas are defined where existing conditiolis do not iiicct criteria. These

problems are taken into account when plaiiiiiiig future system.

C . Su in ma ry, Con e1 us ion, and Recoinmenda tions

In 201 1, a Construction Work Plan (CWP) was developed for tlie years 201 1 through 2013 using the

results of this L,RSS. Necessaiy construction was identified that would be needed during these years to

satisfactorily handle the anticipated loading for this period. The major line construction coiicems are

overloaded single-phase lilies reqiiiring iiiultiqhasing aiid the upgrading of several iiiaiii feeders to larger

collductors 1

D. System Growth Patterns

Taylor County RECC is located in the central portioii of I<eiikiclcy and serves iiieiiil?ers in four coiiiities.

Statutes of the ICeiitucky State L,egislature established tlie electric service area for TCRECC. There are

presently iio anticipated changes to the currently assigiied electric service area.

4

Tlic service area ciicoiii1)asscs generally the rural areas around tlic siiiall towns of Caiiipbcllsville,

Columbia, and Greensburg. Steady growth is being experienced around the small cities aiid towns with

modest growth in the rcmaining rural areas.

E. Capacity of Existing System

The losses for tlie TCRECC systeiii are in line with tlie RUS Bulletiii 45-4 for a systeiii of this size. The

average systeiii Iosscs for tlie past 5 years are 5.4 percent and can be seen in Exhibit I . Losses are

projected to average 5.4 ~~c rcen t over tlie next 20 years.

The service capacity for present loads is adequate for the most part. Total installed substation capacity in

2010 was 256 MVA. This compares to a winter peak to lireseiit of 154 MW. All suhstatioiis are below

80% capacity and in Iinc with the limits established by the Systciii Design Criteria found in Exhibit 20.

The TCRECC electric systeiii plant is maintained in satisfactory operating condition. Froin tlie 2009 Form

7, the five year coiisuiiier outage average is 41 5.3 1 iiiiiiutes (6.92 liours) per coiisuiiicr per year, wliich is X1,P " CT- nf < fl 1 1' lzpl v e a ~ Fol

L V ge minutes per I . . 3009. 1067 7 3 outs

coiisiiiiier were atti-ibuted to a niaJor storiii. Excluding this major storiii, the five year average is 201.86

minutes (3.36 hours) per coiis~iiiier per year.

. . . .

Taylor Couiity RECC's O&M expenses for tlie previous five years are suiiiiiiarjzed in Exliibit 5 . The five-

year average is approximately 5.33 percent of total distribution plant. The five-year average total Annual

Fixed Charge Rate, not included O&M, as a percentage of total distribution plant was 9.99 percent a i d

can be found in this exhibit.

I?. Environmentally Sensitive Areas

TCRECC staff is lciiowledgeablc of areas that may be of coiicerii to environmental aiid ecological issucs.

Tlicre arc no sensitive arcas of coiiccrii that will be affectcd by coiistructioii proposed in this study.

G. Adequacy of Basic Data

Tlic loading conditions calculated wcre based on pcalic coiisuiiier energy usage per line section. TCRECC

engineering personnel aiid Patterson & Dewar Eiigiiieers provided the line section assignments and

energy data. For the most part tlie data provided appeared to be excellent. Metered pealc substation loads

and power factors coiiforiiied extremely well to calculated loading coiiditioiis for the existing system.

5

These loads wcrc reviewed with tlie engiiieeriiig and operating staff of TCRECC. This data is considered

to be a good representation of the current system conditions as well a good basis for prqjectiiig future

system coiiditioiis.

N. Long-Range Demand Level

This long-range ciigiiieeriag plan is completed in accordaiicc with RlJS Bullctin 172.4D- I O 1A entitled

Electric Sjsteni Lmig-Rnngc Plmiiiiiig Guide. The system is expected to cxpcriciice approximately 1.6

tiiiies the past system peak demand in 25 years. This deinaiid magnitudc is sufficient to require capacity

increases in iiiajor system components. In this study, the system is designed to support the load and time

frame projections outliiied in tlie load forecast. Not only are the twenty-four year pro,jectioiis outlined iii

this Plan, but interiiiediate levels are addressed as well. The fivc load levels are identified and outliiied per

the followiiig sclicdule.

Load Total Peak _I__ Level -- Cons u in e r s Deinand (MWJ

1 26,298 16.3 2013114 2 27,205 180 20 1 611 7

4 ,L s L 4 L L V L Y I 2 V

3 28,467 206 2020/2 1 f. 1- m A m I ? A I^

1.

Input

5 33,064 250 2035136

Area Load Density and Growth Potential

vas solicitcd from Taylor County RECC’s eiiginceriiig staff to identify wious growth areas of the

systciii. The discussion with thc cooperative’s staff resultcd in dcvclopmciit of the L,RSS growth rates

J. Special Loads

Besides the classification of the areas above, locatioiis were identified where loads are expected to

develop. TCRECC’s engineering persoiiiiel were knowledgeable of areas where iiew residential

construction is anticipated.

I(. Service Reliability

In designing tlic long-range plan, and in paiticular tlic iiitcriiicdiatc plans, emphasis was placed on

selecting p i ojccts which would eiisurc coiitiiiucd high quality scrvicc and reliability. This study docs not

attempt to design future transiiiission facilities, wliich should be addressed by EIQC.

In addition to transmission and substation reliability, distribution reliability is also important. The

distribution lines and equipment need to be Itept in good working condition. This includes the

rcplacciiicnt of obsolete equipment including older high loss transforniers, dcterioratcd poles, and old,

brittle copper conductor. The goal is to continue to develop a distribution system that is economical yet

reliable while iiiaintainiiig as low an O&M expense as is technically and econoiiiically feasible.

L. System Design Guidelines

The System Design Guidelines, Exhibit 20, was used as a guide for improving and uprating facilities. The

construction standards outliiied in tlie guidelines were used as a basis for the curi-cnt Construction Work

Plaii and remain valid for future construction and improvenieiits. Tlie guidelines were strictly adhered to

in the design and development of the preferred plan.

M. Other Criteria

In addition to the system design guidelines, tlie Conductor Life Cycle Analysis (Exhibit 19) was used to

cietcrinine tlie appropriate conductor size to use when 1-e-conductoring existing lines. By using the current r

.L . . . c o s I 0 1 1 1 o 1 1 5 anc1 e e 0 1 1 7 i LIL '1 A *>I5 c W l i l g1vc i1K l-rm&zm- io

usc based on the combination of original costs, O&M costs, losses, and TCRECC's staiidard sizes of

conductor. The priiiiaiy conductor sizes recoiiiiiicrided in this study are 1/0 ACSR, 336 ACSR, and

477 ACSR.

All exploratory plans were based on winter pealtiiig conditiolis and a iiiaximum of eight volts drop from

thc substation without line regulation for the long range load levcl. This ensured that each plan had

basically the same capacity regardless of voltage class, conductor size, and iiuiiiber of ultimate delivery

points or main feeders. However, in accordance with the latest RUS Bulletin 1724D-101A, once the

preferred plaii was selected, tlie ultiiiiate design was plaiiiied with a iiiaxiinuin of eight volts drop with

oiic bank of line regulation for tlie intermediate levels. Virtually all distribution systems use line

regulation to maintain voltage on the extremities of primaiy lines until major iniproveiiieiits can be

justified. This is a much 111ore realistic and practical approach for developing a distribution plant to meet

fiiture needs.

7

N. Financial Criteria

Thc L,ong Range Plaii was choseii oii tlie basis of two factors: oiic, tlic most reliable service possible, and

two, the most economical. Wlieii lool<ing at econoinics, the total costs of the plans are compared by the

Oiic On:iiei*shQ7 method. This approach adds the costs of system improvcmeiits for both the power

supplier aiid the distributor.

Iii developing a preferred plan fi-oiii the seven alteniate plans, a preseiit worth analysis was compiled. A

present worth analysis is most frequently used to determine the present value of money receipts aiid

disburseiiieiits. This method provides an easy way to compare elcctrically equivalent alternatives by

resolving their ecoiioiiiic coiisequeiices at the presciit time.

This analysis was applied to both the distributoi- and the supplier tinder tlie O m Owiersliij~ concept.

These ecoiioiiiic aiialyses use tlie cost of improvements allocatcd to their respective years, inflated, aiid

returiied to a present worth value for both distributor and stipplier. These costs include distribution liiie

improvements, substation improvements, transmission improveiiients, delivery point charges, aiid losses.

Costs to both TCRECC and EKPC were broken out for each plaii for comparative reasons. If two plans

rcsiilted in approximately the saiiie Oi7e Owiier~sh@ costs then the plan that spread the costs inore evenly

bctwceii distributor and supplier was coiisidered the preferred approach.

0. Assumptions

Thc rcsiilts aiid filial recommciidatioiis of this study arc based oil a number of l ey cconoiiiic parameters

joiiitly agrced ripon by TCRECC, EKPC, and Pattcrsoii & Dewar Eiigiiicers. The chart shown below

summarizes the parameters aiid quantities used.

8

Assumptions

Eiicrgy Cost/ 1tWIi Prescnt Wortli Intcrcst Rate Annual Fixcd Chargc Annual Fixed Charge (Substations) Annual Fixed Chargc (Transmission) Distribution O&M Costs (%) Substation O&M Costs (%) Transmission O&M Costs (%) Iiiflatioii Rate Energy Iiiflatioii Ratc

Pow er Di s t rib u t o r

$0.08 6.90 Yo 9.99 %

5.33 O h

3.00 % 2.50 O h

Power Supplier

$0.08 8.97 (YO

8.SSYo 10.14%

2.00 Yo 5.40 Yo 3.00 % 2.50 %

A sensitivity analysis was perfoiiiied on tlircc of the seveii plans. The results of tlie analysis are shown in

Exhibit 18. The results of these variations conclitde that Plan G is a solid plan to follow regardless of tlie

economic conditions.

P. Facilities and Equipment

Facilitics and equipment included in this study are piovidcd by both supplier and distributor, a d are

categorized and studied iiidividually and togctlicr under thc O m O~i~17eYShzj7 coiiccpt. All distribution

lilies and relatcd equipment are owiicd by Taylor Coiinty RECC, and substations and transmission liiics

are owned by EKPC. For tlic sake of convenience in the analysis pi-occss, all equipment coiimoii

bctwecii plans weic omitted. TCRECC coordination closely with EI<PC concerning thc L,RSS, aiid

EICPC’s input added greatly to the final optioiis for the L,RSS.

Q. Exploratory Plans

From tlie load pro.jectioiis listed in the planning criteria above, seven exploratory plans were designed

using sound eiigiiieeriiig guidelines. These plans are listed below.

9

PLAN A PLAN B PLAN C PLAN D PLAN E PL,AN F PLJAN G

PLAN DESCRIPTIONS Upratc Existing Substations. New Sparl<sville substation added. Saine as Plan B, but new Bloyd’s Crossroads substation added Saiiic as Plan C, but new Saloiiia 2 substation added. S a m as Plan D, but new Caiitowii substation added. Samc as Plan E, but new L,og Cliurch substation added. Samc as Plan F, but new Pierce substation added.

R. Plan Selection

Froin these basic options, substation load centers were cstablishcd. Ecoiioinics for plant iiivcstmcnt to

servc tlic 250 MW load level was calculatcd. In ordcr to have a O m Oivne~ship comparison, thc

traiismissioii and substation costs for EIQC wcrc includcd in each plan. A coiiiparisoii of the prcseiit

woi th analysis for cadi plan rcsultcd in thc most ccoiiomical approach to scrvc tlic futurc systcin iiccds.

Tlic results arc shown in Exhibit 17 Tlic chart shown bclow suiiiiiiarizcs thc prcsciit worth costs foi thc

diffcrent options

PRESENT WORTH (201 1 Dollri-s)

One Ownership Preferred Plan PIaii - Rank Concept Cost Difference - - A $43,471,132 $2,96 1,591 7

B $42,386,178 S 1,876,637 6

c $42,2 10,233 $1,700,692 5

D $41,928,119 $1,4 18,578 4

E $40,706,8 15 S 197,274 3

F $40,550,088 $40,547 2

It iiiust bc iiotcd that tlic aforcmcntioiicd costs do not rcllcct tlic total plant rcquircd to seilrc thc long-

iaiigc load level. Expciiscs coiimoii to all plans havc bccii ignored in thc comparisons. Also, tlic abovc

figures icprcsciit 201 1 costs iiiflated at 3.0 percent pcr year. As tlic tablc indicates, plaii G would rcsult in

the most ccoiioinical approach to serve tlic futurc load.

10

S. The Recoininended Plan

Thc rccommcndcd Prefcrrcd Plan calls for tlic followiiig iicw substations. Picrcc (20 16), Cantown (20 19),

L,og Church (202 I ) , Sparltsville (2024), Saloiiia 2 (2026), and Bloyd’s Crossroads (2027). In addition, tlic

following substations will req~iii e tlie addition of power traiisforiiicr cooling fans”

Coburg (20 1 1 ), Crcston (2020), East Caiiipbcllsvillc (2028), and Grceiisburg (2034).

New substation Requircd Existing Substatioii Rclievcd Pierce M c I h n e y Coi iier Caiitowii Phil Log Churcli G arl in Sparltsville West Coluiiibia Saloiiia 2 Mile Laiic Bloyd’s Cross1 oads Suiiimcrsvillc

In addition to prcveiitiiig tlie uprating of an existing substation, building the iicw substation results in

much less heavy conductor consti-uction aiid far greater scrvicc rcliability and voltage.

DL~C to the abuiidaiice of 69 1tV transmission line and reasonable substation construction costs, the system

voltage for TCRECC will reinah 7.2/12.47 ItV for the study period. Taylor County RECC presently does ik.

worlting eiiergizcd 25 kV lines. The management atid staff of Taylor County RECC, as well as P&D,

concur that maiiitaiiiiiig a 7.2h2.47 ItV systciii based oii tlic current and projected economics is tlie

preferred option.

Exhibits 10, 1 1 and 12 iteiiiize thc traiisiiiissioii and distribution system construction and substations of

the Preferred Plan. Tlie recoiimended distribution consti-uctioii aiid new substation locations can bc seen

011 Map 2.

T. Alternate Plans Reviewed

Plan F - Alternate Plan

This plan differs fi.0111 the piefcrred plan in that the McKiiiiiey Coriicr substation is uprated to an

11.2 MVA transformer instead of the addition of the Pierce substation. If the Pierce substation is not

added, service reliability will be compromiscd aiid iicw licavy conductor will bc nccded to scive load in

the area. However, tlic other Gvc iicw substations arc rcconuiiendcd for scrvicc in this plan.

11

V. CONCLlJSION

Tliis study is iiiteiided as a guide to anticipated futurc systeiii growth aiid developmeiit. Adherence to tlie

coiistructioii guidelines set forth will enable the Cooperative to serve the loads forecast in an efficient,

orderly, ecoiioiiiical, and environmentally acceptable iiiaiiiier. Tliis is true as long as the conditions and

assumptions upon which this study is based reiiiaiii valid. Therefore, this study should be reviewed before

the completion of aiiy iiew Construction Work Plan. Tlie review should iiiclude all of tlie following:

Are customer aiid 1cW load projections iii line with present growth patterns? Have any iiew growth pockets or areas developed that are not iiicluded in this study?

consideriiig inflation and are tliey allocated reasonably?

representative of present day conditions?

e

0

e Do the cost estimates and system plant levels represent present ecoiioinic conditions

e Are tlic assumed economic parameters of inflation, interest rates, energy costs, etc.,

A negative answer to any of tlie above qiiestioiis iiiiplics that this study may need to be aiiieiided or eveii

redone. A re-evaluation is iioniially required each seven to ten years. Tlie real value in systeiii plaiiiiiiig

lies in lceepiiig this Long Range Systeiii Study on an up-to-date basis aiid far enough ahead of year-by-

year coiistructioii to poiiit out the most practical aiid ecoiioiiiic directioii for future expansion.

12

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TAYLOR COUNTY RURAL ELECTRIC COOPERATIVE CORPORATION Kentucky 23 Taylor


201 I LONG RANGE SYSTEM STUDY

COST ESTIMATES (20 1 1 DOLLARS)

DISTRIBUTION 30 110ACSR 30 336ACSR 30 336 ACSR Double Circuit 30 477ACSR 30 477 ACSR Double Circuit

Cost I Mile - - $55,000 per mile

$85,000 per mile $ 1 10,000 per mile

$95,000 per mile $120,000 per mile

- - - - - - - -

SUBSTATIONS Uprate existing substations. - 69-12 5 kV, 15/20/25 MVA with 8 feeder bays

69-12 5 kV, 11 2 MVA doubled-over station (22 4 MVA Base Capacity)

69- 12 5 kV, 5 MVA 69-1 2 5 kV, 1 1 211 4 0 MVA 69-1 2 5 kV, 15120125 MVA

(1 38 or 16 1 )I1 2 5 kV, 1211 6/20 MVA

- - -

Build new substations. - - - - - - - 69-12 5 kV, 1 1 2114 0 MVA doubled-over station (22 4 MVA base capacity)

(138 or 161)/12 5 kV, 12/16/20 MVA doubled-over station (24 0 MVA base capacity)

-

= - -

$9oo,ooo $720,000

$645,000 $800,000

$1,240,000 $1,240,000 $1,355,000 $2,460,000

TRANSMISSION 69kV, 266 8 ACSR Line Cost Per Mile - - $350,000 per mile 69kV Tap Structure and Two-way Air-Break Switch 69kV Tap Structure and Three-way Air-Break Switch 138kV or 161 kV, 556.5 ACSR Line Cost Per Mile 138kV or 161 kV Tap Structure and Three-way Motor-Operated Air-Break Switch

$80,000 each $90,000 each

$450,000 per mile $150,000 each

- - - - - - - -

* Substation and transmission costs based on estimates from EKPC dated 1211412009

KY23 LRSS Ex 3.xls EXHIBIT 3

Page 1 of 3




ECONOMIC PARAMETERS AND BASE ASSUMPTIONS

ECONOMIC CRITERIA (2010 BASIS):

Losses / kWh ($) Present Worth Interest Rate (YO) Annual Fixed Charge (YO) ** Annual Fixed Charge (YO) (Transmission) ** Annual Fixed Charge (%) (Substations) ** Distribution 0 & M Costs (Yo) Substation 0 & M Costs (%) Transmission 0 & M Costs (%) Inflation Rate (%) Energy Inflation Rate (YO) Total Value of Distribution Plant (12/31/09)

Power Distributor TCRECC

Distribution $0.0800

6.90% 9.99%

5.33%

3.00% 2.50%

$62,234,331

Power Supplier East Kentucky PC

Sub. / Trans. $0.0800 *

8.97% *

10.14% * 8.55% *

2.00% * 5.40% * 3.00%

* Data provided by East Kentucky Power Cooperative on January 19,201 0 ** Interest, depreciation, taxes, and insurance only.


Page 2 of 3




LOADING AND OPTIONS

- System Design Loads _..- Winter Total

Peak kW Demand Consumers January 2009 Peak = 154,562

LL1 2013114 System = 163,000 26,298 LL2 201 6/17 System = 180,000 27,205 LL3 2020/21 System = 206,000 28,467 LL4 2029/30 System = 242,000 31,273 LL5 2035/36 System = 250,000 33,064

per year 1.80%

PLAN OPTIONS FOR EVALUATION:

nl c 17 5 k\l IGi7 ,A, hl-mA. vu, -_" ... Plan B - Plan C- Plan D- Plan E- Plan F- Plan G-

New Sparksville substation added. Same as Plan B, except new Bloyd's Crossroads substation added. Same as Plan C, except new Saloma 2 substation added. Same as Plan D, except new Cantown substation added. Same as Plan E , except new Log Church substation added. Same as Plan F, except new Pierce substation added.


Page 3 of 3




Consumer Outage Hours (Outage hours per c o n s u m e r per year )

O u t a a e C a u s e

Power Extreme Pre- Year Supplier Storm Arranged Other Totals

2005 0.05 0.34 0.04 115 1.58

2006 0.12 2.73 0.01 3.01 5.87

2007 0.01 0.59 0.03 1.25 1.88

2008 0.34 2.34 0.00 1.98 4.66

2009 0.49 17.79 0.01 4.24 22.53

Five Year Average = 0.20 4.76 0.02 2.33 7.30

Five Year Average = 0.20 1.50 0.02 2.33 4.05 (excluding 2009 ex t r eme s torm)

Ky23 LRSS Ex 4 XIS EXHIBIT 4



2011 LONG RANGE SYSTEM STUDY SUMMARY RUS FIXED CHARGE RATE PROJECTIONS

TOTAL ANNUAL FIXED CHARGE RATE (TIER - Method)

cos t Debt

Year (CD) 2005 1.78 % 2006 1.67 % 2007 1.66 Yo 2008 1.77 Yo 2009 1.61 %

Cost Operation Capital Maintenance Taxes Depreciation

TIER --- (CC) ( O&M) (Tx) P e p ) (TFCR) x 3.7600 = 6.69 Yo 5.29 Yo 0.09 Yo 3.00 % 15.07 Oh x 3.3663 = 5.61 'Yo 5.94 'Yo 0.09 Yo 3.00 Yo 14.64 Yo x 3.0155 = 5.01 Yo 5 18 Yo 0.10 % 3.00 % 13.28 Yo x 2.2818 = 4.04 Yo 5.16 Yo 0.09 'Yo 3.00 Yo 12.29 % x 5.6091 = 9.05 % 5.08 % 0.08 % 3.00 % 17.21 Yo ___-

Projected 1.70 % 3.6065 6.08 Yo 5.33 Yo 0.09 Yo 3.00 % 14 50 %

TFCR = Cost of Capital (CC) + Oper. & Main. (O&M) + Taxes (Tx) + Depreciation (Dep)

KEY RATIOS Plant

Year TIER TIER DSC DSC Ratio Ratio Ratio 2005 3.7600 3.7600 35.74 Yo 64.26 Yo 3.20 3.20 5.69 2006 3.3663 3.3663 33.48 Yo 66.52 Yo 3.07 3.07 5.64 2007 3.01 55 3.01 55 33.37 Yo 66.63 % 2.35 2.35 6.43 2008 2.2818 1.8728 35.59 Yo 64.41 % 2.48 2.24 7.08 2009 5.609 1 4.1342 32.42 O/o 67.58 Yo 4.36 3.54 5.75

Modified Debt Equity Modified Revenue

__-- --

Projected 3.6065 3.2297 34.12 % 65.88 % 3.09 2.88 6.12

KY23 LRSS Ex 5 FxCh.xls EXHIBIT 5

Page 1 of 2


Cam p bel lsvi I le, Kentucky

2011 LONG RANGE SYSTEM STUDY SUMMARY RUS FIXED CHARGE RATE PROJECTIONS

TOTAL ANNUAL FIXED CHARGE RATE (Goodwin Method)

COST OF EQUITY FACTOR

ENTER the Capital Retirement Cycle. (Number of Years) ENTER Utility Plant Growth Rate. (YO) Calculated Cost of Equity Factor (YO) (Goodwin Formula)

M = (I+L)"(K+l) - (I+L)"K x 100 (I+L)"K - 1

Cost Equity (CE) = M x Equity Ratio for (Goodwin Method)

cos t cos t Cost Operation Debt Equity Capital Maintenance Taxes Depreciation

Year (CD) (CE) (CC) ,_ (O&M) (Tx) P e p ) (TFCR) 2005 1.78 % + 5.08 Yo = 6.86 Yo 5.29 Yo 0.09 Yo 3.00 Yo 15.24 % 2006 1.67 Yo + 5.26 % = 6.92 Yo 5.94 Yo 0.09 Yo 3.00 % 15.95 % 9nn7 1 CC 01 L E 37 Of - E Qf2 Of- r; 9 8 OL. Q 1 o/,

d . L , ," ". I " I " 3.m "/- I 5 u) O/?

2008 1.77 Yo + 5.09 Yo = 6.86 Yo 5.16 Yo 0.09 Yo 3.00 Yo 15.1 1 Yo 2009 1.61 Yo + 5.34 % = 6 95 Yo 5.08 Yo 0.08 Yo 3.00 % 15.12 %

Projected 1.70 % 5.21 % 6.90 Yo 5.33 % 0.09 O/o 3.00 % 15.32 Yo

TFCR = Cost of Capital (CC) + Oper. & Main. (O&M) + Taxes (Tx) + Depreciation (Dep)

KY23 LRSS Ex 5 FxCh.xls EXHIBIT 5

Page 2 of 2

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TAYLOR COUNTRY RURAL ELECTRIC COOPERATIVE CORPORATION Kentucky 23 Taylor


2011 LONG RANGE SYSTEM STUDY Cost Estimates - Distribution Line Construction

(201 1 Dollars)

1.L1 201 1-2013 Reconductoring 20 llOACSR 30 1/0ACSR 30 336ACSR 30 336 ACSR (DC) 30 477ACSR 30 477 ACSR (DC)

LL2 2014-2016 Reconductoring 30 1/0ACSR 30 336ACSR 30 336 ACSR (DC) 30 477ACSR 30 477 ACSR (DC)

LL3 2017-2020 Reconductoring 30 1/0ACSR 30 336ACSR 30 336 ACSR (DC)

Miles Cost I Mile 0 7 @ $ 40,000 $ 28,000

0 0 @ $100,000 = $

18 6 @ $ 55,000 = $ 1,023,000 8 9 @ $ 85,000 = $ 756,500

0 0 @ $ 95,000 = $ 0 0 @ $110,000 = $

$ 1,807,500

Cost per year (3 years) = $ 602,500

Miles Cost / Mile 77 6 @ $ 55,000 = $4,268,000

3 6 @ $ 85,000 = $ 306,000

2 6 63 $ 95,000 = $ 247,000 0 0 @ $100,000 = $

0 0 ijj! $110,000 = $ $4,821,000

Cost per year (3 years) = $ 1,607,000

Miles Cost / Mile 59 9 @ $ 55,000 = $ 3,294,500 4 0 @ $ 85,000 = $ 340,000 0 0 @ $100,000 = $

30 477 ACSR (DC)

LL4 2021 -2029 Reconductoring 30 1/0ACSR 30 336ACSR 30 336 ACSR (DC) 30 477ACSR 30 477 ACSR (DC)

LL5 2030-2035 Reconductoring 30 1/0ACSR 30 336ACSR 30 336 ACSR (DC) 30 477ACSR 30 477 ACSR (DC)

1 5 @ $ 110,000 = $ 165,000 $4,654,500


Miles Cost I Mile 39 6 @ $ 55,000 = $2,178,000

9 4 @ $ 85,000 = $ 799,000

13 0 @ $ 95,000 = $ 1,235,000 1 9 @ $ 110,000 = $ 209,000

$4,421,000

0 0 @ $100,000 = $

Cost per year (9 years) = $ 491,222

Miles Cost I Mile 63 5 @ $ 55,000 = $ 3,492,500 41 7 @ $ 85,000 = $ 3,544,500

5 3 63 $ 95,000 = $ 503,500 0 0 @ $100,000 = $

0 0 ijj! $110,000 = $ $7,540,500


KY23 LRSS Ex 6 lo 16 XIS EXHIBIT 10



2011 LONG RANGE SYSTEM STUDY Cost Estimates - Transmission Facilities

(201 1 Dollars)

Miles Cost I Mile

LL1 None

LL2 2016 Tap Structure - Pierce $80,000

LL3 201 9 Tap Structure - Cantown $80,000

LL4 2021 Tap Structure - Log Church $80,000 69 kV to Log Church 2.0 $350,000

$80,000 69 kV to Sparksville 1.5 $350,000

2026 Tap Structure .. Saloma 2 $80,000

2027 Tap Structure - Bloyd's Crossroads $80,000

2024 Tap Structure - Sparksville

__

LL5 None

Extended Cost

$80,000

$80,000

$80,000 $700,000

$80,000 $525,000

$80,000

EKPC Supplier

$80,000

$80,000

$80,000 $700,000

$80,000 $525,000

$80,000

$80,000 $80,000

KY23 LRSS Ex G to 1G.xls EXHIBIT 11



2011 LONG RANGE SYSTEM STUDY Cost Estimates - Substations

(201 1 Dollars)

TOTAL EKPC IS u p pl ier) - - COSTS -..-_

$ 800,000 $ 800,000

LL4 2009 Add Cooling Fans - Campbellsville #2

201 1 Add Cooling Fans - Coburg

LL2 2016 Build Pierce Substation 69-12.47 kV, 11 "2 MVA 4-feeders

LL3 2019 Build Cantown Substation $ 800,000 $ 800,000 69-12.47 kV, 11 2 MVA 4-feeders

Add Cooling Fans - Creston 2020

LL4 2021 Build Log Church Substation $ 800,000 $ 800,000 69-12.47 kV, 11 "2 MVA 4-feeders

2024

2026

2027

2028

LL5 2034

Build Sparksville Substation $ 800,000 $ 800,000

4-feeders

Build Saloma 2 Substation $ 720,000 $ 720,000

4-feeders

Build Bloyd's Crossroads Substation

4-feeders

Add Cooling Fans - East Campbellsville

Add Cooling Fans - Greensburg

69-12.47 kV, 11 2 MVA

69-12 47 kV, 1 1.2 MVA

69-12.47 kV, 11.2 MVA $ 800,000 $ 800,000

' $4,720,000' $ 4,720,000

EXHIBIT 12 KY23 LRSS Ex 6 to 16.xls



2011 LONG RANGE SYSTEM STUDY Cost Estimates - Uprating Existing Services

(201 1 Dollars)

Service Wires to Increase Capacitv

From 201 1-2013 Construction Work Plan: 2011 44 upgrades $609 each = $26,796 2012 44 upgrades $627 each = $27,588 2013 44 upgrades $646 each = $ 28,424

For the years 2014-2035, costs will be increased by 3% each year for inflation. Total upgrades per year will remain constant.

KY23 LRSS Ex 6 to 16 XIS EXHIBIT 13



2011 LONG RANGE SYSTEM STUDY Cost Estimates - Miscellaneous Distribution Equipment

(201 1 Dollars)

Sectionalizing Equipment

From 201 1-2013 Construction Work Plan: 201 1 = $ 110,256 2012 = $ 113,568 201 3 = $116,976

Line Voltage Regulators

From 20 1 1-201 3 Construction Work Plan: $ 92,000 - Estimate per year -

Line Capacitors

From 201 1-2013 Construction Work Plan: $ 2,000 - Estimate per year -

For the years 2014-2035, costs will be increased by 3% each year for inflation. Total upgrades per year will remain constant.

KY23 LRSS Ex 6 to 16 XIS EXHIBIT 14



2011 LONG RANGE SYSTEM STUDY Cost Estimates - Pole & Conductor Replacements

(201 1 Dollars)

Pole Replacement From 201 1-2013 Construction Work Plan:

2011 447 poles $1,292 each = $577,524 2012 447 poles $1,331 each = $594,957 2013 447 poles $1,371 each = $612,837

For the years 2014-2035, costs will be increased by 3% each year for inflation Total poles per year will remain constant.

Conductor Replacement From 201 1-201 3 Construction Work Plan, overhead conductor replacement is $1 50,000 each year. There is a one time special underground replacement project in 2012 for $250,000

For the years 2014-2035, $150,000 estimated cost for 2013 will be increased by 3% each year for inflation.

Conductor Replacement Plan: 1 Replace all single phase copper lines causing consistent outages. 2. Two and three phase copper lines are to be replaced as needed due to feeder loading conditions

4 New single phase lines are built either 4 ACSR or 1/0 ACSR depending on likelihood that line will require three-phase construction in the near future

5 Small amounts of old 4 ACSR remain on the system and will be replaced as needed. 6 Taylor County RECC's goal is to replace approximately 5 miles per year.

hn v n -1-4 h A n n P " uitfcu " V I " nc .,.

Total Miles of ,Copper Conductor on System - No. Substation

0 Campbellsville 1 Mile Lane 2 Greensburg 3 Summersville 4 McKinney Corner 5 Coburg 6 Columbia 7 Green River Plaza 8 Bass 9 Phil

10 West Columbia 11 Creston 12 East Campbellsville 13 Garlin

Totals =

Iph 2.0 2.8 8.6 12.2 8.3 8.3 12.2 0.1 2.2 10.0

12.6 1.9

97.9

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KY23 LRSS Ex 6 to 16.xls EXHIBIT 15

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Plan A - Plan B - Plan C- Plan D- Plan E- Plan F- Plan G-



2011 LONG RANGE SYSTEM STUDY ECONOMIC COMPARISONS

(201 1 DOLLARS)

PLAN SUMMARY

No new substations added, system voltage remains 12 5 kV New Sparksville substation added Same as Plan B, except new Bloyd's Crossroads substation added Same as Plan C, except new Saloma 2 substation added Same as Plan D, except new Cantawn substation added Same as Plan E , except new Log Church substation added Same as Plan F, except new Pierce substation added

PRESENT WORTH ECONOMIC ANALYSIS

(EKPC) (TCRECC) Lowest Cost Power Power One Plan

Supplier Distributor Ownership Difference --

Plan A ($1,545,456) $45,016,588 $43,471,132 $2,961,591 Plan B ($1,218,645) $43,604,823 $42,386,178 $1,876,637 Plan C ($942,116) $43,152,349 $42,210,233 $1,700,692 Plan U ,84b,Y, I , , , Plan E $ ~ ~ ~ : ~ ~ ~ ~ ;::,564,0:: $1 97,274 Plan F $214,654 $40,335,434 $40,550,088 $40,547 Plan G $605,922 $39,903,619 $40,509,541 $0

CONSTRUCTION COSTS AND LOSSES SUMMARY

(EKPC) (TCRECC) (TCRECC) Power Power Total Power Total Cost of Lowest Cost

Supplier Distributor Construction Distributor Construction Plan costs costs Losses and Losses Difference _-_ costs _-

Plan A $1,475,979 $25,717,176 $27,193,155 $1 9,299,412 $46,492,567 $3,057,790 Plan B $1,818,961 $24,236,745 $26,055,706 $1 9,368,078 $45,423,784 $1,989,007 Plan C $2,076,852 $23,863,411 $25,940,263 $1 9,288,938 $45,229,201 $1,794,424 Plan D $2,076,852 $23,656,926 $25,733,778 $1 9,190,013 $44,923,791 $1,489,014 Plan E $2,134,574 $22,390,356 $24,524,930 $1 9,173,720 $43,698,650 $263,873 Plan F $3,165,927 $21,333,959 $24,499,886 $19,001,475 $43,501,361 $66,584 Plan G $3,531,158 $21,012,707 $24,543,865 $18,890,912 $43,434,777 $0

EconCriteria 2 0 3 5 . ~ 1 ~ EXHIBIT 17



1 0% $39,777,109 $37,104,351

2.0% $41,525,814 $38,735,623 2 5% $42,472,350 $39,618,544 3.0% -- $43,471 , l ' z m $40,550,088--' 3.5% $44,525,5 14 $4 1,533,3 14 4 0% $45,639,085 $42,571,488

1 5% $40,628,38 1 $37,898,454

201 1 LONG RANGE SYSTEM S'TUDY One Ownership Present Worth

Sensitivity Analysis*

$37,072,712

$38,700,347 I_ $39,580,855

$40,509,541 $41,489,430 $42,523,747

$37,865,185 "_

~ _ _ .

O/O

Inflation - Rate Plan A Plan F Plan G

1.3% $46,364,091 $43,000,189 1.8% $43,471,132 $40,550,088 3 0% $33,667,025 $30,967,274

$43,011,931 $ 4 0 , 5 0 9 , 5 4 r - $30,976,117

1 0% $41,634,572 .- $38,754,088 1 5% $42,209,858 $39,316,864 2 0% $42,82 1,157 $39,974,671 2 5% $43,471,132 $40,550,088 3 0% $44,162,658 $4l ,225 ,Em" 3 5% $44,898,833 $41,945,112 4 0% $45,683,002 $42,710,96 1

$38,728,593 $39,286,727 - $39,879,526 $40,509,54 1 $41,179,524 $41,85- $42,651,490

$66,882,465 $63,591,606 4.0% 5 0% $58,910,831 $55,993,110 6 0 % ,__ $52,177,952 $49,575,890 7.0% $46,466,533 $44,132,923 8 0% $41,600,603 $39,496,503 9 0% $37,437,159 $35,530,299

__

* For the three closest plans with different design approaches

$63,599,079 $56,010,379 $49,600,05 1 $44,16 1 ,743-"- $39,528,27 1 $35,563,714

--

KY23 LRSS Ex 18 Sensitivity Analysis.xls EXHIBIT 18 Page 1 of 5

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CONDUCTOR LIFE CYCLE ANALYSIS (NEW CONSTRUCTION LEGEND AND INPUT VALUES)

0.00% TOTAL Total fixed cost. This is an optional replacement for 0 & M + TAX + DEP + INS -.I__.

5 33% 0 & M Operations and Maintenance Expense as a percentage of Average Net Distribution - " ~

Plant calculated using RUS Bulletin 1724D-101A Electric System Long-Range Planning Guide based on RUS Fixed Charge Calculation Guide

Plant the taxes were paid on annual Form 7, 2 years ago, Part C, line 5 + line 22 Tax Rate. (Property tax / Plant) x 100, or estimated future tax rate Most Owners use straight-line depreciation where the depreciation rate is the reciprocal of the asset's life Use annual rate for Coop, for classes of plant Repreciation rate on RUS Form 7 Part E Lines 5(f) and line 6(f) Insurance as a percentage of Net Distribution Plant Calculating the cost of insurance as a percentage of investment is difficult, and the result makes little difference, therefore, it can be ignored for most applications

0 09% TAX Property tax annual Form 7, last year Part A, line 13(b)

-~ 3 OOo/o DEP

0 00% INS

7 m o / " INF The a- rate. . . 35 m The loan amortization period in years. 7.2 KV Line to ground voltage in kV

-

9800% PF Peak month power factor 6.90% INT 3 00% LGR

$0 00 $/KW

Cost of Capital (Calculated using RUS Fixed Charge Guide ) used for Present Worth Calculation The annual rate of growth projected for the peak demand (Use latest PRS)

Monthly demand charge in dollars per kW per month If $/KW is zero the following dependant inputs will also be zero

35 ULC Useful Life of Conductor

0 00% KWI Demand charge inflation rate 0.00% CF

0 000 RMO 0,000 -RAT 0 000 N

Coincidence factor - This factor represents the coincidence between the non coindedent peak for the line and billing demand The number of months the metered demand exceeds the minimum biling demand The annual demand ratchet expressed as a decimal The ratio of the average of the squares of the monthly kW demands for the months when the metered demand exceeds the minimum billing demand to the square of the peak month demand

--_-1

$0.0632 $/KWH Energy charge in dollars per kWH per month 1.50% KWHl Energy charge inflation rate

4800% LF Annual load factor

Ky23 LRSS Ex 19 XIS EXHIBIT N Page 1 of 3



CONDUCTOR LIFE CYCLE ANALYSIS

7.2 kV Summary

Initial Loading Future Loading based on a

300% LGR for 35 Years

For loads below 1,808 kW use 110 ACSR 5,087 kW

For loads between 1,808 kW and 2,847 kW use 336 ACSR 5,087 kW

For loads above 2.847 kW and kW use 477 ACSR 8,011 kW

Conductor

Construction Costs

Cost Per Mile Ohms Per Mile 50% 100% Conductor Operating Capacity*

- -~

3 0 110 ACSR $55,000 0 888 2,561 5,123 kW

3 0 477ACSR $95,000 0 196 6,837 13,675 kW

* Operating Capacity is defined as the manufacturer's rating at a maximum recommended continuous operating temperature of 75" C (167" F), with a 25" C (77" F) ambient temperature and a 2 ft.lsec wind

Ky23 LRSS Ex 19 XIS EXHIBIT N Page 2 of 3

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SYSTEM DESIGN GUIDELINES

Each of the criteria items listed below was reviewed and concurred by the engineering staff at Taylor County RECC and the RUS General Field Representative.

Construction proposed in this construction work plan is required to meet the following minimum standards of adequacy for voltages, thermal loading, safety, and reliability on the system.

1) The maximum voltage drop from the substation on primary distribution lines is not to exceed 8 volts unregulated, 16 volts with one set of line voltage regulators, and 24 volts with two sets of line voltage regulators Ordinarily, lines will be limited to one bank of line regulators

2) The following equipment is not to be thermally loaded by more than the percentage shown on the nameplate

Power Transformers. Voltage Regulators Oil Circuit Reclosers 100% Line Fuses. 80%

95% summer rating / 95% winter rating 100% at 10% buck or boost; 160% at 5% boost or buck

3) Primary conductors are considered for replacement when loaded to 65% of the thermal rating. Major tie lines between substations can be loaded to 100% during emergency situations.

Poles and crossarms are to be replaced as soon as practicable if found to be physically deteriorated by inspection

Conductors are to be replaced if ACSR is found to have a rusted core or if copper has become brittle and dangerous

Primary distribution lines are to be rebuilt if they are found to be unsafe or in violation (when constructed) of the National Electrical Safety Code or other applicable code clearances.

New lines and line conversions are to be built according to the standard primary voltage levels as recommended in the Long Range System Study

New primary conductor sizes are to be determined on a case by case basis using the Economic Conductor sizing computer program A minimum of 1IO ACSR is to be used on main lines, and a minimum of 4 ACSR is to be used on tap lines

All new primary construction is to be overhead except where underground is required to comply with governmental or environmental regulations, local restrictions, or favorable economics I

10) All new distribution lines are to be designed and built according to RUS standard construction

11) A single-phase tap will be considered for multi-phasing if any of the following conditions are

specifications and guidelines.

present: a) Serves more than 60 meters, b) Load current over 35 - 50 amps, c) Serves an area that is growing

EXHIBIT 20

CONTAINS

LARGE OR

ECEIV N: August 19,2011

ITEM 2

TAYLOR COUNTY RECC P 0 BOX 100 CAMPBELLSVILLE KY 42719

RESPONSE TO PSC ORDER IN CASE NO 201 1-00163

ITEM 2

Line Loss for 2008 was 5.96% for 2009 2.54%

Taylor County RECC completed the conversion from the consumer reading the meter to AMR meters in the first quarter of 2009. Readings from AMR meters were used for the bills mailed to consumers in May 2009.

Under the consumer read meter system consumers would read the meter anywhere between the 10th of each month to the last day of the month. The AMR uses the meter reading for the last day of the month.

-, . . I ne 3 up in 18.7% line loss. SEE BELOW:

PURCHASE SOLD OFFICE USE LOSS 39,959,416 47,363,024 59,295 (7,462,903)

As a result line loss far 2009 was 2.54%

Actual Line Loss for 201 0 was 5.4%.

Witness available: John F. Patterson

ITEM 3



ITEM 3

Load Factor for the year 2000 was 46.2 and for the year 2008 was 44.3 and for the year 2009 was 39.7.

KW LOAD KWH DEMAND FACTOR

2000 384,044,950 94,800 46.2

2008 549,212,071 141,570 44.3

2009 537,279,486 154,562 39.7

this is the main contributing factor to the reduction in Load Factor.

ITEM 4



ITEM 4

a. NP is listed in error, these jobs are complete.

b. 1/0 ACSR three phase conversion per mile estimates that were utilized were low. Additionally, during the workplan period, there were some escalations in contractor labor prices as well as substantial escalations in material costs.


ITEM 5



ITEM 5

309.01 does not exist in Exhibit C, it appears that the commission is comparing 309.01 to 301.09. The direct comparison for 309.01, in terms of Exhibit C, is 304.10. Although somewhat confusing as it pertains to a backwards looking comparison, a naming convention change was made with this workplan. Every substation has a matching numerical identifier within our CIS and GIS systems. In the past, the substation number utilized within the workplans did not match that of the CIS/GIS which TCRECC operational personnel utilize in day to day processes. In order to simplify interpretation of the each 300 job, a t least as far as which substation the job is tied to, the change was made. In workplans prior to the current, as an example, the 4 substation(304.10) coincided with jobs to be done on the Phil substation. However, within the CIS/GIS systems the Phil substation is coded as substation 90, hence the identifier assigned with this workplan(309.01). Given this convention change, TCRECC operations personnel can more easily identify, by noting the last digit of the 300 number, the substation on which the job is tied to.

a. Cost for construction better reflects the cost of labor and materials versus cost estimated a t the start of the last workplan that proved too conservative.

b. n/a c. No duplication confirmed.


ITEM 6



ITEM 6

TCRECC will be responsible for costs associated with constructing circuits exiting the substation thereby tying into existing lines.


ITEM 7


RESPONSE TO PSC ORDER IN CASE NO 201 1,-00163

ITEM 7

a. All CATV attachments are not code compliant. TCRECC inspects joint use attachments during pole inspections, staking for new builds/pole changes as well as during general system inspections.

b. TCRECC does bill CATV for al l attachments and billings are current. c. In the vast majority of cases, TCRECC owns the pole. Issues arise when TCRECC changes the pole

and tops above the joint use cable. When the joint users make their attachment to the new poles the old poles are, many times, left in place. Try and maintain a 4 year cycle but do have issues a t times with yard trees ect. d.


ITEM 8



ITEM 8

See the response to Item 2 of this filing for a discussion of the decrease in line loss for 2009.

Actual Line Loss for 201 0 was 5.4%.

Witness available: John F. Patterson

ITEM 9

TAYLOR COUNTY RECC P 0 BOX I00 CAMPBELLSVILLE KY 42719

RESPONSE TO PSC ORDER IN CASE NO 2011-00163

ITEM 9

TCRECC walks line/checks poles on one substation per year. Below is the approximate number of poles checked via our line walking process: 06 1- 4710 07 - 4165 08 - 4553 09 - 1847 10 - 2269

Additionally, the following day-to-day processes result in poles being checked/replaced: C

Lineman/Serviceman - before climbing poles, poles are verified in good condition Pole changes due to joint use, ect - obviously, new poles are placed

Counts associated with these processes are not tracked.


ITEM 10

TAYLOR COlJNTY RECC P 0 BOX I 0 0 CAMPBELLSVILLE KY 4271 9


ITEM 10

Yes. a. Voltage readings are provided, the spreadsheet details "1200 meters for which TCRECC

monitored voltage throughout the past winter. These meters are dispersed all over the system but some are purposely set a t the end of each feeder to allow for voltages to be obtained a t the system extremities. TCRECC utilizes AMR to set up a job to read the voltage for the meters in attempts to coincide with the a.m. system peak -the results of the job are dumped into Excel. The AMR processes/functions are at the 'meter' level and these are unaware of the concept of line section as it pertains to system modeling. Therefore, utilizing the inherent AMR formats, TCRECC concentrated on investigating the geographic location of the meters in question i i t i l q / r r n z z referenungto svztem A d c e - column I of the spreadsheet details this as it provides a location of the pertinent meter. During cold weather, and after interrogating several of the daily jobs, patterns become evident. Utilizing the data in this fashion allows TCRECC to identify areas, versus line sections, that have issues given the peak conditions. With these areas noted, special attention is given to system modeling results to verify that the model shows the same system weaknesses. TCRECC(P&D) models the system using a balanced model. There are several issues of note when trying to match model output to real world voltage readings down to a tolerance of 2v each and every time. Several of the issues/limitations are noted:

. . .

1.

2.

3.

4.

5.

Model is balanced, no system is perfectly balanced, amperage wise, a t peak and different parts of the system grow a t different rates over the period of the workplan. Model is ran with a certain system loading, does the model loading exactly match the system loading at the time the voltages were obtained? Is the loading on the existing system reflective of the existing/just past peak or is it the end of work plan loading level? Is the meter on a high usage house or a low usage stock barn, the barn is a better indicator of primary voltage given less transformer/service voltage drop Meter manufacturer advertises plus/minus 1% tolerance voltage readings

b. n/a


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