STTTFc DT - Kentuckypsc.ky.gov/PSCSCF/Post Case Referenced Correspondence/2000 cas… · STTTFc "DT :,,A wilmmezkas AliORNEIS April 30, 2014 Mark R. Overstreet (502) 209-1219 (502)

Please do not hesitate to contact me if you have any questions.

Very uly

Mark R. M verstree

y

STTTFc

"DT

:,,,A■wilmmezkas AliORNEIS

April 30, 2014

Mark R. Overstreet (502) 209-1219 (502) 223-4387 FAX [email protected]

HAND DELIVERED

Jeff R. Derouen Executive Director Public Service Commission 211 Sower Boulevard P.O. Box 615 Frankfort, KY 40602-0615

B APR 3 0 2014

PUBLIC SERVICE COMMISSION

RE: Kentucky Power Company's 2013 Public Service Commission Annual Report And Related Filings

Dear Mr. Derouen:

Enclosed please find and accept for filing the original and ten copies of Kentucky Power Company's 2013 Annual Resource Assessment for Kentucky Power Company in accordance with the Commission's March 29, 2004 Order in Administrative Case No. 387. Included as part of this filing is the Company detailed discussion of the consideration given to price elasticity in making its forecasts. Also being filed is the original and ten copies of Kentucky Power Company's motion for confidential treatment with respect to portions of its response to Data Request No. 9.

A copy of the Kentucky Power Company 2010 FERC Form-1 and a copy of the 2010 Annual Public Service Commission Utility Financial Report for Kentucky Power Company are also enclosed.

MRO

RECEIVED APR 3 0 2014

VERIFICATION PUBLIC SEFiviLiz COMMISSION

The undersigned, Ranie K. Wohnhas, being duly sworn, deposes and says be is the Managing Director Regulatory and Finance for Kentucky Power, that lie has personal knowledge of the matters set forth in the forgoing responses for which he is the identified witness and that the information contained therein is true and correct to the best of his information, knowledge, and belief

Ranie K. Wohnhas

COMMONWEALTH OF KENTUCKY ) Administrative Case No. 387

COUNTY OF FRANKLIN

Subscribed and sworn to before me, a Notary Public in and before said County and State, by Ranie K. Wohnhas, this the day of April 2014.

My Commission Expire (/'

ICPSC Administrative Case No. 387 Annual Resource Assessment

Calendar Year 2013 Order Dated December 20, 2001

Item No. 1 Page 1 of 1

Kentucky Power Company

REQUEST

Actual and weather-normalized monthly coincident peak demands for the just completed calendar year. Demands should be disaggregated into (a) native load demand (firm and non-firm) and (b) off-system demand (firm and non-firm). Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420).

RESPONSE

Page 1 of Attachment 1 to this response provides actual and weather normalized 2013 monthly peak internal demands for Kentucky Power Company and AEP System-East. Kentucky Power Company and AEP System-East had 21 and 841 MW of contractual interruptible capacity, respectively.

Page 2 of Attachment 1 to this response provides actual 2013 monthly system demands for Kentucky Power and AEP System-East. The system demands include internal load and off-system sales. Weather-normalized monthly peak system demands for Kentucky Power Company and AEP System-East have not been developed and therefore, are not available.

Please note that the AEP System-East internal and system peak demands include loads for retail customers that receive generation services from an alternative supplier.

WITNESS: Ranie K Wohnhas

Kentucky Power Company and AEP System-East Zone Actual and Weather Normalized Peak Internal Demand (MW)

2013

Kentucky Power Company AEP System-East Zone Peak Peak Normalized Peak Peak Normalized

Month Peak Day Hour Peak Peak Day Hour Peak

January 1,409 1/23/2013 8 1,516 19,970 1/23/2013 8 20,007 February 1,316 2/1/2013 9 1,381 19,087 2/1/2013 9 19,517 March 1,294 3/22/2013 7 1,299 18,267 3/22/2013 7 17,886 April 1,129 4/3/2013 7 922 16,430 4/3/2013 7 14,233 May 1,022 5/31/2013 16 938 18,276 5/30/2013 16 17,158 June 1,124 6/12/2013 16 1,106 19,233 6/25/2013 16 19,621 July 1,138 7/18/2013 16 1,162 20,673 7/16/2013 16 20,837 August 1,097 8/28/2013 16 1,149 18,801 8/30/2013 16 20,381 September 1,084 9/10/2013 16 1,000 20,353 9/10/2013 15 17,840 October 978 10/26/2013 8 832 15,527 10/4/2013 14 13,980 November 1,194 11/13/2013 7 1,189 17,489 11/25/2013 8 16,410 December 1,275 12/13/2013 8 1,371 18,392 12/13/2013 8 18,323

0 a • CD •-• c D 0) sa DJ 0

CD • a n> En 0 " 2- o

kif 5). •

)). m < " CO 0 0 (1, CD ro

g 3 09 a' OZ CD z 2 N..) rs.) o o 0 o Cc.) •-■•• •-••• • - C)

-4

Kentucky Power Company and AEP System-East Zone Actual Peak System Demand (MW)

2013

Kentucky Power Company AEP System-East Zone Peak Peak Peak Peak

Month Peak Day Hour Peak Day Hour

January 1,744 1/22/2013 8 26,233 1/25/2013 12 February 1,663 2/1/2013 9 24,681 2/1/2013 9 March 1,458 3/6/2013 10 22,216 3/6/2013 10 April 1,257 4/3/2013 7 18,487 4/3/2013 7 May 1,158 5/21/2013 16 20,640 5/30/2013 14 June 1,469 6/24/2013 15 25,793 6/24/2013 16 July 1,432 7/23/2013 15 24,662 7/10/2013 14 August 1,612 8/28/2013 15 27,041 8/30/2013 15 September 1,453 9/10/2013 15 26,208 9/10/2013 15 October 1,241 10/4/2013 17 21,728 10/4/2013 14 November 1,428 11/27/2013 18 22,012 11/26/2013 18 December 1,711 12/13/2013 9 25,270 12/12/2013 10

KPSC Administrative Case No. 387 Annual Resource Assessment




REQUEST

Load shape curves that show actual peak demands and weather-normalized peak demands (native load demand and total demand) on a monthly basis for the just competed calendar year. Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420).

RESPONSE

Pages 1 through 14 of Attachment 1 to this response provide 2013 monthly load duration curves for Kentucky Power Company's internal load. Pages 13 through 24 provide 2013 monthly load duration curves for Kentucky Power Company's system load. Pages 25 through 36 provide 2013 monthly load duration curves for AEP System-East's internal load. Pages 37 through 48 provide 2013 monthly load duration curves for AEP System-East's system load. The system load, for both Kentucky Power Company and AEP System-East, includes internal load and off-system sales.

Weather-normalized monthly internal peaks for Kentucky Power Company and AEP System-East are provided on Page 1 KPSC 1-1, Attachment 1. Weather-normalized system peaks have not been developed and therefore, are not available.

Please note that the AEP System-East internal and system hourly loads include loads for retail customers that receive generation services from an alternative supplier.


Kentucky Power Company January 2013 Load Duration Curve

(Internal Load)

1,600

1,400

1,200

1,000 ct)

ca

800 0) a)

600

400

200

0 > (1. • CD • •••1 c I2J DJ C) XI

as

o cn

•

0 0 B• -

amm o a m

-ari) R a :ill: CD ta 0

CD CD NJ 3 cn

O (D ZB NN• •;-1'

CO Nrt co s-4

ludgliM mil, wiuuuWlletiJixa FION NM .1 bi Mug, fwxui,blukilia

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

1,200

1,000

800 co

Kentucky Power Company February 2013 Load Duration Curve

(Internal Load)

1,400

600

400

200

0 aLr

1

0 > = CD

G 0 CD N 6 0

o cn 0 3

itT

oD CD a 3 > cr

— co CO c•D CD -,-° 0 cD CD IV iso 2— 3• 09 oZ o CD Z3 N.) NJ •

CD = 0 0 0 CO N

•

E,1 -92.1

,

51 101 151 201 251 301 351 401 451 501 551 601 651

Hours

0

1,400

1,200

1,000

800 co

co I

600 a

400

200

0 a

0 0) 0 00 7z1>

g. 0 CD

0 00

= (D 0. 33 .13 D C cr cn CD < (0 DJ CD ° Op CD ry

D- B . 65 moZ C.) ro •0 CD

N., 0 3 CD Z 3 --"=0 (D 0063

0 Co -x N 7,4%

51

101

151

201

251

301

351 401

451

501

551

601

651

701

Hours

Kentucky Power Company March 2013 Load Duration Curve

(Internal Load)

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

1,200

1,000

800

600 a) a)

400

200

0

0

■17.7i , uvnrawuninnwwoum atrunmmu~ua+ullunrtxmXHxi.Nr~P46aiNfM~uAKiu~

Kentucky Power Company April 2013 Load Duration Curve

(Internal Load)

Kentucky Power Company May 2013 Load Duration Curve

(Internal Load)

luit,..1■14 ill. U 11 ,h1.11.4.11stiMukoigiaplikliMEINilikAzimliognilit.idluligat040,1,1m11■WitlItliduutal..111arganalmukuoi 111.

1,200

1,000

800

400

200

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

0

1,200

1,000

800

a) 5

400

200

0 > 7- E -o c C1 CO CO C)

> 7J 0- CD CL cn Co3 O ID (D • Fo" o C) CD CD

a c 3 71

ea Es

(nrn Z co 0 CD cp CD na w

O CD Z 3 NJ —" 0 co 0 0 Ca

-I " 0 CO

' .

0 „ 110.11,141 U4=1,11144144 uaulal.1,1ivout,uat Milumuuta

1 51 101 151

201 251 301 351 401

451 501 551 601 651 701

Hours

Kentucky Power Company June 2013 Load Duration Curve

(Internal Load)

1,200

1,000

800

600 a)

a

400

200

0

■t.

51 101 151 201 251 301

351 401

451 501 551 601 651 701

Hours

Kentucky Power Company July 2013 Load Duration Curve

(Internal Load)

0 > a • -0 c

•

0 CD W D3 (-)

(

•

3_ ?,,=.

oco 0 -3— w cc, c cT, =

(1) CD 0- 3 ai

co sn ci) CD g NJ

3 c (D n o Z

-`1D.3 •

0 c 3 n Na 0 CD Z

O_ 0 a) CD C3 CO 4:a • CO

CO

•

CA3 CD

1,200

1,000

800

400

200

51 101 151 201 251 301 351 401 451

Hours

501 551 601 651 701

Kentucky Power Company August 2013 Load Duration Curve

(Internal Load)

1,200

1,000

800

400

200

0 —NdoI 1unmli1,4M1lldlxtlnluuaniwaiM1OAIWillllingaUYii 1.14101nlu4ktl0uu nYlulultulwuuuiWitllwuylu uLtudilnNll Ytlu110 ITAT

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

0 • a • ED, -0

C 0 CO w iv 0

CD a s 0 In t.

CD 1:3 3 (D

C Fo- 0 a w 2 - 3

-0 > O 19. CD -< (I+ CD 4 (D 0 CD DJ

— 3 cn ,0 Z (C)

9 cn 18 18

0

g ca -,CD 0 CO

03 s C\) 74. 03 --4

Kentucky Power Company September 2013 Load Duration Curve

(Internal Load)

601 551 451 501 351 401 51 101 151 201 251 301 651 701

1,200

1,000

800

cC

600

400

200

Hours

0.11.1411,1i 114■14Ialiu, 4,14..144 DI

Kentucky Power Company October 2013 Load Duration Curve

(Internal Load)

0 • a = (A m a• 0 CI) Ill c-s) 73 > co ocn 0

• ?IT 0 02_, • = CD > 2- 3 E3 > Faj — ° <

Nn N CD iv CD _CD (D 0 3N --,27 oz o CD Z B N n) • 7r: P -9 El 8 C'g W s — Ni ,=-1.C4-,

1,400

1,200

1,000

800

co a) cu 600

400

200

0 11.1,14ti 41,041 4111,14th pu4 .11 Nilig ;blatant 4 vala ut Set p>v bab bila 4 lb bat it 44 ti it 4 a masa 411,4 444104 atillatilthaliamlattatabalatititiblitlaitailiii

Kentucky Power Company November 2013 Load Duration Curve

(Internal Load)

1 a s o C") cp tj — c (73. o = CD cn

, < (D 0 FD"n CD a) IV

3 cn o Z cn -

O Z (so.) N.) •o OGG)

W—i4, C) CO W

— Co

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

Kentucky Power Company December 2013 Load Duration Curve

(Internal Load)

551 601 651 701 1 51 101 151 201 251 301 351 401 451 501

Hours

0

> a CD m

C 0 0) CD ED (-)

CD o_ cn 0 o (1, -•

FD- a CD W cD 0_ 3 -1 -0 >

Er CO >

a) 0 CD ° C-17 NJ CD g 3 LI - oZ

0 CD Z3 NJ N'

4=.• ° 0 CD 8

CO 7

1,400

1,200

1,000

800

ca a )

600 5

400

200

aludniaidap

Kentucky Power Company January 2013 Load Duration Curve

(System Load)

2,000

1,800

1,600

1,400

cn 1,200

1,000

0 2 800

600

400

200 0

> • CD • •-■ -13 a Cr) • rn 0

XI a_ > co a. cn 0 02 o CO cp C 0 =.

co -D° ••■■ W —

Cr a' CD tn cc. c'D psi

o CD Z 3 Ni Ni' 4.• • C3 03 CO

0 1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

1,800

1,600

1,400

1,200

1,000

a) • 800

600

400

200

0 .11 D Itilgi,a.glalt11.11■14I■1141IiitIlitiMIL1814t411{1.1111.111.11i1■ 111I111,11i111.1.1.1.11111■01itillittlik11.11111a/tiillthilliglatillialllit..1.111.1i.R.1,111.1414011.1.1glimilli11.1,1l411111111111.1.11.111.11.1.1Iidialltilatiallititfla.1.11g.IMINgIRIII5011,III.1141111.111:111iiilliaill1111.1141111.11111.11,111.11■1:t11111111fitilliNialligila fliallitAIMANThilthillEiiltil.11111.1113.1iillt.fia.1.11.1,.1.1.1atitililitiintig.R. ■giitri N IN

Kentucky Power Company February 2013 Load Duration Curve

(System Load)

0 > • ""- `

C 0 CD

CD Da (-)

7J 0_ > CD

CD CL 0 3

O 030

0 •—• • T m. co 5

CL 3 > v a- °

a) 0 rD LD 0 CD D.)

.19: 89 8° 03°Z

41, •"'" • (1) 0 03 CO

1 51 101 151 201 251 301 351 401 451 501

Hours

551 601

651

Kentucky Power Company March 2013 Load Duration Curve

(System Load)

1,600

1,400

1,200

1,000

2 600

400

200

0

= c 0 Cn 1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

ED

ED SD

CL

0 CD >

Cr) 0 0 Hours 0 CD (D = — c (17 o a m ,D (7',.. cp a. 3 -,

07, ,Z'.- > -,w u .°' (0 --- cn CD < CD l''' =".• -< —, (D (D m —' =' 3 w a) o z gl

CD Z ni Iv ° --* m o a, o so ow

at -. iv a c...) -,. -4

0 wiamn 1/.4:

Kentucky Power Company April 2013 Load Duration Curve

(System Load)

1,400

1,200

1,000

cn 800

cts

a) 600

400

200

0 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

0 > a c

•

C1 Cn • Al 0

70 FL

o (n • 0 c0 -'.

> = tU py 3 cn cr < cr.

0 CD N.) cu

cn m oZ cr) 3

Z i 3n

o co ry = o c) O GOfD 0 co

oo CA)

Kentucky Power Company May 2013 Load Duration Curve

(System Load)

1,400

1,200

1,000

1:4., 800

ca t

600

400

200

0

;Da c • 0 CD El] 11 C")

CD (7?) a > a

o (i) 0 0 3

cp

• _ te a

-0 >

>(i) g_

(aa) n ,cn - CD CD NJ

g 3 in) P c) o Z 3 r.) tsi •

0 8 ' Co 03

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

mi 1,1 dliq 11

701 151 201 251

301

351 401

451

501

551

601

651

1,600

1,400

1,200

600

400

200

Hours

0 51 101

luwigh .11

Kentucky Power Company June 2013 Load Duration Curve

(System Load)

Kentucky Power Company July 2013 Load Duration Curve

(System Load)

0

N7 m C ocn W 11 n

> 0 u) 0 0

CU (D C CT 0

-0

•

D CD Icr cn "

< CD 0 CD a) -'=- 3WWOZ o fD Z3 rs.) NJ -4, o rD OO CJ

7 0 CO CO O

1,600

1,400

1,200

1,000 U)

ca

800 a) a) 2

600

400

200

ipuOplhnii,11tlQhIhltwituNIidin.iW ,uts

51 101 151

201

251

301

351 401

451 501 551 601 651 701

Hours

Kentucky Power Company August 2013 Load Duration Curve

(System Load)

1

51

101

151

201

251

301

351 401

451

501

551

601

651

701

Hours

1,800

1,600

1,400

1,200

U)

1-',01,000

cs) 800 a

600

400

200

0 > 3 c o c

-0n a °

CD > cn 0 0 51- o =

(T) 0 (I)

> g 3 3 w > c° _< EP, < CD 0 FD" cn r,3 CD " 3 o Z c) 3 cn " o ZB N NJ

7 0 0 0 CO -^ (1) O co

co -4 NJ

Kentucky Power Company September 2013 Load Duration Curve

(System Load)

1,600

1,400

1,200

1,000 cn

800

5 600

400

200

Ali 141,1111411.1111■11.11th aria {1,11,41.11.141ai .1.1,1111.1.11 II it in an il.1 lillwatt 141 luMalut. litta mum AllititutivaNtailaaiulhkimaatilhidi

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

13 800

co

cv

(1) 600

Kentucky Power Company October 2013 Load Duration Curve

(System Load)

1,400

1,200

1,000

400

200

0 › ..

afIl 1 Ilfla WI , If if If I fl, 1, C 0 Cl)

301 351 401 451 501 551 601 651 701 a DO DO 0

Fp . .1 . , X ci. CD 0 C/3 n o 3

DO cp :,--

-0 -,... CD C-

cu r 3 7,

. ..,a)cr -- (1) C) ci7.- (c3V) (-<D N.) CD mrs., g 3 ,,, _,n) p Zo O CD Z 3 ro ro •

CO ' 9 SD "C' 8 COW CO —, NO ,-« CO —, --.4

iff mom

51

101

151

201

251

Hours

Kentucky Power Company November 2013 Load Duration Curve

(System Load)

1,600

1,400

1,200

1,000

a) 2

600

400

200

ilniIwMip1,11.11E Nib 1 NM GM o

351 401

451

501

Hours

0 1 51

101

151

201

251

301 11 I

551 601 651 t I 1,01

701

1,800

1,600

1,400

1,200

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

800

1

600

400

200

Kentucky Power Company December 2013 Load Duration Curve

(System Load)

AEP System-East Zone January 2013 Load Duration Curve

(Internal Load)

25,000

20,000

015,000

ca

(la

Ei0,000

5,000

IlMitgluom witrnioal.mitrn 1+41. I

1 51 101 151 201 251 301 351 401 451 501

Hours

0 > (4. 2c E c pcn cl)

?O.'" oCD w 0 0 nr c (17 0

> CD CL Ej

a an > (c g- < Ns)

Z

n) ry,=- c O PD

3 °Z

-O 0 if) C) 0 CO • CD Co

551

601

651

701

AEP System-East Zone February 2013 Load Duration Curve

(Internal Load)

25,000

20,000

.15,000

ammo

5,000

0 • ilt ill uglIttii■ I.IIIIiitaiirillaill.,1{1,d1,11,EmliLlmili,140.tlii1i■giillltititiaiilaigti,14.{illtiall1144

1 51 101 151 201 251 301 351

la Ill lotottlill

401 451 501 551 601 651

Hours

0 >

•

CD C7_

• " —0

C CO

DO CU 0

CD as a

o cn 0 c.) 3 C13 ct,

C) =

CD

g C77

1:1 > (I)

D.

2 3 a) > cr. CCI •-•• CD < N

cc, cD 0 CD FP CD Na 2c 3. now( :c 0Z

0 CD Z 2 n) • C7 GO

03

AEP System-East Zone March 2013 Load Duration Curve

(Internal Load)

0

CD; -10 C

•

D C/)

na

03 Ill

(DI o W 0 3 —

•

FD-CD 0 V .

= ) m o_ 3 cr CD

O

•

CU r7- N

•

(D-< r‘ 3 wc n OZ o CD Z 3 IV N.) • "•00,000.)

•"" 0 CO CO

•

03

20,000

18,000

16,000

14,000

012,000

10,000 a) a) E 8,000

6,000

4,000

2,000

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

AEP System-East Zone April 2013 Load Duration Curve

(Internal Load)

0

cDC

•

(!) a) DJ 0

73 as (D

oCO 0 o 3

CD (/) -0 CD 2,- Ei,)

> cD ■■•

0 CD cp CD

3

D.3 Z =. 3 cn

cn o N • — co co —

ro

18,000

16,000

14,000

12,000

17'310,000

ca

ami 8,000

6,000

4,000

2,000

•

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

20,000

18,000

16,000

14,000

(012,000

cu

10,000 as a) a) E 8,000

6,000

4,000

2,000

fi

51 101 151 201 251 301 351 401

Hours

miantaWm1

501 551

601 451 651 701

AEP System-East Zone May 2013 Load Duration Curve

(Internal Load)

501 551 601 651 701

AEP System-East Zone June 2013 Load Duration Curve

(Internal Load)

20,000

25,000

15,000

ca *.■

510,000

5,000

In717 ■ I I

51 101 151 201 251 301 351 401 451

Hours

0

AEP System-East Zone July 2013 Load Duration Curve

(Internal Load)

0

c D Cn CO SI) 0

CD >

o cn 0 0 3 cr) CD

> 2- > - (13 — cn (1) 0 FD"nD CD IV CD

2= 3 9 oz 0 0 Z 3 Ni Ni

0 4, * •

0 0

CO CO

CO ;•••• CO —4

25,000

20,000

N 15,000

cc

ca Cs)

E10,000

5,000

Itla htlYkN6104 buYiNlkApNliiuWNmxNbuaxWnumAUwXAniWWptltIA

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

AEP System-East Zone August 2013 Load Duration Curve

(Internal Load)

20,000

18,000

16,000

14,000

(n 12,000

ca

10,000

cu

2 8,000

6,000

4,000

2,000 0

> a

•

CD D OD

DJ CD C)

• as O co

▪

o cp C) (I) CD a. 3

(c) (1) (1) n g -< C') 3 &I)) z 1\) 3 o O CD Z 3 h00,,CDC)O3

4, • Cj CO CO i ts.) CJJ

11

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

15,000

ca

ca cs)

10,000

20,000

AEP System-East Zone September 2013 Load Duration Curve

(Internal Load)

25,000

5,000

iii 441 14 'hi Mt . 6 a a mum, N .1111 Adv. ita .171.17 0 701 51 101 151 201 251 301 351 401 451 501 551 601 651

Hours

AEP System-East Zone October 2013 Load Duration Curve

(Internal Load)

18,000

16,000

14,000

12,000

1,1 10,000

a) 8,000 2

6,000

4,000

2,000

0

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

0

o =

cn fa)

AEP System-East Zone November 2013 Load Duration Curve

(Internal Load)

20,000 -

18,000

16,000

14,000

(f) 12,000

10,000 cr) cs)

8,000

6,000

4,000

2,000

MI al .4( ITM Nadi Math ,[13 am al 4 14

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

111 144 IIuuIxlik ul Liura ASPokurkAMUw CIEFIlia Mak 41,1,14144 1u1., .11 A3Wxwaniata. Mar.,atrakal xAWpu agoalm

20,000

18,000

16,000

14,000

012,000

10' 000 CIS CIS

8,000

6,000

4,000

2,000

0

AEP System-East Zone December 2013 Load Duration Curve

(Internal Load)

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

AEP System-East Zone January 2013 Load Duration Curve

(System Load)

30,000

25,000

20,000

63 15,000

a) a)

10,000

5,000

151 201 251 301 0 WI 116 iaieli

51 101 111

351 401 451 501 551 601 651 701

Hours

25,000

20,000

10,000

AEP System-East Zone February 2013 Load Duration Curve

(System Load)

30,000

5,000

0 ■I l ■I,..I I ptnlilII11 I 1.11IIIRI1.1 1 ai(II ■IIiill1114. Wlcli Ri ,111141111.111111a IIIlI 111..Iliiill■16 , h WU. 1 Ilflaii.7111 II■ II. III Iti, 1i.1,11.101711iLlii■NIII

51

101

151

201

251

301 351

401

451

501

551

601

651

Hours

0 > CL • CD

• 0 Ci) CD CD

CD CL CD >

o c)

cp 3. C CT, 0

.11 1:13

> ce. 3 > a)

CO 0-n,

< CD a) CD C' CD cntn a) N.) co . 3 ch z co 9 CI) —n 0 O CD Z 3 N.) '

0,,, O 0 CO CO CO

CO s N.) a CO

5,000

0 1 51 101 151 201 251 301 351 401 451 501 651 551 601 701

Hours

25,000

20,000

015,000

210,000

AEP System-East Zone March 2013 Load Duration Curve

(System Load)

AEP System-East Zone April 2013 Load Duration Curve

(System Load)

20,000

18,000

16,000

14,000

012,000

ca

5'10,000 ET) a) 5 8,000

6,000

4,000

2,000

0 —1E 11 la a 51 101

111,taa.7 ■11atlialallailt. 7a7 151 201

altaii,771(

251 301 351 401 451 501 551 601 651 701

Hours

0

o vi • a) o • a s

O D) C

•

T 0 F = CD

> ° ,1 ?fi'

CD P•■• CD cD

g 3 c —9 0Z 0 CD Z3 NN'

= 0 0 0 C.J • g co

51 101 151 201 251 301 451 551 701 501 601 651 351 401

Hours

AEP System-East Zone May 2013 Load Duration Curve

(System Load)

25,000

5,000

u)15,000

ca

ca

0 510,000

20,000

Ita

101 151 201 251 301 351 401

Hours

451 501 551 601 651 alltaatalf,11

701

0 > COCL --0

c p CD E at 0

• — >

CD cn0 czi O ea (1, 57! - -

•

3 I3 'ID

•

6 — .< < CD c, cn CD m g 3 Lb) _9 p Zo o co Z 3 N N'

▪

•-•

0 CD 0

0 0 C.. CO) •

CO •-•1

1 51

AEP System-East Zone June 2013 Load Duration Curve

(System Load)

30,000

25,000

20,000

U)

15,000 CD

10,000

5,000

0

30,000

25,000

20,000

10,000

5,000

0

AEP System-East Zone July 2013 Load Duration Curve

(System Load)

1

0 x. a J c

•

C/) a a, 0 7J CD: ??,: a) CI) 0 3 O 0

• CD -

>

E4 0 >

="2: CD " -‹ rD a) CD ro 42' BrDWOZ to 3 t.n o o CD z 3 n.) tv •

o DOC 4, CD Co • co -> -4

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

AEP System-East Zone August 2013 Load Duration Curve

(System Load)

1.141 ail, I ml n1 't .

51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours

30,000

25,000

20,000

ca 15,000

a) 2

10,000

5,000

0

51 101 151 201 251 301 351 401

Hours

25,000

20,000

Cl)

cts

15' 000 (TI

a)

10,000

5,000

0 651 701 501 601 551 451

rdi o.,

AEP System-East Zone September 2013 Load Duration Curve

(System Load)

30,000

AEP System-East Zone October 2013 Load Duration Curve

(System Load)

25,000

20,000

co 15,000

ci 10,000

5,000

51

101

151

201

251

301

351 401

451

501

551

601

651

701

Hours

0 • a • 92,

U)E.

•

I. 0 • a ?,>_ cp cn 0 0 3 O c o = CD Li+

-0 >

E (c2 („,

0) 3 3 c? z 3 - 0 Z3 NN '

-4•=o ca roci CO 4, "- • • OJ 0 CO

AEP System-East Zone November 2013 Load Duration Curve

(System Load)

25,000

20,000

015,000

E10,000

5,000

51 101

0 • a = CD

c • 0 (I) fat o

CI

•

A — C> t. oCD — c 0 a cn ao • a. U

. • > co u, •.'•• CD 0 •-< CD

0 CD cp r,) =- 3 cn o

-"`i 3 cn o o CD Z3 NN' —'= O O O COO

• CD CO CO • CA)

151 201 251 301 351 401 451 501 551 601 651 701

Hours

AEP System-East Zone December 2013 Load Duration Curve

(System Load)

0 a 5P,

C D CO a cu 0 xi as cn ti 3 0 0 cp C it; Cl a 3 D

> D E- 3 17, r

8 C°

3 ID 0 Z 3 No 0 CD Z 3 Di CV • _4.".". a 0 s, C0 coC.J

OD -

30,000

25,000

20,000

U)

5 15, 000 as

2

10,000

5,000

1 51 101 151 201 251 301 351 401 451 501 551 601 651 701

Hours





REQUEST

Based on the most recent demand forecast, the base case demand and energy forecasts and high case demand and energy forecasts for the current year and the following four years. The information should be disaggregated into (a) native load (firm and non-firm demand) and (b) off-system load (both firm and non-firm demand). Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420).

RESPONSE

Page 1 of Attachment 1 to this response provides Kentucky Power Company's forecast of seasonal peak internal demands and annual internal energy requirements. In addition, the associated high forecast for seasonal peak internal demands and internal energy requirements are provided on this page.

The AEP-East Power Pool terminated effective January 1, 2014, therefore loads for the AEP System-East are no longer available.

The off-system energy sales forecasts for Kentucky Power Company are provided on Page 2 of Attachment 1 to this response. Forecasts of off-system peak demand for Kentucky Power Company have not been developed and therefore, such forecasts are not available. In addition, high forecasts for off-system energy sales and peak demand have not been developed and therefore, such forecasts are not available. The AEP-East Pool terminated effective January 1, 2014, therefore loads for the AEP System-East Power Pool are no longer available.


Kentucky Power Company Base and High Forecast

Energy Sales (GWH) and Seasonal Peak Demand (MW) 2014 - 2018

Summer

Preceding Winter Energy Sales

Peak Demand

Peak Demand Year Base High Base High Base High

2014 6,958 6,984 1,132 1,136 1,432 1,437 2015 6,953 6,984 1,133 1,138 1,431 1,437 2016 6,970 7,034 1,134 1,144 1,432 1,445 2017 6,975 7,095 1,137 1,156 1,431 1,456 2018 6,979 7,151 1,139 1,167 1,431 1,466

0 • a • CD —I C0 CC) 03 C)

a ?.,=. • o o n) rD C DT 0 a CD C/1 CD O. 3 ff > cs

• w 'CD ° CDN CD INDZ =- 3 cc) f CD

al O cn o — C D CD G 3 rsa NJ •

o mo m oc8 cc2 — —>

Kentucky Power Company Forecast Off-System Energy Sales (GWh)

2014 - 2018

KPCo Off-System

Year Sales

2014 2,284 2015 1,455 2016 1,002 2017 1,117 2018 1,041

> 94_ T3 c 0(1)

0

Co c I

o cp =• C 0 .

-4"; CI- 3 E3

>

w (I) < W

CO ° M

(1) CD IV

CD g 0 0 Z

cn - CD Z 3 Ni 0

070 0 02 eo


Calendar• Year 2013 Order Dated December 20, 2001



REQUEST

The target reserve margin currently used for planning purposes, stated as a percentage of demand. If changed from what was in use in 2001, include a detailed explanation for the change. Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420).

RESPONSE

Due to the October 1, 2004 integration of AEP's Eastern System into the PJM Interconnection, AEP is now required to comply with the PJM mandated reserve margin.

The installed reserve margin requirement (IRM) is recalculated each year, depending on five-year average generation reliability, PJM load shape, and assistance available from neighboring regions. In addition, KPCo's responsibility to PJM depends on its twelve-month history of generator reliability and its peak demand diversity in relation to the PJM total load. Attachment 1 to this response provides an example of the PJM reserve requirement calculation.

For the 2014/15 delivery period PJM has set the IRM at 15.9%. For the 2015/16 delivery period PJM has set the IRM at 15.3% and 15.6% for the 2016/17 delivery period. For planning purposes KPCo assumed a 15.6% IRM for all future years. The resulting KPCo reserve margin for 2014/15 is 37.4% as shown in Attachment 2 of the response to Item No. 5. (This compares with 12% that AEP used, based on our own determinations, from the late 1990s until 2004, and 15% prior to that.)

AEP East utilities that own generation have for decades operated as part of the AEP integrated public utility holding company system under the now-repealed Public Utility Holding Company Act of 1935. As part of that arrangement, those companies coordinated the planning and operations of their respective generating resources pursuant to the AEP Interconnection Agreement (Pool or Pool Agreement).


Calendar Year 2013 Order Dated December 20,2001


On December 17, 2010, in accordance with Section 13.2 of the Pool Agreement, each of the Pool members provided notice to the other members (and to American Electric Power Service Corporation (AEPSC), as agent) to terminate the Pool Agreement (which includes the Interim Allowance Agreement (IAA)), on January 1, 2014. As a result, effective January 1, 2014, Kentucky Power Company (KPCo) became responsible for its own generation resources and maintenance of an adequate level of power supply resources to individually meet its own load requirements for capacity and energy, including any required reserve margin.

The AEP-East Power Pool no longer exists, and forecasts regarding it are no longer available.


KPSC Administrative No. 387 Order Dated December 20, 2001

Calendar Year 2013 Annual Resource Assessment

Item No. 4 Attachment 1

Page 1 of 1

PJM Reserve Margin Example For 2014/15 Planning Year

Line Comment Factors

2 PJM Installed Reserve Margin (IRM) = 15.90%

3 PJM EFORd = 6.05% Based on 5-year average PJM EFORd

4 Forecast Pool Requirement (FPR) = 1.089 FPR = (1 + Line 2) * (1 - Line 3) 5 6 Obligations

7 Total Load Obligation = 1,156 With implied PJM diversity factor

8 UCAP Obligation = 1,259 Line 4 * Line 7

9 UCAP Market Obligations = 0

10 Total UCAP Obligation = 1,259 Line 8 + Line 9 11 12 Resources

13 Net ICAP = 2,250

14 KPCo EFORd = 20.77% MW-weighted average of Unit EFORds

15 Available UCAP = 1,783 Line 13 * (1- Line 14) 16 17 Position

18 Net UCAP Position = 524 Line 15 - Line 10

19 Net ICAP Position = 661 Line 18 / (1- Line 14) 20

21 Reserve Margin Percent = 94.6 Question 5 attached Exhibit 5-2, Column (16)

22 Reserve Percent Required By PJM = 37.4 Line 21 - (Line 19 / Question 5 attached Exhibit 5-2, Column (6)) * 100

ICPSC Administrative Case No. 387 Annual Resource Assessment




REQUEST

Projected reserve margins stated in megawatts and as a percentage of demand for the current year and the following 4 years. Identify projected deficits and current plans for addressing these. For each year identify the level of firm capacity purchases projected to meet native load demand. Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420)

RESPONSE

Attachment 1 to this response provides projected winter peak demands, capabilities, and margins for KPCo for the winter seasons 2013/14 through 2017/18.

Attachment 2 to this response provides projected summer peak demands, capabilities, and margins for KPCO for 2014 through 2018 since the AEP System — East Zone view is no longer applicable after January 1, 2014 as outlined in the response to Item No. 4.

The AEP-East Power Pool no longer exists, and forecasts regarding it are no longer available.

WITNESS: Ranie K Wohithas

Internal Demand

(0)

DSM

(b)

Committed Sales Total

Demand

Inter- ruptible Total Demand Demand

(0.1) 57.3 1.3 0.1 4.6

1121-1 I Nai

(2) 820 19 2

66

Capacity - MW Existing

Capacity & Chngs

(c)

Sales Capacity Additions Purchases Annual

Name/ MW Mkt. Purch. Identifier

Total Equivalent

Capacity. Net Sales

(d)

(7J (8) vl 1m

1,471 41 0 0 1,430 2,251 (e) 0 2,251 1,451 0 0 0 1,451 1,433 0 0 0 1,433 1,438 0 ecoPower (Biomass; 58.5 0 1,497

Margin (f)

% of MW Demand

Peak Demand - MW

(2p (3t (4, (5> 1 6)1,1)-(5)

1,440 (8) 0 1,432 0 1,432 1,442 (11) 0 1,431 0 1,431 1,445 (13) 0 1,432 0 1,432 1,446 (15) 0 1,431 0 1,431 1,448 (17) 0 1,431 0 1,431

Winter Season

2013/14 2014/15 2015/16 2016/17 2017/18

KENTUCKY POWER COMPANY Projected Winter Peak Demands, Generating Capabilities, and Margins

Notes: (a) Based on July 2013 Load Forecast.

(b) Existing plus approved and projected "Passive EE, and WO.

(c) Reflects KPCo's ownership ratio of the following winter capability assumptions. EFFICIENCY IMPROVEMENTS:

2017/18: Rockport 1: 5 MW (turbine) GAS-CONVERSION RERATES:

2016/17: Big Sandy 1: (18 MW) ASSUMED RETIREMENTS FOR PLANNING PURPOSES:

201506: Big Sandy 2: 800 MW

(d) Includes KPCo's share of: RPM Auction Sales of 700 MW (UCAP) in 2013/14

Sale of 13 MW to Duke in 2013/14 3.6 MW capacity credit from SEPA's Philpot Dam via Blue Ridge contract in 2013/14

(e) Reflects the ownership transfer of 50% of Mitchell Units 1 & 2 effective 2014/15 (780 MW)

(f) Represents margin relative to KPCo peak demand, not PJM requirement.

O

C p cn

DJ DJ 0 Fr;

CD a r:L. rn 0 ID 3

o —. c (IT M. a = CD 0- 3 > cr 2,71 5

° CD cc, m IV CD 3 ,,, o z 3 - 0 Z3 N r..) • O .0 O 8 cow

—

Peak Demand - MW

Inter- Net

ruptible Other

Internal Demand DSM Net KPCo Committed Total

Demand Response Internal Sales KPCo (a) (b) (c) Demand Demand

1,157 0 (1) 1,156 0 1,156 1,180 0 (2) 1,178 0 1,178 1,198 0 (3) 1,195 0 1,195 1,066 0 (3) 1,063 0 1,063 1,069 0 (5) 1,064 0 1,064

Summer Season

2014 2015 2016 2017 2018

KENTUCKY POWER COMPANY

Projected Summer Peak Demands, Generating Capabilities, and Margins

Existing Capacity

it Planned Changes

(4)

Capacity - MW Planned

Capacity Additions

Total Capacity

2,250

Reserve Margin Reserve Margin PJM ICAP Position After Interruptible Ix/ New Capacity Before Interruptible

w/ New Capacity After Interruptible w/ New Capacity

Committed Name/

Net Sales Identifier Annual

MW Purch.

Reserve% Required By

PJM

Net Position

MW MW % of

Demand MW % of

Demand

2,250

oil !lc,

1,094 94.6

(1,i1Z)-01

1,094 94.6 37.4 661 1,450 1,450 272 23.1 272 23.1 16.5 60 1,432 1,432 237 19.8 237 19.8 17.7 25 1,432 ecoPcnver(Biontass) 58.5 1,491 428 40.3 428 40.3 17.0 219 1,438 1,497 433 40.7 433 40.7 17.9 243

Notes: (a) Based on (July 2013) Load Forecast (With implied PJM diversity factor)

(b) Demand Response approved by PJM in the prior planning year plus forecasted "Active" DR

(c) For PJM planning purposes, the ultimate impact of new DSM is 'delayed' about 4 years to represent the ultimate recognition of these amounts through the PJM-originated load forecast process.

(d) Reflects KPCo's ownership ratio of the followirm summer capability assumptions: EFFICIENCY IMPROVEMENTS:

2018: Rockport 1 6 MW (turbine) GAS CONVERSION BERATES:

2016: Big Sandy 1 (18 MW) ASSUMED RETIREMENTS FOR PLANNING PURPOSES:

2015: Big Sandy 2:800 MW

O

a • " C t7 (r) M CU 0

(/)

•

CL f c.D > a. fit 0 0 o 133

3

C o CD C. ci — re 3

> S14 sr 02.

11) — < MOS. W rg ta

o (t. —s

3 Z re N

O :0 5 c0 8 WO IV 01 —s





REQUEST

A list that identifies scheduled outages or retirements of generating capacity during the current year and the following four years.

RESPONSE

Please see Attachment 1 to this response.


KPSC Administrative No. 387 Order Dated December 20, 2001



Page 1 of 1 Big Sandy Plant

Year Unit 1 Unit 2

2014 4 weeks 4 weeks

2015 More than 4 weeks No Outage Scheduled/Planned Retirement

2016 More than 4 weeks Retired

2017 *No Outage Scheduled Retired

2018 *No Outage Scheduled Retired

*The Company currently is seeking a Certificate of Convenience and Public Necessity to

convert Big Sandy Unit 1 to natural gas.

Mitchell Plant

Year Unit 1 Unit 2

2014 Less than 4 weeks Less than 4 weeks

2014 4 Weeks

2015 4 weeks More than 4 weeks

2015 More than 4 weeks

2016 Less than 4 weeks

2017 Less than 4 weeks Less than 4 weeks

2018 Less than 4 weeks More than 4 weeks





REQUEST

Identify all planned base load or peaking capacity additions to meet native load requirements over the next 10 years. Show the expected in-service date, size and site for all planned additions. Include additions planned by the utility, as well as those by affiliates, if constructed in Kentucky or intended to meet load in Kentucky. Please provide the information for both Kentucky Power Company individually and the AEP-East Power Pool (pursuant to the Commission's December 13, 2004 Order in the Rockport UPSA extension, Case No. 2004-00420).

RESPONSE

Kentucky Power Company entered into a contract agreement to purchase the output of the 58.5 MW ecoPower Hazard LLC biomass plant, located near Hazard, Kentucky. Generation from the ecoPower facility is expected to begin in 2017.

As a result of the January 1, 2014 termination of the AEP Interconnection Agreement ("pool agreement"), a mix of generation resources is needed to meet KPCo's projected capacity needs, on a stand-alone basis, through 2024. Currently no additional resources aside from the aforementioned ecoPower purchase are planned for KPCo.




Item No. 8a & b Page 1 of 1


REQUEST

The following transmission energy data for the just completed calendar year and the forecast for the current year and the following four years:

a. Total energy received from all interconnections and generation sources connected to the transmission system.

b. Total energy delivered to all interconnections on the transmission system

RESPONSE

Please see Attachment 1 to this response.

WITNESS: Ranie K Wolmhas

8(a) All quantities represent metered values.

Received from MINIM 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 (Actual) (Actual) "Actual) (Actual) (Actual) (Actual)

Appalachian Power (1) 7,826,055 4,637,687 5,042,019 4,230,880 4,338,641 4,631,523 (4) (4) (4) (4) (4) Ohio Power (1) 8,832,135 10,872,502 11,316,622 11,393,398 10,644,478 10,066,676 (4) (4) (4) (4) (4) East Ky Power Coop 402,847 481,140 412,663 510,543 394,193 386,124 (4) (4) (4) (4) (4) LGE(Kentucky Utilities) 810,871 933,540 884,267 780,095 730,063 565,818 (4) (4) (4) (4) (4) TVA 448,365 523,823 604,964 654,875 551,305 566,823 (4) (4) (4) (4) (4) Illinois Power Co. (2) 33,190 35,408 46,376 59,956 136,798 111,628 (5) (5) (5) (5) (5) Illinois Power Co. (3) 23,629 16,769 20,742 26,552 101,471 89,276 (5) (5) (5) (5) (5)

Big Sandy Generating Plant 6,021,182 6,262,165 6,552,258 6,372,925 2,661,344 2,764,447 2,177,950 972,794 76,586 100,957 109,140 *Mitchell 1 & 2 (KPCo Share 50%) 3,121,055 3,713,573 4,544,876 4,578,073 4,548,186 *Rockport Purchase Power Agreement 2,082,336 2,006,845 2,482,695 2,487,699 2,455,178

7,381,341 6,693,211 7,104,157 7,166,729 7,112,505 8(b) All quantities represent metered values.

Delivered to (NIINM: 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Appalachian Power (1) 15,917,326 15,589,080 16,340,364 15,816,607 11,673,720 11,550,084 (4) (4) (4) (4) (4) Ohio Power (1) 360,333 465,000 466,832 494,931 526,005 371,910 (4) (4) (4) (4) (4) East Ky Power Coop 213,189 154,558 154,000 176,721 206,810 136,118 (4) (4) (4) (4) (4) LGE(Kentucky Utilities) 14 11 23 1 36 0 (4) (4) (4) (4) (4) TVA 62 0 0 1 0 0 (4) (4) (4) (4) (4) Vanceburg and Olive Hill 101,657 95,284 103,058 95,607 95,525 95,502 (6) (6) (6) (6) (6)

Notes: (1) An AEP System company. (2) At the Riverside independent power producing plant (IPP) in Lawrence County, KY. (3) At the Foothills independent power producing plant (IPP) in Lawrence County, KY. (4) The Company does not forecast metered interchange; however, the future years' energy flows are not expected

to be materially different from the year 2013 actuals. (5) The Company does not, and can not, forecast energy production output from an IPP. (6) This is a 3rd Party Firm Load that is served by Kentucky Power.

*Kentucky Power resources that are not connected to the Kentucky Power Transmission System

O Ft

c t7 0) tu (*)

• a › B • rD -•

m 2. = m Co > a) a F3

a".?

0 P co _< < •-■• >

co re

3 co m (D to 3 NJ NJ•

O z 9. CD 8 Eg



Item No. 8c & d Page 1 of 2


REQUEST

The following transmission energy data for the just completed calendar year and the forecast for the current year and the following four years.

c. Peak load capacity of the transmission system.

d. Peak demand for summer and winter seasons on the transmission system.

RESPONSE

c. The maximum amount of electric energy that can be transmitted through a transmission network is a function of the level of the load and generation connected to the transmission system as well as the level and direction of transmission service into, out of, and through the network. Therefore, the 'Peak Load Capacity' of the transmission system cannot be quantified as a single value.

The Kentucky Power transmission system capacity is designed to serve the existing and projected load. It is also designed to reliably serve the load for any single contingency outage of a line, transformer or generator. The existing transmission system together with the capacity additions listed in response to Item No. 9 will provide adequate capacity to serve the existing and projected loads shown in the table below.



Item No. 8c & d Page 2 of 2


d. The actual summer and winter peak demands are shown below for 2013/2014. In addition, forecasted summer and winter peak demands for 2014 through 2018 are also shown in the table below.

Kentucky Power Company Seasonal Peak Demand

Actual 2013 and Forecast 2014-2018

Year Summer Preceding Winter

Peak Demand Peak Demand (MW) (MW)

2013 1,138* 1,409* 2014 1,132 1,645* 2015 1,133 1,432 2016 1,134 1,431 2017 1,137 1,431 2018 1,139 1,432

*Based on Actual Load Data






REQUEST

Identify all planned transmission capacity additions for the next 10 years. Include the expected in-service date, size and site for all planned additions and identify the transmission need each addition is intended to address.

RESPONSE

Please see Attachment 1 to this response. Confidential treatment is being sought for portions of the attachment.


KPSC Administrative Case No. 387 Order Dated December 20, 2001



Page 1 of 2 The following projects are planned for the Kentucky Power Company transmission system: REDACTED

Hazard Area Improvements Project — This project, which includes the Bonnyman-Softshell line, will provide another 138 kV source into the Hazard area of eastern Kentucky. Station and line work will be required. This project will provide single contingency reliability to the Hazard area subtransmission system and double contingency reliability to the area 138 kV system. Current projected in-service date is December 2014.

Big Sandy Area Improvements — This project will install a second 765/345 kV transformer at the Baker 765 kV station. This project will provide double contingency reliability to the critical transmission system. The anticipated in-service date would be June 2015.

Thelma and Busseyville Station Upgrades — This project will address thermal overload concerns on the Big Sandy-Thelma 138kV circuit. Station and line work will be required. This project will increase the thermal rating on the Big Sandy-Thelma 138kV line. Current projected in-service date is June 2015.

Dorton 138kV Circuit Breaker Project- This project will install three 138kV circuit breakers and one circuit switcher at Dorton Station. The project will solve thermal loading concerns and operational reliability concerns. The current projected in-service date is June 2015.

Johns Creek and Stone Station Upgrades — This project will install two new 138 kV circuit breakers at Johns Creek and one 138kV circuit breaker at Stone Station. This project will provide additional reliability to customers, operational flexibility, and voltage support under contingency conditions. Current projected in-service date is June 2015.

Cedar Creek Station Upgrades — This project will install two new 138 kV circuit breakers at Cedar Creek Station. This project will provide operational benefits and provide voltage support for single contingency line outages. Current projected in-service date is April 2016.

KPSC Administrative Case No. 387 Order Dated December 20, 2001



Page 2 of 2 REDACTED

KPSC Administrative Case No. 387 Supplemental Response

PSC Letter Dated May 31, 2013 Page 1 of 2

Kentucky Power Company — Electricity Price in Forecast Modeling

Kentucky Power Company confirms that it takes electricity price and the effects of its changes into consideration in every load forecast, including the forecast filed on April 30, 2014, in Administrative Case No. 387. As was further requested in the Commission's letter dated May 31, 2013, the following provides a discussion of the impacts of prices on electricity sales and how price is accounted for in the load forecast.

An understanding of the relationship between energy prices and energy consumption is fundamental to developing a forecast of electricity consumption. In theory, the effect of a change in the price of a good on the consumption of that good can be disaggregated into two effects, the "income" effect and the "substitution" effect. The income effect refers to the change in consumption of a good attributable to the change in real income incident to the change in the price of that good. For most goods, a decline in real income would induce a decline in consumption. The substitution effect refers to the change in the consumption of a good associated with the change in the price of that good relative to the prices of all other goods. The substitution effect is assumed to be negative in all cases; that is, a rise in the price of a good relative to other, substitute goods would induce a decline in consumption of the original good. Thus, if the price of electricity were to rise, the consumption of electricity would fall, all other things being equal. Part of the decline would be attributable to the income effect; consumers must make decisions on how to allocate their budget to purchase electricity services and other goods and services after the price of electricity rises. Part would be attributable to the substitution effect; consumers would substitute relatively cheaper fuels for electricity once its price had risen.

The magnitude of the effect of price changes on consumption differs over different time horizons. In the short-term, the effect of a rise in the price of electricity is severely constrained by the ability of consumers to substitute other fuels or to incorporate more electricity-efficient technology. (The fact that the Company's short-term energy consumption models do not include price as an explanatory variable is a reflection of the belief that this constraint is severe). In the long-term, however, the constraints on substitution are lessened for a number of reasons. First, durable equipment stocks begin to reflect changes in relative energy prices by favoring the equipment using the fuel that was expected to be cheaper; second, heightened consumer interest in saving electricity, backed by willingness to pay for more efficiency, spurs development of conservation technology; third, existing technology, too expensive to implement commercially at previous levels of energy prices, becomes feasible at the new, higher energy prices; and fourth, normal turnover of electricity-using equipment contributes to a higher average level of energy efficiency.

KPSC Administrative Case No. 387 Supplemental Response

PSC Letter Dated May 31, 2013 Page 2 of 2

For these reasons, energy price changes are expected to have an effect on long-teiiii energy consumption levels. As a reflection of this belief, most of the Company's long-term forecasting models, including the residential, commercial, manufacturing and mine power energy sales models, incorporate the price of electricity as an explanatory variable. The residential Statistically Adjusted End-Use (SAE) Model uses price in development of explanatory variables. There are a variety of short- and long-run elasticities utilized in this analysis. In addition to electricity prices, the residential SAE model utilizes the price of natural gas and associated cross-price elasticities. Likewise, the commercial SAE model incorporates electricity price and an associated price elasticity to develop explanatory variables. Manufacturing and mine power have price as an explanatory variable. In these cases, the coefficient of the price variable provides a quantitative measure of the sensitivity of the forecast value to a change in price. The manufacturing model incorporates the price of natural gas to consumers in the state of Kentucky.

Documents

STTTFc DT - Kentuckypsc.ky.gov/PSCSCF/Post Case Referenced Correspondence/2000 cas… · STTTFc "DT :,,A wilmmezkas AliORNEIS April 30, 2014 Mark R. Overstreet (502) 209-1219 (502)