UManitoba Hydro Undertaking # 1 UResponse U: /kWh applied ... · Undertaking # 1 Transcript Page # 145 Workshop Date May 11, 2016 May 30, 2016 Page 2 of 6 Schedule B1 Manitoba Hydro

Undertaking # 1 Transcript Page # 145

Workshop Date May 11, 2016

May 30, 2016 Page 1 of 6

2015 COST OF SERVICE METHODOLOGY REVIEW

UManitoba Hydro Undertaking # 1 Manitoba Hydro to provide all PCOSS schedules (including Schedule B2 & B3, without net export revenue and Schedules D1 & D2) for the scenario Hydro has already run where the marginal weighted energy "capacity adder" is added on for only the winter peak period.

UResponse U: The following version of PCOSS14-Amended includes a capacity adder of 5.74¢/kWh applied to

the 661 Peak Winter hours only. The change in RCC provided is in comparison to PCOSS14-Amended, which included an adder in all annual peak hours. The Customer Demand Energy Cost Analysis and Functional Breakdown provided have not been reduced by Net Export Revenue.



May 30, 2016 Page 2 of 6

Schedule B1

Man

itoba

Hyd

roPr

ospe

ctiv

e C

ost O

f Ser

vice

Stu

dyM

arch

31,

201

4R

even

ue C

ost C

over

age

Ana

lysi

sC

apac

ity

Add

er A

ppli

ed to

Pea

k W

inte

r H

ours

Onl

yS

U M

M A

R Y

C

hang

eC

ost

Cos

tC

hang

eC

hang

eC

lass

Net

Exp

ort

Tot

alR

CC

%le

ssle

ssin

in

Tot

al C

ost

Rev

enue

Rev

enue

Rev

enue

Cur

rent

NER

NER

RC

CN

ERC

usto

mer

Cla

ss($

000)

($00

0)($

000)

($00

0)R

ates

Res

iden

tial

636,

405

58

8,63

0

42,3

07

630,

937

99

.1%

594,

098

4,06

3.6

-0

.7%

Gen

eral

Ser

vice

- Sm

all N

on D

eman

d13

2,95

3

135,

035

8,

591

143,

626

10

8.0%

124,

362

(86.

3)

0.

0%G

ener

al S

ervi

ce -

Smal

l Dem

and

138,

746

13

6,08

0

8,95

3

14

5,03

3

104.

5%12

9,79

4

(5

9.0)

0.0%

Gen

eral

Ser

vice

- M

ediu

m19

9,95

9

186,

797

13

,001

19

9,79

7

99.9

%18

6,95

8

(9

94.2

)

0.5%

Gen

eral

Ser

vice

- La

rge

0 - 3

0kV

99,2

31

84,9

56

6,43

5

91

,391

92

.1%

92,7

96

(852

.5)

0.

8%G

ener

al S

ervi

ce -

Larg

e 30

-100

kV*

61,3

95

57,8

08

4,04

9

61

,857

10

0.8%

57,3

46

(459

.1)

0.

8%G

ener

al S

ervi

ce -

Larg

e >1

00kV

*20

3,66

5

189,

258

13

,301

20

2,55

8

99.5

%19

0,36

5

(1

,658

.5)

0.9%

*Inc

lude

s C

urta

ilmen

t Cus

tom

ers

SEP

968

82

6

-

826

85

.4%

968

-

0.

0%

Are

a &

Roa

dway

Lig

htin

g22

,122

21

,630

45

6

22,0

86

99.8

%21

,666

88

.3

-0.4

%

Tot

al G

ener

al C

onsu

mer

s1,

495,

443

1,40

1,01

9

97

,092

1,

498,

111

100.

2%1,

398,

351

42

.3

0.0%

Die

sel

9,94

8

6,

612

668

7,

280

73.2

%9,

280

(42.

3)

0.

4%

Expo

rt24

7,47

3

345,

233

(9

7,76

1)

247,

473

10

0.0%

6,59

7.2

Tot

al S

yste

m1,

752,

864

1,75

2,86

4

-

1,

752,

864

100.

0%



May 30, 2016 Page 3 of 6

Schedule B2 (Not reduced by Net Export Revenue)

Man

itoba

Hyd

ro

Pros

pect

ive

Cos

t Of S

ervi

ce S

tudy

- M

arch

31,

201

4

Cus

tom

er, D

eman

d, E

nerg

y C

ost A

naly

sis

C

apac

ity

Add

er A

ppli

ed to

Pea

k W

inte

r H

ours

Onl

y

SU

MM

AR

Y

C U

S T

O M

E R

D

E M

A N

DE

N E

R G

Y

Bill

able

Met

ered

Cos

tN

umbe

r of

Uni

t Cos

tC

ost

%

Dem

and

Uni

t Cos

tC

ost

Ener

gyU

nit C

ost

Cla

ss($

000)

Cus

tom

ers

$/M

onth

($00

0)R

ecov

ery

MV

A$/

KV

A($

000)

mW

h¢/

kWh

Res

iden

tial

128,

894

486,

987

22.0

6

190,

890

0%n/

an/

a31

6,62

0

7,

404,

453

6.85

**

GS

Smal

l - N

on D

eman

d25

,670

53,7

7839

.78

36

,054

0%

n/a

n/a

71,2

29

1,

605,

511

6.68

**

GS

Smal

l - D

eman

d8,

722

12,4

9258

.18

41

,843

38

%2,

390

6.63

88

,181

2,04

7,71

55.

58

Gen

eral

Ser

vice

- M

ediu

m7,

628

1,97

432

2.01

59

,714

87

%7,

302

7.15

13

2,61

7

3,

174,

662

4.41

Gen

eral

Ser

vice

- La

rge

<30k

V3,

837

288

n/a

25,8

00

100%

4,04

27.

33

*69

,594

1,70

2,48

14.

09

Gen

eral

Ser

vice

- La

rge

30-1

00kV

2,65

240

n/a

9,63

7

100%

2,89

44.

25

*49

,106

1,32

7,21

03.

70

Gen

eral

Ser

vice

- La

rge

>100

kV

2,45

016

n/a

21,0

27

100%

8,40

92.

79

*18

0,18

8

4,

903,

742

3.67

SEP

326

2993

5.95

13

2

0%

n/a

n/a

509

26,5

002.

42

**

Are

a &

Roa

dway

Lig

htin

g16

,655

155,

024

8.95

2,25

5

0%n/

an/

a3,

211

10

0,48

75.

44

**

Tot

al G

ener

al C

onsu

mer

s19

6,83

371

0,62

838

7,35

3

25

,038

911,

257

22,2

92,7

61

Die

sel

235

755

25.9

1

352

0%n/

an/

a9,

361

13

,754

70.6

2

**

Expo

rtn/

an/

an/

a21

,172

0%

n/a

n/a

226,

300

9,01

3,00

0

2.

75

***

Tot

al S

yste

m19

7,06

871

1,38

340

8,87

7

25

,038

1,14

6,91

9

31,3

19,5

15

* - i

nclu

des

reco

very

of c

usto

mer

cos

ts**

- in

clud

es re

cove

ry o

f dem

and

cost

s**

* -in

clud

es re

cove

ry o

f cus

tom

er a

nd d

eman

d co

sts



May 30, 2016 Page 4 of 6

Schedule B3 (Not reduced by Net Export Revenue)

Man

itoba

Hyd

roPr

ospe

ctiv

e C

ost O

f Ser

vice

Stu

dy -

Mar

ch 3

1, 2

014

Func

tiona

l Bre

akdo

wn

Cap

acit

y A

dder

App

lied

to P

eak

Win

ter

Hou

rs O

nly

S U

M M

A R

Y

Gen

erat

ion

Tra

nsm

issi

onSu

btra

nsm

issi

onD

istr

ibut

ion

Dis

trib

utio

nT

otal

Cos

tC

ost

Cos

t C

ost

Cus

t Ser

vice

Plan

t Cos

tC

lass

($00

0)($

000)

%($

000)

%($

000)

%C

ost (

$000

)%

($00

0)%

Res

iden

tial

636,

405

315,

252

49.5

%49

,801

7.8%

33,0

905.

2%71

,153

11.2

%16

7,10

926

.3%

Gen

eral

Ser

vice

- Sm

all N

on D

eman

d13

2,95

3

70

,932

53

.4%

10,6

368.

0%5,

973

4.5%

18,0

8213

.6%

27,3

2920

.6%

Gen

eral

Ser

vice

- Sm

all D

eman

d13

8,74

6

87

,809

63

.3%

12,5

919.

1%6,

881

5.0%

4,32

13.

1%27

,144

19.6

%

Gen

eral

Ser

vice

- M

ediu

m19

9,95

9

13

2,04

6

66

.0%

19,3

279.

7%9,

514

4.8%

6,57

63.

3%32

,496

16.3

%

Gen

eral

Ser

vice

- La

rge

<30k

V99

,231

69,2

93

69.8

%9,

990

10.1

%4,

756

4.8%

3,60

73.

6%11

,584

11.7

%G

ener

al S

ervi

ce -

Larg

e 30

-100

kV61

,395

48,8

88

79.6

%6,

222

10.1

%3,

632

5.9%

2,58

14.

2%71

0.1%

Gen

eral

Ser

vice

- La

rge

>100

kV

203,

665

179,

395

88.1

%21

,820

10.7

%0

0.0%

2,42

11.

2%29

0.0%

SEP

968

509

52.6

%13

213

.7%

00.

0%30

931

.9%

171.

7%

Are

a &

Roa

dway

Lig

htin

g22

,122

3,19

8

14.5

%32

91.

5%45

12.

0%54

72.

5%17

,598

79.5

%

Tot

al G

ener

al C

onsu

mer

s1,

495,

443

90

7,32

3

60

.7%

130,

848

8.7%

64,2

964.

3%10

9,59

77.

3%28

3,37

818

.9%

Die

sel

9,94

8

9,36

1

94.1

%0

0.0%

00.

0%0

0.0%

587

5.9%

Expo

rt24

7,47

3

22

5,55

0

91

.1%

21,9

228.

9%0

0.0%

00.

0%0

0.0%

Tot

al S

yste

m1,

752,

864

1,

142,

235

65

.2%

152,

770

8.7%

64,2

963.

7%10

9,59

76.

3%28

3,96

516

.2%



May 30, 2016 Page 5 of 6

Schedule D1

2014 Prospective Cost of Service StudyProspective Peak Load Responsibility Report

Seasonal Coincident Peaks (2 CP) at Generation Peak

Winter SUMMER D14

Forcast Total Energy @ Generation

Avg % of

Yearly Energy

Estimated Seasonal Energy

Seasonal CP LF

Estimated Seasonal Demand

Avg % of

Yearly Energy

Estimated Seasonal Energy

Seasonal CP LF

Estimated Seasonal Demand

2CP Estimated Demand

Residential Residential 8,541,179,836 63.0% 5,380,943,297 70.1% 1,767,057 37.0% 3,160,236,539 73.0% 980,320 1,373,688 Seasonal 102,206,821 43.6% 44,603,685 162.5% 6,319 56.4% 57,603,136 162.5% 8,027 7,173 Water Heating 16,204,306 49.5% 8,021,131 126.0% 1,465 50.5% 8,183,175 126.0% 1,471 1,468 Total Residential 8,659,590,963 5,433,568,112 1,774,841 3,226,022,850 989,817 1,382,329

GS Small Non-Demand 1,854,567,658 57.8% 1,071,940,106 73.9% 333,915 42.2% 782,627,551 69.7% 254,269 294,092 Demand 2,363,968,908 56.1% 1,326,186,557 76.9% 396,998 43.9% 1,037,782,351 78.2% 300,518 348,758

4,218,536,565 2,398,126,663 730,913 1,820,409,902 554,787 642,850 Seasonal 5,707,215 20.0% 1,141,443 162.5% 162 80.0% 4,565,772 162.5% 636 399 Water Heating 5,558,687 49.7% 2,763,057 106.0% 600 50.3% 2,795,630 106.0% 597 599 Total GSS 4,229,802,467 2,402,031,163 731,675 1,827,771,304 556,020 643,848

General Service - Medium 3,653,690,359 53.0% 1,936,455,890 79.0% 564,275 47.0% 1,717,234,469 76.8% 506,337 535,306

General Service - Large0 - 30 Kv 1,942,588,302 50.6% 982,949,681 81.6% 277,301 49.4% 959,638,621 78.8% 275,773 276,537

30 - 100 Kv 1,226,541,957 52.2% 640,254,901 92.2% 159,857 47.8% 586,287,055 105.8% 125,486 142,672 30 - 100 Kv - Curtailed Cust 248,944,081 49.2% 122,480,488 102.3% 27,561 50.8% 126,463,593 95.9% 29,862 28,712

Over 100 Kv 3,111,483,050 52.7% 1,639,751,567 96.9% 389,551 47.3% 1,471,731,483 104.8% 318,008 353,780 Over 100 Kv - Curtailed Cust 2,259,539,507 50.1% 1,132,029,293 105.1% 247,951 49.9% 1,127,510,214 104.3% 244,798 246,374

Total G.S.- Large 8,789,096,897 4,517,465,930 1,102,221 4,271,630,966 993,927 1,048,074

Street Lighting 117,520,773 57.5% 67,618,144 86.7% 17,964 42.5% 49,902,629 0.0% - 8,982

Total - General Consumers 25,449,701,458 14,357,139,240 4,190,977 11,092,562,218 3,046,102 3,618,539

Dependable Exports 5,010,288,250 37.6% 1,883,868,382 111.6% 388,594 62.4% 3,126,419,868 89.3% 792,806 590,700 Opportunity Exports 4,729,711,750 37.6% 1,778,371,618 111.6% 366,833 62.4% 2,951,340,132 89.3% 748,409 557,621 Total Extra Provincial 9,740,000,000 3,662,240,000 755,428 6,077,760,000 1,541,214 1,148,321

Integrated System 35,189,701,458 18,019,379,240 4,946,404 17,170,322,218 4,587,316 4,766,860

Total Surplus Energy 30,478,903



May 30, 2016 Page 6 of 6

Schedule D2

Ener

gy (M

W.h

) Wei

ghte

d by

Mar

gina

l Cos

t (D

omes

tic

and

Dep

enda

ble

Expo

rts)

Spr

ing

Sum

mer

Fall

Win

ter

2013

/14

Fore

cast

Pea

kS

houl

der

Off

Pea

kP

eak

Sho

ulde

rO

ff P

eak

Pea

kS

houl

der

Off

Pea

kP

eak

Sho

ulde

rO

ff P

eak

Tot

alW

eigh

ted

Ener

gy/1

000

Res

iden

tial

8,54

1,17

9,83

6

Res

iden

tial

272,

001,

550

530,

434,

386

341,

228,

942

532,

088,

120

973,

550,

491

502,

930,

598

356,

769,

291

648,

991,

849

410,

273,

989

972,

624,

664

1,78

5,68

9,26

7

1,21

4,59

6,68

7

8,54

1,17

9,83

6

31

,766

,747

R

es F

RW

H16

,204

,306

R

esid

entia

l FR

WH

642,

320

1,25

2,59

9

805,

798

1,43

0,88

9

2,61

8,06

8

1,35

2,47

9

680,

444

1,23

7,78

3

782,

491

1,32

2,34

8

2,42

7,76

3

1,65

1,32

5

16,2

04,3

06

56

,522

Res

Sea

sona

l10

2,20

6,82

1

R

esid

entia

l Sea

sona

l4,

309,

005

8,

403,

057

5,

405,

695

10

,173

,061

18

,613

,436

9,

615,

594

4,

018,

892

7,

310,

685

4,

621,

605

7,

279,

742

13

,365

,234

9,

090,

814

10

2,20

6,82

1

348,

799

G

S Sm

all N

on D

eman

d1,

854,

567,

658

G

S Sm

all N

on-D

eman

d68

,055

,877

12

4,24

4,79

5

73

,605

,024

15

6,94

6,67

7

23

1,22

9,51

9

13

1,17

5,91

8

80

,806

,229

13

8,72

7,00

1

84

,341

,946

19

5,71

8,59

3

34

5,80

5,05

9

22

3,91

1,02

0

1,

854,

567,

658

6,82

8,58

9

G

SS F

RW

H5,

558,

687

G

S Sm

all N

on-D

eman

d FR

WH

237,

115

432,

884

256,

449

559,

940

824,

959

467,

997

246,

360

422,

948

257,

140

473,

778

837,

094

542,

024

5,55

8,68

7

19

,682

GSS

Sea

sona

l5,

707,

215

G

S Sm

all N

on-D

eman

d Se

ason

316,

486

577,

786

342,

292

919,

842

1,35

5,20

3

768,

803

177,

060

303,

974

184,

807

194,

575

343,

784

222,

603

5,70

7,21

5

18

,161

GS

Smal

l Dem

and

2,36

3,96

8,90

8

GS

Smal

l Dem

and

86,1

24,8

73

155,

733,

913

96,3

27,7

43

188,

753,

572

305,

064,

993

181,

849,

238

104,

235,

551

181,

172,

476

113,

763,

401

239,

738,

503

427,

070,

670

284,

133,

975

2,36

3,96

8,90

8

8,

582,

249

GS

Med

ium

3,65

3,69

0,35

9

GS

Med

ium

141,

740,

153

252,

393,

249

155,

128,

403

320,

769,

079

516,

218,

800

312,

884,

924

159,

104,

617

273,

969,

089

170,

260,

709

347,

898,

566

607,

136,

570

396,

186,

201

3,65

3,69

0,35

9

13

,094

,185

G

S La

rge

<30K

V1,

942,

588,

302

G

S La

rge

750-

30kV

79,8

06,6

28

136,

361,

704

89,0

06,7

29

178,

393,

889

280,

455,

280

184,

178,

767

85,3

26,8

37

141,

620,

048

94,3

86,4

74

176,

365,

574

296,

279,

849

200,

406,

525

1,94

2,58

8,30

2

6,

864,

556

GS

Larg

e 30

-100

kV1,

226,

541,

957

G

S La

rge

30-1

00kV

42,4

83,5

26

84,0

80,1

43

64,8

60,9

09

89,1

88,6

12

168,

441,

583

130,

807,

980

47,1

83,5

22

90,9

50,0

46

71,2

84,3

43

98,5

41,5

23

190,

227,

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691



May 30, 2016 Page 1 of 4


Manitoba Hydro Undertaking # 2 Manitoba Hydro to provide all PCOSS schedules with the scenario provided on slide 20 of Manitoba Hydro’s COSS workshop presentation from May 11, 2016, as well please provide a version of Schedules B2 and B3 without deducting the Net Export Revenue (i.e. similar to MIPUG/MH-I-6A).

Response: Please see the Schedules below.



May 30, 2016 Page 2 of 4

Man

itoba

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roPr

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f Ser

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May 30, 2016 Page 3 of 4

Man

itoba

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May 30, 2016 Page 4 of 4

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Undertaking # 3 Transcript Page # 205 & 211


May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 3 Manitoba Hydro to provide monthly MISO Voluntary Capacity Auction prices for the period 2009 to 2013

Response: Please see the attachment to this Undertaking for the monthly MISO Voluntary Capacity Auction prices from 2009 to 2013.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 4 Manitoba Hydro to confirm whether all the times that were given in the discovery responses are for hour ending.

Response: All Information Request responses displaying Load Research results show time as hour ending. Load Research headings show the period under study as “from” and “to” times.



June 8, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 5 Manitoba Hydro to provide a schedule of historic export sales from 2005 through to the 2014 year for all hours, and a similar schedule to the one provided in the table shown in Coalition 58A, and provide the forecasted export sales looking forward in a similar table.

Response: Please see the table below for dependable and opportunity sales across all hours for the period 2005 to 2015.

For forecasted export sales to Canada and the U.S., please see Manitoba Hydro’s response to PUB/MH I-71a. The breakdown between firm and opportunity sales is confidential.

GWh CAD $M AvgPrice GWh CAD $M AvgPrice2005/06 4,044 240 59.25 10,303 510 47.73

2006/07 3,654 218 59.67 6,250 295 46.53

2007/08 3,921 209 53.22 7,099 328 44.42

2008/09 4,087 233 57.12 6,039 287 43.64

2009/10 3,263 186 56.99 7,597 184 22.98

2010/11 3,377 172 51.09 6,967 181 24.77

2011/12 3,742 175 46.79 6,502 152 22.18

2012/13 3,636 177 48.69 5,451 146 25.18

2013/14 3,479 182 52.22 7,058 203 28.92

2014/15 3,133 183 58.34 6,877 201 28.83

2015/16 2,701 206 76.22 7,580 201 25.33

DEPENDABLE EXPORTS OPPORTUNITY EXPORTS



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 6 Manitoba Hydro to provide how indirect costs were allocated to each of the generating assets and what assumptions were made to do that, and what portion of the total cost shown in column 8 is indirect cost

Response: Please see the table below. The allocation of the indirect costs represents 31% of the Total Cost shown in column 8 of the attachment as provided in response to PUB/MH I-63b. Costs functionalized as Generation in the PCOSS but unrelated to operation of the stations such as DSM, power purchases and Diesel facilities have been excluded from the analysis. Indirect Cost Description Allocation Basis Common Generation Cost Allocated on GS energy Mitigation/Water Management Allocated by river system on GS energy Town Site Assigned to associated GS Gillam Services Allocated to Lower Nelson GS on energy Northern Collector Circuit Assigned to associated Lower Nelson GS Bipoles/Radisson/Henday Allocated to Lower Nelson GS on energy Communication Allocated on GS energy Building/General Equipment (Interest & Cap Tax) Allocated on GS net investment Grants-in-Lieu of Taxes Allocated on GS net investment



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 7 Manitoba Hydro to provide RCCs and the percentages that go along with each of them.

Response: The class RCC percentages that underpin slide 39 of the presentation are as follows:

Customer Class PCOSS14-Amended

PCOSS14-Amended

(NER on G&T)

PCOSS14-Amended

(One Export Class)

PCOSS14 116/08*

PCOSS14 116/08**

Residential 99.8% 98.7% 98.3% 95.4% 95.1% GSS – ND 108.0% 107.2% 107.5% 106.3% 106.3% GSS – D 104.5% 104.7% 105.1% 105.8% 105.9% GSM 99.4% 100.0% 100.1% 99.9% 100.3% GSL <30 91.3% 92.2% 91.7% 92.6% 90.7% GSL 30-100 100.0% 101.9% 102.5% 111.8% 112.5% GSL >100 98.6% 101.3% 102.1% 111.6% 113.7% ARL 100.2% 99.7% 99.6% 94.0% 93.6%

* Filed as MIPUG-MFR4 ** Filed as COALITION/MH I-85



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 8 Manitoba Hydro to provide hourly load profile data for exports using Manitoba Hydro's load research in the same Excel format that was provided for the domestic classes in response to PUB/MH I-53

Response: Hourly export kW loads for each year of Load Research supporting PCOSS08 (Order 116/08)

and PCOSS14-Amended are provided in the Excel attachment to this Undertaking, similar

format as Manitoba Hydro’s response to PUB/MH I-53c-e. Exports are total loads measured at

the meter. Hourly export data is not available for 2004-2005 Load Research, therefore, seven

years are provided rather than eight.



May 30, 2016 Page 1 of 4


Manitoba Hydro Undertaking # 9 Manitoba Hydro to provide the MISO financial sales data added to the table provided in response to PUB/MH I-22b

Response: Please see the tables below from PUB/MH I-22b, including MISO financial sales data.



May 30, 2016 Page 2 of 4

MISO Financial SalesGWh

Date 5 x 16 2 x 16 7 x 8Apr-08 144 133 152 6May-08 140 139 113 13Jun-08 132 155 67 58Jul-08 116 89 335 31

Aug-08 78 192 384 51Sep-08 212 174 339 38Oct-08 133 148 303 29

Nov-08 112 183 223 35Dec-08 22 62 43 6Jan-09 27 34 26 20Feb-09 39 56 38 6Mar-09 17 79 37 9Apr-09 158 107 159 92May-09 156 79 74 32Jun-09 138 61 66 32Jul-09 203 59 108 39

Aug-09 169 73 98 68Sep-09 177 129 296 42Oct-09 217 190 364 66


Aug-10 158 168 289 99Sep-10 164 145 219 46Oct-10 202 189 256 25

Nov-10 103 69 167 15Dec-10 13 66 77 10

GWhMISO Physical Sales



May 30, 2016 Page 3 of 4


Date 5 x 16 2 x 16 7 x 8Jan-11 14 57 66 12Feb-11 26 62 88 40Mar-11 55 81 138 31Apr-11 114 92 173 37May-11 221 138 227 58Jun-11 189 121 199 95Jul-11 159 207 357 46

Aug-11 152 150 341 32Sep-11 103 88 185 26Oct-11 88 112 178 10


Aug-12 186 181 327 14Sep-12 172 177 221 15Oct-12 143 77 28 16


Aug-13 222 225 378 14Sep-13 164 187 244 38

MISO Physical SalesGWh



May 30, 2016 Page 4 of 4


Date 5 x 16 2 x 16 7 x 8Oct-13 227 152 301 43


Aug-14 162 226 378 22Sep-14 157 113 235 32Oct-14 15 38 75 7


Aug-15 288 188 303 11Sep-15 226 118 239 10Oct-15 134 104 231 23

Nov-15 263 135 127 21Dec-15 231 91 106 17Jan-16 94 75 31 13Feb-16 169 101 84 5

MISO Physical SalesGWh



May 30, 2016 Page 1 of 2


Manitoba Hydro Undertaking # 10 Manitoba Hydro to look at the data provided and the references in attachment 31 from the interim proceeding, showing sales under permit 379 in August 2013, and add to table in response to PUB/MH I-22d

Response: Information Requests PUB/MH I-22d requests a breakdown of monthly firm sales by Permit Number for firm contracts. The export sales under the WPS NEB permit 379 are not firm sales, and therefore were not included in the original response to PUB/MH I-22d. However, as requested in this Undertaking, Manitoba Hydro has included the information regarding WPS NEB Permit 379 sales (GWh) in the table below.



May 30, 2016 Page 2 of 2

NSP MPNSP

(Incl Diversity) WPSEPE-224 EPE-392 EPE-374 EPE-33 EPE-34 EPE-387 EPE-35 EPE-379

Apr-14 171 93May-14 153 63 57Jun-14 167 34 26 105 75Jul-14 178 54 41 110 77

Aug-14 168 54 41 112 78Sep-14 163 28 21 102 70Oct-14 136 39

Nov-14 160Dec-14 184Jan-15 176Feb-15 160Mar-15 175Apr-15 176May-15 179 110 59Jun-15 23 180 99 53Jul-15 25 191 105 57

Aug-15 24 184 80 43Sep-15 24 186 100 53Oct-15 24 175 88 41

Nov-15 24 94Dec-15 25 101Jan-16 25 101Feb-16 24 103

The WPS contract was not included in the original response as it is not a firm contract.

Diversity

NSP GRE



May 30, 2016 Page 1 of 3


Manitoba Hydro Undertaking # 11 Manitoba Hydro to provide detail of the cost difference among the three (3) types of poles.

Response: The cost associated with the three types of pole structures is based on the basic tangent pole structure.

It should be noted that the costs shown below are based only on the construction of a new tangent 45’pole structure as part of a green field installation supporting a single three phase overhead feeder and service without the use of any anchoring or supporting structures. Though this is a basic structure, there are a large number of variations. Poles can range from 30’ to 70’, can hold up to 8-12 overhead lines of varying voltage levels and may require multiple cross arms and insulators. Depending on the location of the pole, guying/anchoring may be required as might more advanced supporting structures such as rock anchors. Costs will also fluctuate from rural to urban environments due to equipment haulage, traffic coordination, underground line location or permit costs associated with the nature of the project.

The components used for each structure are as follows:

Option #1 - Cost of a pole supporting both primary and secondary lines:

• Estimated Cost: $1,700

• Structure Description: a new tangent 45’pole structure as part of a green field construction supporting a three phase primary line of 3x2/0acsr bare wire on an 8’ cross arm with a secondary rack supporting four secondary lines with no anchoring or supporting structures.

• Material Used: o 1 x 45’ class 3 CCA (green) pole o 1 x 25kV single 8’ cross arm o 3 x 25kV porcelain insulators o 3 x 2/0 armour rod o 3 x preformed 2/0acsr pre-form poly tie o 1 x four spool secondary rack o 4 x #6 aluminum secondary tie wire



May 30, 2016 Page 2 of 3

• Man-hours Used: o 1.0 hour of Engineering o 4.8 hours of Overhead Line Construction o 4.0 hours of Pole Installation

Option #2 - Cost of a pole supporting only primary lines:


• Structure Description: a new tangent 45’pole structure as part of a green field construction supporting a three phase primary line of 3x2/0acsr bare wire on an 8’ cross arm with no anchoring or supporting structures.

• Material Used: o 1 x 45’ class 3 CCA (green) pole o 1 x 25kV single 8’ cross arm o 3 x 25kV porcelain insulators o 3 x 2/0 armour rod o 3 x preformed 2/0acsr pre-form poly tie


Option #3 - Cost of a pole supporting only secondary lines:


• Structure Description: a new tangent 45’pole structure as part of a green field construction supporting a secondary rack supporting four secondary lines with no anchoring or supporting structures.

• Material Used: o 1 x 45’ class 3 CCA (green) pole o 1 x four spool secondary rack



May 30, 2016 Page 3 of 3

o 4 x #6 aluminum secondary tie wire




May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 12 Manitoba Hydro to provide data on length of secondary cable.

Response: Further to the discussion which occurred at pages 697-702 of the transcript, Manitoba Hydro can confirm that it does not have information on the total length of secondary cable on the distribution system as secondary cables were not tracked prior to 2006.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 13 Manitoba Hydro to clarify whether table shows conductor length for service drops, for all overhead distribution including service drops, or overhead distribution not including service drops

Response: The table in GAC/MH I-47 Attachment 1 shows conductor length for overhead distribution not

including service drops, which are not tracked.



May 30, 2016 Page 1 of 2


Manitoba Hydro Undertaking # 14 Manitoba Hydro to indicate the number of night time hours to determine coincident peak and non-coincident peak [for streetlights].

Response: The CP Load Factor for A&RL in PCOSS14-Amended is based on a load research study prepared in 1999/2000 that included a sample of 13 points of metering. Since the preparation of PCOSS14, Manitoba Hydro has started including Area & Roadway Lighting in Load Research studies based on an estimated hourly load profile which will be used in future COSS. The Area and Roadway Lighting (A&RL) class load profile is estimated by aggregating the total of all luminaries including bulb and ballast energy consumption at steady state. Sunset and sunrise times are at Winnipeg and taken from National Research Council Canada. Photo cells that control the lighting typically turn on 2 to 5 seconds after sunset and off 2 to 5 seconds before sunrise. For the purposes of calculating the A&RL hourly kW load profile, the streetlight operations are assumed to coincide with sunset and sunrise times. The resultant hourly kW demand estimates for A&RL are either full load (on), no load (off) or partial load if crossing sunset or sunrise. The Load Research data is used to identify the Top 50 system peaks and whether the lights were on or off during those 50 peaks hours. The peak hours may vary from year to year and as such, the number of hours on during the winter and summer peaks are only an indicator of the seasonal coincident peak load factors. The actual load factors feed into the 2CP allocator (not the hours). The following table providing eight years of Area and Roadway Lighting data was prepared to respond to this Undertaking.



May 30, 2016 Page 2 of 2

Area and Roadway Lighting

Corresponding to Highest 50 Generation Peaks

Year Non Coincident Peak Load

Factor

Winter Top 50

Coincident Peak Load

Factor Dec-Feb 06:00 to

22:00

Winter Top 50 Hours "On"

Winter Energy

Nov-Apr

(% of

annual)

Winter Seasonal


Factor (D1 - 2CP)

Summer Top 50


Factor Jun-Aug 06:00 to

22:00

Summer Top 50 Hours

On

Summer Energy May-Oct

(% of

annual)

Summer Seasonal


Factor (D1 - 2CP)

Total Top 50 x 2 Hours On

2013-2014 48.9% 93.3% 26.2 57.9% 108.9% 366.1% 6.7 42.1% 305.8% 32.9 2012-2013 49.0% 81.0% 30.2 57.9% 94.5% 730.6% 3.4 42.1% 610.6% 33.6 2011-2012 48.9% 86.5% 28.3 58.1% 101.0% 4447.2% 0.6 41.9% 3707.2% 28.8 2010-2011 48.9% 91.5% 26.7 58.0% 107.0% 1613.0% 1.5 42.0% 1345.2% 28.2 2009-2010 48.9% 83.8% 29.2 57.9% 97.9% 3580.0% 0.7 42.1% 2987.7% 29.9 2008-2009 48.9% 103.2% 23.7 57.9% 120.4% 1174.3% 2.1 42.1% 980.6% 25.8 2007-2008 48.9% 86.2% 28.4 58.1% 100.8% 1359.2% 1.8 41.9% 1132.7% 30.2 2006-2007 48.9% 90.6% 27.0 57.9% 105.9% 3190.1% 0.8 42.1% 2662.2% 27.8

Average 48.9% 89.5% 27.5 58.0% 104.6% 2057.6% 2.2 42.0% 1716.5% 29.6

Definitions: NCP: Single highest hourly kW demand. "On" for A&RL.

NCP LF: Average annual hourly kW demand/NCP CP: Average of 50 hourly kW demands corresponding to the Top 50 system peak hours at generation.

CP LF: Average annual hourly kW demand/CP

Seasonal CP LF: Average seasonal hourly kW demand/CP



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 15 Manitoba Hydro to provide Excel file with annual average load profiles by customer class for years 2012/2013 and 2013/2014.

Response: Hourly load profiles for each of the domestic rate classes from 2012/13 and 2013/14 Load

Research can be found in the Excel attachment to this Undertaking, in a similar format to

Manitoba Hydro’s response to PUB/MH I-53c-e.



May 30, 2016 Page 1 of 3


Manitoba Hydro Undertaking # 16 Manitoba Hydro to provide Schedules B2 and B3 without the net [export] revenue being deducted.

Response: Please see the Schedules below.



May 30, 2016 Page 2 of 3

Manitoba Hydro Prospective Cost Of Service Study - March 31, 2014

Customer, Demand, Energy Cost Analysis Model of Coalition/MH-I-85

S U M M A R Y prior to allocation of Net Export Revenue

C U S T O M E R D E M A N D E N E R G Y

Billable MeteredCost Number of Unit Cost Cost % Demand Unit Cost Cost Energy Unit Cost

Class ($000) Customers $/Month ($000) Recovery MVA $/KVA ($000) mWh ¢/kWh

Residential 127,812 486,987 21.87 201,172 0% n/a n/a 222,135 7,404,453 5.72 **

GS Small - Non Demand 25,518 53,778 39.54 39,921 0% n/a n/a 48,938 1,605,511 5.53 **GS Small - Demand 8,666 12,492 57.81 46,112 38% 2,390 7.31 60,855 2,047,715 4.37

General Service - Medium 7,604 1,974 321.03 66,114 87% 7,302 7.91 93,057 3,174,662 3.19

General Service - Large <30kV 3,837 288 n/a 30,657 100% 4,042 8.53 * 48,428 1,702,481 2.84 General Service - Large 30-100kV 2,646 40 n/a 10,420 100% 2,894 4.51 * 33,447 1,327,210 2.52 General Service - Large >100kV 2,445 16 n/a 24,476 100% 8,409 3.20 * 124,004 4,903,742 2.53

SEP 325 29 933.74 133 0% n/a n/a 509 26,500 2.42 **

Area & Roadway Lighting 16,503 155,024 8.87 2,774 0% n/a n/a 2,952 100,487 5.70 **

Total General Consumers 195,356 710,628 421,778 25,038 634,325 22,292,761

Diesel 234 755 25.81 351 0% n/a n/a 9,323 13,754 70.33 **

Export n/a n/a n/a 45,704 0% n/a n/a 441,014 9,013,000 5.40 ***

Total System 195,590 711,383 467,833 25,038 1,084,661 31,319,515

* - includes recovery of customer costs** - includes recovery of demand costs*** -includes recovery of customer and demand costs



May 30, 2016 Page 3 of 3

Manitoba HydroProspective Cost Of Service Study - March 31, 2014

Functional BreakdownModel of Coalition/MH-I-85

S U M M A R Y prior to allocation of Net Export Revenue

Generation Transmission Subtransmission Distribution DistributionTotal Cost Cost Cost Cost Cust Service Plant Cost

Class ($000) ($000) % ($000) % ($000) % Cost ($000) % ($000) %

Residential 551,118 222,135 40.3% 60,331 10.9% 35,862 6.5% 71,010 12.9% 161,781 29.4%

General Service - Small Non Demand 114,376 48,938 42.8% 13,521 11.8% 6,722 5.9% 18,046 15.8% 27,149 23.7%General Service - Small Demand 115,633 60,855 52.6% 15,841 13.7% 7,708 6.7% 4,312 3.7% 26,917 23.3%

General Service - Medium 166,776 93,057 55.8% 24,075 14.4% 10,704 6.4% 6,563 3.9% 32,376 19.4%

General Service - Large <30kV 82,922 48,428 58.4% 12,138 14.6% 5,307 6.4% 3,600 4.3% 13,449 16.2%General Service - Large 30-100kV 46,513 33,447 71.9% 6,667 14.3% 3,753 8.1% 2,576 5.5% 70 0.2%General Service - Large >100kV 150,925 124,004 82.2% 24,476 16.2% 0 0.0% 2,416 1.6% 29 0.0%

SEP 967 509 52.7% 133 13.7% 0 0.0% 308 31.9% 17 1.7%

Area & Roadway Lighting 22,229 2,952 13.3% 504 2.3% 578 2.6% 546 2.5% 17,648 79.4%

Total General Consumers 1,251,459 634,325 50.7% 157,686 12.6% 70,634 5.6% 109,378 8.7% 279,436 22.3%

Diesel 9,908 9,323 94.1% 0 0.0% 0 0.0% 0 0.0% 585 5.9%

Export 486,718 441,014 90.6% 45,704 9.4% 0 0.0% 0 0.0% 0 0.0%

Total System 1,748,084 1,084,661 62.0% 203,390 11.6% 70,634 4.0% 109,378 6.3% 280,021 16.0%



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 17 Manitoba Hydro to explain what Planned Orders by SCC is and why it would add to a different number [than presented in MIPUG/MH I-4b and Schedule E1 Amended]

Response: Manitoba Hydro uses operating orders to plan, collect, and settle the costs of internal jobs and tasks. The planning orders used to weight class shares for each of the areas in the C10 allocator included only the planned direct labour costs and overhead for each area. The total costs shown in Schedule E1 Amended also included depreciation on common and regulatory assets, purchased services/material, travel and other expenses, as well as assessment of common and administrative costs.



May 31, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 19 Manitoba Hydro to indicate how the direct and indirect costs are calculated and the incremental costs are calculated; what methodology does Manitoba Hydro use to be able to calculate those costs; if those incremental costs are included in the cost of service study, and if so, how they're included in the cost of service study.

Response: Manitoba Hydro determines the cost of serving a new or increased customer load by pricing the materials and labor to provide the required infrastructure. Materials are priced at their current cost plus applicable overheads. Labor for Manitoba Hydro personnel is charged at the activity rate plus applicable overheads. Manitoba Hydro also recovers indirect overhead costs which were previously capitalized with the project but are now expensed. The amount of investment allowance is determined and applied as per Manitoba Hydro customer policy. The investment allowance is an offset to the cost of service extension. The amount of labor and material cost in excess of the investment allowance is recovered from the customer by way of a payment prior to the construction of the facilities. When these assets are put in service, the material and labor cost of these facilities are capitalized in accordance with current accounting policy. Contributions in Aid of Construction are also recorded and serve to offset the gross plant investment by the amount of the Contribution. From a cost of service perspective, the net investment (to the extent it has not been fully funded by contributions) is functionalized based on asset type and added to rate base which is used to allocate costs such as Finance Expense and Net Income. Depreciation expense is consistently functionalized based on asset type and classified and allocated accordingly. The indirect costs associated with the project and paid by the customer which are now expensed are included as other revenue and applied as an offset to operating costs in cost of service.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 21 Manitoba Hydro to provide a list of assets that were moved out of subtransmission into distribution

Response: Please see the response to Undertaking 25.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 22 Manitoba Hydro to provide website link to schedule of additional charges

Response: Information on Other Charges, such as the Late Payment Fees and NSF Cheque Fees, can be found at the link below (which was included in Manitoba Hydro’s response to COALITION/MH I-77c). https://www.hydro.mb.ca/customer_services/how_to_read/your_bill/read_your_bill.html The fees and charges currently in place can be accessed by going to page 3 of the sample bill, selecting “Other charges” from the drop down menu, and then selecting “Other Charge Options”. A drop down menu will appear listing each of the Other Charges.

https://www.hydro.mb.ca/customer_services/how_to_read/your_bill/read_your_bill.html



May 30, 2016


Manitoba Hydro Undertaking # 23 Manitoba Hydro to provide monthly capacity factor data for the following individual stations, Kettle, Long Spruce, and Limestone for five (5) different years, fiscal year 2002/2003, 2003/2004, 2013/2014, 2014/2015, and 2015/2016.

Response: The requested data is provided in Figure 1, Figure 2 and Table 1 below. As Mr. Cormie discussed at pages 107 and 108 of the Transcript, under normal flow conditions, Manitoba load (capacity and energy) is completely served by hydraulic facilities and capacity reserves are supported through thermal and imports as well as hydro. In drought conditions, such as in the 2003/04 year, capacity reserves are supported by hydraulic facilities that are still capable of meeting energy requirements for short durations. Figure 1 is a chart of annual capacity factors for Kettle, Long Spruce, Limestone and the aggregate of the three Lower Nelson River generating stations from fiscal year 1992/93 to 2015/16. Figure 2 is a chart of monthly capacity factors for Kettle, Long Spruce, Limestone and the aggregate of the three Lower Nelson River generating stations from fiscal year 1992/93 to 2015/16. Table 1 includes the monthly and annual capacity factors for the Lower Nelson River generating stations from fiscal year 1992/93 to 2015/16. Please note:

1. Water supply conditions are the primary variable affecting capacity factors. For example as shown in Figure 1, Lower Nelson River Capacity Factors range from approximately 40% to almost 90% for the period shown, with 2003/04 and 2005/06 being the driest and wettest years respectively.

2. Capacity factors were calculated based on 2015/16 net nominal interconnected capability values. Capability values can vary slightly from year to year for various reasons including: unit upgrades, removal of generator restrictions, changes to forebay operating ranges. These changes can affect the calculated capacity factor for a given station.

3. Other variables beyond those provided in (1) and (2) can also affect capacity factors. Examples of these include the addition of other supply sources, load growth, generation outages, river ice conditions, HVDC availability (in the case of the Lower Nelson River



May 30, 2016

generation), and interconnection availability. For example in Figure 2, the dip in capacity factors in September 1996 is largely attributed to the extended outage on the HVDC system as a result of a wind storm near Dorsey. Similarly, in October 2014, the 500 kV US tieline was out of service for the month, resulting in reduced export market access. This resulted in a temporary dip in the capacity factor of the Lower Nelson River stations.



May 30, 2016 Page 3 of 8

Figure 1. Annual capacity factors for Lower Nelson River stations from 1992/93 through 2015/16.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1992/93

1993/94

1994/95

1995/96

1996/97

1997/98

1998/99

1999/00

2000/01

2001/02

2002/03

2003/04

2004/05

2005/06

2006/07

2007/08

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

Annu

al Nom

inal Cap

acity

Factor in %

Lower Nelson River Capacity Factors

Lower Nelson (f.y.)

Kettle (f.y.)

Long Spruce (f.y.)

Limestone (f.y.)



May 30, 2016 Page 4 of 8

Figure 2. Monthly capacity factors for Lower Nelson River stations from 1992/93 through 2015/16.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%1992/93

1993/94

1994/95

1995/96

1996/97

1997/98

1998/99

1999/00

2000/01

2001/02

2002/03

2003/04

2004/05

2005/06

2006/07

2007/08

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

Mon

thly Nom

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acity

Factor in %

Lower Nelson River Capacity Factors

Lower Nelson (mo.)

Kettle (mo.)

Long Spruce (mo.)

Limestone (mo.)

Sep‐1996Oct‐2014



May 30, 2016 Page 5 of 8

Table 1. Monthly and fiscal year nominal capacity factors for Lower Nelson River generation.

Kettle Long Spruce Limestone Lower Nelson River

1992/93 64% 66% 59% 63%Apr 53% 57% 50% 53%

May 59% 65% 57% 60%

Jun 59% 61% 52% 57%

Jul 52% 52% 41% 48%

Aug 50% 53% 48% 50%

Sep 54% 56% 50% 53%

Oct 70% 71% 64% 68%

Nov 78% 79% 73% 77%

Dec 73% 78% 70% 73%

Jan 70% 73% 66% 69%

Feb 78% 79% 72% 76%

Mar 70% 74% 67% 70%

1993/94 59% 63% 57% 59%Apr 51% 54% 50% 52%

May 46% 47% 44% 45%

Jun 37% 39% 36% 37%

Jul 42% 45% 41% 43%

Aug 54% 56% 51% 53%

Sep 60% 62% 54% 58%

Oct 72% 78% 72% 73%

Nov 60% 64% 59% 61%

Dec 76% 80% 72% 76%

Jan 75% 82% 74% 77%

Feb 71% 76% 69% 72%

Mar 64% 70% 65% 66%

1994/95 63% 66% 61% 63%Apr 57% 61% 57% 58%

May 66% 71% 65% 67%

Jun 58% 60% 57% 58%

Jul 59% 62% 57% 59%

Aug 57% 61% 56% 58%

Sep 57% 59% 55% 57%

Oct 60% 63% 59% 60%

Nov 67% 71% 65% 67%

Dec 64% 68% 61% 64%

Jan 72% 75% 68% 71%

Feb 72% 74% 67% 71%

Mar 69% 72% 66% 69%

1995/96 65% 69% 63% 65%Apr 66% 71% 65% 67%

May 64% 69% 63% 65%

Jun 61% 65% 60% 62%

Jul 54% 57% 53% 54%

Aug 63% 67% 60% 63%

Sep 66% 70% 64% 67%

Oct 73% 77% 71% 73%

Nov 68% 72% 65% 68%

Dec 66% 71% 63% 66%

Jan 69% 72% 64% 68%

Feb 65% 70% 62% 65%

Mar 63% 68% 62% 64%

1996/97 73% 77% 70% 73%Apr 63% 68% 63% 64%

May 68% 75% 68% 70%

Jun 78% 80% 77% 78%

Jul 74% 74% 69% 72%

Aug 80% 82% 79% 80%

Sep 59% 58% 53% 56%

Oct 72% 78% 72% 74%

Nov 75% 79% 72% 75%

Dec 80% 84% 75% 79%

Jan 77% 81% 73% 77%

Feb 77% 80% 72% 76%

Mar 77% 81% 73% 77%

1997/98 83% 86% 79% 82%Apr 81% 87% 78% 82%

May 82% 87% 79% 82%

Jun 85% 83% 80% 83%

Jul 83% 81% 72% 78%

Aug 84% 83% 83% 84%

Sep 82% 85% 79% 82%

Oct 78% 83% 77% 79%

Nov 85% 89% 81% 84%

Dec 86% 90% 81% 85%

Jan 86% 89% 80% 85%

Feb 85% 87% 79% 83%

Mar 80% 84% 77% 80%



May 30, 2016 Page 6 of 8

Table 1. (continued)


1998/99 70% 73% 67% 70%Apr 77% 82% 75% 77%

May 82% 86% 79% 82%

Jun 82% 88% 81% 83%

Jul 87% 89% 82% 86%

Aug 81% 84% 78% 81%

Sep 59% 62% 57% 59%

Oct 62% 64% 59% 61%

Nov 63% 64% 59% 62%

Dec 63% 65% 59% 62%

Jan 61% 63% 58% 61%

Feb 63% 66% 59% 63%

Mar 58% 61% 56% 58%

1999/00 65% 68% 62% 64%Apr 60% 64% 59% 61%

May 52% 55% 51% 53%

Jun 63% 64% 60% 62%

Jul 60% 63% 58% 60%

Aug 57% 60% 55% 57%

Sep 61% 63% 58% 61%

Oct 69% 72% 67% 69%

Nov 67% 70% 64% 67%

Dec 70% 74% 67% 70%

Jan 69% 73% 66% 69%

Feb 73% 77% 67% 72%

Mar 74% 78% 71% 74%

2000/01 75% 79% 72% 75%Apr 67% 72% 66% 68%

May 69% 72% 67% 69%

Jun 61% 64% 59% 61%

Jul 73% 76% 70% 73%

Aug 77% 81% 75% 77%

Sep 76% 80% 73% 76%

Oct 81% 84% 78% 81%

Nov 77% 81% 74% 77%

Dec 75% 81% 73% 76%

Jan 80% 84% 75% 79%

Feb 84% 88% 78% 83%

Mar 81% 85% 77% 81%

2001/02 78% 81% 74% 77%Apr 74% 78% 72% 75%

May 89% 92% 85% 89%

Jun 92% 93% 87% 90%

Jul 93% 93% 86% 90%

Aug 83% 85% 77% 81%

Sep 78% 81% 75% 77%

Oct 76% 78% 72% 75%

Nov 77% 78% 72% 75%

Dec 71% 75% 68% 71%

Jan 77% 79% 72% 76%

Feb 68% 71% 64% 67%

Mar 62% 66% 60% 62%

2002/03 66% 70% 64% 66%Apr 57% 61% 55% 57%

May 61% 63% 58% 61%

Jun 70% 73% 67% 70%

Jul 69% 72% 66% 69%

Aug 71% 74% 68% 71%

Sep 70% 73% 67% 69%

Oct 70% 74% 68% 71%

Nov 63% 68% 62% 64%

Dec 69% 73% 66% 69%

Jan 72% 77% 69% 72%

Feb 62% 67% 60% 63%

Mar 57% 61% 56% 57%

2003/04 41% 43% 39% 41%Apr 51% 55% 50% 52%

May 50% 53% 49% 51%

Jun 43% 44% 40% 42%

Jul 45% 47% 43% 45%

Aug 38% 40% 37% 38%

Sep 33% 34% 31% 33%

Oct 31% 32% 29% 31%

Nov 34% 35% 32% 34%

Dec 41% 42% 38% 40%

Jan 41% 42% 38% 40%

Feb 41% 42% 38% 40%

Mar 45% 47% 42% 44%



May 30, 2016 Page 7 of 8



2004/05 71% 75% 68% 71%Apr 39% 41% 37% 39%

May 47% 50% 46% 47%

Jun 62% 66% 61% 63%

Jul 72% 75% 69% 72%

Aug 74% 76% 70% 73%

Sep 71% 75% 68% 71%

Oct 76% 80% 73% 76%

Nov 83% 86% 79% 83%

Dec 76% 81% 72% 76%

Jan 83% 89% 79% 83%

Feb 86% 93% 82% 86%

Mar 84% 90% 81% 84%

2005/06 88% 90% 86% 88%Apr 88% 89% 85% 87%

May 93% 91% 91% 91%

Jun 88% 90% 87% 88%

Jul 90% 93% 88% 90%

Aug 86% 88% 86% 87%

Sep 81% 80% 78% 79%

Oct 84% 81% 81% 82%

Nov 95% 97% 90% 94%

Dec 82% 89% 81% 84%

Jan 90% 94% 85% 89%

Feb 89% 95% 84% 89%

Mar 89% 98% 91% 92%

2006/07 76% 79% 73% 76%Apr 83% 87% 82% 84%

May 92% 93% 88% 91%

Jun 91% 92% 90% 91%

Jul 94% 96% 89% 93%

Aug 92% 95% 87% 91%

Sep 74% 77% 70% 73%

Oct 57% 58% 53% 56%

Nov 58% 61% 55% 58%

Dec 70% 74% 67% 70%

Jan 75% 78% 70% 74%

Feb 67% 72% 64% 67%

Mar 65% 69% 62% 65%

2007/08 82% 86% 79% 82%Apr 63% 67% 61% 63%

May 77% 83% 75% 78%

Jun 77% 83% 76% 78%

Jul 90% 97% 89% 91%

Aug 95% 98% 91% 94%

Sep 83% 87% 80% 83%

Oct 81% 84% 79% 81%

Nov 94% 96% 89% 92%

Dec 79% 83% 75% 78%

Jan 86% 89% 78% 84%

Feb 83% 89% 77% 82%

Mar 77% 83% 73% 77%

2008/09 83% 86% 79% 83%Apr 80% 84% 77% 80%

May 75% 78% 72% 75%

Jun 71% 75% 68% 71%

Jul 89% 93% 86% 89%

Aug 93% 95% 94% 94%

Sep 89% 91% 89% 90%

Oct 89% 92% 86% 89%

Nov 92% 94% 87% 91%

Dec 81% 85% 77% 80%

Jan 81% 84% 74% 79%

Feb 81% 85% 72% 79%

Mar 76% 81% 71% 75%

2009/10 83% 85% 79% 82%Apr 77% 82% 75% 77%

May 83% 81% 78% 81%

Jun 83% 85% 82% 83%

Jul 88% 92% 87% 89%

Aug 88% 90% 84% 87%

Sep 81% 81% 80% 81%

Oct 90% 93% 86% 90%

Nov 87% 88% 80% 85%

Dec 77% 82% 73% 77%

Jan 83% 86% 76% 81%

Feb 81% 84% 74% 79%

Mar 78% 81% 73% 77%



May 30, 2016 Page 8 of 8



2010/11 83% 85% 80% 82%Apr 73% 75% 68% 72%

May 57% 58% 52% 55%

Jun 72% 74% 68% 71%

Jul 82% 86% 79% 82%

Aug 87% 88% 88% 87%

Sep 83% 86% 84% 84%

Oct 87% 88% 86% 87%

Nov 90% 92% 91% 91%

Dec 91% 94% 86% 90%

Jan 91% 92% 84% 89%

Feb 92% 93% 88% 91%

Mar 93% 93% 86% 91%

2011/12 80% 84% 78% 80%Apr 81% 85% 82% 83%

May 76% 83% 80% 80%

Jun 72% 75% 70% 72%

Jul 88% 89% 87% 88%

Aug 89% 90% 89% 89%

Sep 78% 83% 80% 80%

Oct 81% 81% 77% 79%

Nov 85% 88% 82% 85%

Dec 81% 86% 76% 81%

Jan 85% 89% 80% 84%

Feb 77% 81% 72% 76%

Mar 69% 72% 65% 68%

2012/13 75% 79% 71% 75%Apr 61% 64% 58% 61%

May 66% 70% 64% 66%

Jun 71% 74% 67% 70%

Jul 84% 88% 80% 84%

Aug 84% 83% 76% 80%

Sep 77% 78% 72% 75%

Oct 69% 72% 66% 69%

Nov 77% 78% 74% 76%

Dec 77% 81% 73% 77%

Jan 81% 85% 75% 80%

Feb 79% 84% 73% 78%

Mar 80% 85% 76% 80%

2013/14 80% 83% 75% 78%Apr 73% 79% 72% 74%

May 78% 82% 74% 78%

Jun 79% 84% 76% 79%

Jul 86% 87% 78% 83%

Aug 89% 89% 84% 87%

Sep 76% 75% 71% 74%

Oct 83% 87% 78% 82%

Nov 79% 82% 73% 77%

Dec 82% 86% 76% 81%

Jan 78% 81% 71% 76%

Feb 76% 79% 69% 74%

Mar 76% 80% 70% 75%

2014/15 80% 84% 76% 80%Apr 77% 81% 73% 76%

May 74% 77% 65% 71%

Jun 76% 85% 78% 79%

Jul 85% 87% 84% 85%

Aug 85% 93% 90% 89%

Sep 80% 79% 76% 78%

Oct 63% 64% 54% 60%

Nov 81% 86% 77% 81%

Dec 86% 91% 81% 86%

Jan 88% 92% 82% 87%

Feb 83% 87% 77% 82%

Mar 82% 86% 77% 81%

2015/16 81% 84% 76% 80%Apr 80% 84% 76% 80%

May 80% 86% 77% 81%

Jun 79% 83% 76% 79%

Jul 80% 83% 76% 79%

Aug 82% 85% 78% 81%

Sep 78% 77% 74% 76%

Oct 79% 73% 74% 75%

Nov 79% 83% 76% 79%

Dec 80% 86% 77% 80%

Jan 80% 85% 76% 80%

Feb 84% 89% 78% 83%

Mar 86% 90% 80% 85%

Undertaking # 24a Transcript Page # 879


May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 24 Manitoba Hydro to provide the following in Excel format a) Attachment to PUB/MH I-5; b) table listed in response to PUB/MH I-30c; c) PUB/MH I-60d; d) PUB/MH I-65a; and e) the five (5) tables in response to PUB/MH I-70 [corrected per transcript page 878]

Response: The eight years of Load Research at common bus peak, as well as the two years of Load Research at generation peak, used in PCOSS08 (Order 116/08) and PCOSS14-Amended (Attachment 1 of PUB/MH-I-5a-d) are attached to this response in Excel format.

Undertaking # 24b Transcript Page # 879


May 30, 2016 Page 1 of 1



Response: Please find as an attachment to this Undertaking, the table provided in PUB/MH I-30c in Excel format.

Undertaking # 24c Transcript Page # 879


May 30, 2016 Page 1 of 1



Response: Please find as an attachment to this Undertaking, the tables in the response to PUB/MH I-60d in Excel format.

Undertaking # 24d Transcript Page # 879


May 30, 2016 Page 1 of 1



Response: Please find as an attachment to this Undertaking the table provided in PUB/MH I-65a in Excel format.

Undertaking # 24e Transcript Page # 879


May 30, 2016 Page 1 of 1



Response: Please find as an attachment to this Undertaking the tables provided in PUB/MH I-70 in Excel format.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 25 Manitoba Hydro to explain, in Schedule C6 and C8, the basis for distribution and operating costs being re-functionalized from sub-transmission to distribution.

Response: It is assumed that the Undertaking is asking about Depreciation and Operating costs in Schedules C6 and C12. The schedules include a row which is titled “Common Subtransmission Costs”, but which also includes SCC’s for Common Subtransmission and Distribution costs related to system planning. These costs are prorated between Subtransmission and Distribution on the basis of relative operating cost of each function in Schedule C12, and depreciation in Schedule C6.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 26 Manitoba Hydro to provide an explanation of how the net regulated/intangible costs that are functionalized to distribution are then classified and allocated; whether that's proportional to all categories of distribution costs, or whether it's classified entirely as customer-related, or some other way.

Response: As discussed in response to COALITION/MH I-14, net regulated/intangible distribution costs are largely related to easements. Interest costs (Finance Expense, Capital Tax and Net Income) is sub-functionalized to Poles & Wires, Transformers and Service Drops by prorating based on the relative net book value of each sub-function and classified as identified in the table below. Amortization expense of the assets is functionalized directly as Poles & Wires and Transformers and Service Drops in SAP based on settlement cost center and classified as follows: Demand (NCP) Customer Poles & Wires 60% 40% Transformers 100% Service Drops 100%



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 27 Manitoba Hydro, in regards to splitting costs between primary and secondary, indicate how did it derive that breakdown of cable? Are those costs tracked separately in the SAP, or was this some sort of allocation?

Response: The breakdown of underground cable plant investment between primary and secondary is tracked in SAP.



May 30, 2016 Page 1 of 2


Manitoba Hydro Undertaking # 28 Manitoba Hydro, in regards to GAC/MH I-21, the table on page 3, is to answer the following questions: 1) How was the weight factor derived? 2) Can a GSL customer have more than one (1) meter with the loads being aggregated for billing purposes? 3) How are those costs dealt with, the cost of the meters in diesel areas direct assigned, or how are they dealt with in the cost-of -service study? 4) Provide an explanation: In regards to the customer totals for various classes, the total number of customers in that calculation does not equal the forecasted number of customers shown in the right-hand side of the table, and the same is true for the weighted customers, the number of meter readings.

Response: 1. Please see the table below and page 3 of the response to GAC/MH I-21. The weighting factor

is based on 2005 actual customer counts multiplied by the relative frequency of meter reads for subsets of customers within each class. The total annual reads per class is divided by actual customer count to determine the weighting factor.

2. Yes.

3. Diesel site meter reading costs are directly assigned to the Diesel Class.

4. Manitoba Hydro prepares a number of sub studies which support the cost of service study including the analysis of meter reading activities for purposes of allocating meter reading costs. These sub studies are updated periodically as changes to data are not expected to be sizable or have a material impact to depiction of cost responsibility by class. The meter reading sub study was last updated in 2005, but applied against forecast 2014 customer count and therefore the two right most columns of the schedule, based on forecast 2014 customer count, will not match the 2005 actual data used in the remainder of the schedule.

The customer count excludes Area & Roadway Lighting, Flat Rate Water Heating, and Diesel customers that are not allocated meter reading costs in the PCOSS. As noted in response to COALITION/MH I-93d, the GSS Non-Demand and GSS Demand customer count for Meter Reading inadvertently excluded the 19,736 three-phase customers.



May 30, 2016 Page 2 of 2

Number of Customers - WeightedAllocation of Meter Reading Costs

Meter Reading Frequency Annual Meter ReadingsA B C D E F G H I J K L M N O P

1 H4 * B I4 * C J4 * D K4 * E L4 * F SUM(H:L) M / G N * O2 Bi- Semi- Bi- Semi- Actual Actual3 Monthly Monthly Annual Annual Self Read Total Monthly Monthly Annual Annual Self Read Total Weight Customers Customers4 Rate Class 12/yr 6/yr 2/yr 1/yr 1/3 yr 12 6 2 1 0.3 Factor (Unadj.) (Wtd)

567 Residential 11,194 347,200 67,852 426,246 134,328 2,083,200 0 0 20,356 2,237,884 5.0 462,217 2,311,0858 Diesel 512 512 6,144 0 0 0 0 6,144 12.0 09 Res - Seasonal 4,600 15,507 20,107 0 0 9,200 15,507 0 24,707 1.0 20,888 20,888

101112 GSS ND 4,695 33,656 10,278 48,629 56,340 201,936 0 0 3,083 261,359 5.0 41,074 205,37013 Diesel 163 163 1,956 0 0 0 0 1,956 12.0 014 GSS Seasonal 248 546 794 0 0 496 546 0 1,042 1.0 859 85915 GSS Demand 8,864 56 5 8,925 106,368 336 0 0 2 106,706 12.0 4,221 50,6521617 G.S. Medium 1,777 2 1,779 21,324 12 0 0 0 21,336 12.0 1,974 23,6881819 GSL 0 - 30 kV 227 4 231 2,724 24 0 0 0 2,748 12.0 288 3,4562021 GSL 30 kV - 100 kV 28 28 336 0 0 0 0 336 12.022 Curtailable 1 1223 Non-Curtailable 39 4682425 GSL > 100 kV 12 12 144 0 0 0 0 144 12.026 Curtailable 2 2427 Non-Curtailable 14 1682829 SEP30 GSM 12.0 24 28831 GSL 0-30 12.0 5 603233 27,472 380,918 4,848 16,053 78,135 507,426 329,664 2,285,508 9,696 16,053 23,441 2,664,362 531,606 2,617,018



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking # 29 Manitoba Hydro, in regards to PUB/MH I-33c, which concerned our “beloved” line extension policies, indicate if the current line extension policies had been in effect for only a few years, or for many decades, or for what period of time.

Response: Manitoba Hydro’s service extension policies date back to the era of rural electrification in Manitoba, undertaken in the late 1940s. The following identify adjustments to policy related to investment allowances undertaken since 2005:

• Harmonization of residential service extension allowances – January 1, 2016 (discussed in Transcript pages 859-861)

• Reduction of residential service extension allowances for standard and all-electric customers – June 1, 2014 (discussed in Transcript pages 857-859)

• No investment allowance for GS loads greater than 5 MW or served at >30 kV – June 23, 2005 (PUB MFR 18, Page 2)



May 30, 2016 Page 1 of 1


UManitoba Hydro Undertaking # 30 Manitoba Hydro to answer the following question: In regards to the cost-of-service study, in the tab called Average Rate Base Finance and Reserve, there's $122 million of motor vehicle rate base that seems to disappear, where did it go, and where can the costs be found in other parts?

UResponse U: The costs of motor vehicles are functionalized in Cost of Service through the use of an hourly activity rate that is charged to cost centers through SAP. Motor vehicle operating costs (fuel, repairs, parts, and insurance) are embedded in the fully-costed cost centers that are then functionalized in Schedule C12-Amended, while depreciation is included in Schedule C6-Amended costs. The $122M investment related to motor vehicles is included in Schedule C8-Amended only to reconcile to total rate base.

Undertaking Transcript Page # 254


May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking Transcript Page 254 Why the February 2012 loads and time shown in GAC/MH I-57 (9 am, 3,883,517 kW) do not match that provided in GAC/MH I-8 (6 pm, 3,589,907 kW)?

Response: The response to GAC/MH I-57 includes a table of the 12 monthly Common Bus CP (kW) that occurred during peak hours (06:00 to 22:00) from the 2011/2012 Load Research results. This table shows the single highest Common Bus peak for February occurred at 9:00 and was 3,883,517 kW. The response to GAC/MH I-8 includes a table of the Top 50 Generation Peaks that occurred during winter peak hours from 06:00 to 22:00 in December, January and February. This list includes a generation peak that occurred on 2012‐02‐09 at 18:00. The Common Bus load at that time was 3,589,907 kW.



May 30, 2016 Page 1 of 1


Manitoba Hydro Undertaking Transcript Page 255 In the tables in GAC/MH I-57, if you add up the classes, not including exports, you don't quite get the same thing as the common bus. Is there another category of load or is this a difference between at the meter versus with losses at the bus or basically why, if you look at attachment 1 for April of 2011, if you add up residential through large GS it doesn't come up to the common bus value?

Response: Common Bus kW demands are measured at the transformer banks serving domestic load from the transmission system (>100 kV). Class demands shown in Load Research results are measured (or estimated) at the meter. Distribution losses, seasonal classes, unmetered GSS services, A&RL (Area and Roadway Lighting) and FRWH (Flat Rate Water Heating) are not included in the responses to GAC/MH I-57.



May 30, 2016 Page 1 of 6


Manitoba Hydro Undertaking Transcript Page 602 Provide a table for the Top 50 hours (Summer and Winter) at the Common Bus, in a table similar to GAC/MH I-8

Response: Tables showing the Summer and Winter period Top 50 Common Bus hours from 2011/2012 Load Research Results follow. The tables also include the Top 50 Generation hours (from GAC/MH I-8) for comparison. Peak hours that exist in both tables are identified. Generation kW peaks are measured at generation and include imports. Common Bus kW peaks are measured at the transformer banks serving domestic load from the transmission system (>100 kV). Class demands shown in Load Research results are measured (or estimated) at the meter. Load Research Results 2011/2012

Load Research Results 2011/2012

Top 50 Common Bus Peaks

Top 50 Generation Peaks

During Summer Peak Hours

During Summer Peak Hours

June, July and August; 06:00 to 22:00

June, July and August; 06:00 to 22:00

Date Time Common Bus (kW)

Generation (kW)

Gen. Peak (Y/N)

Date Time Generation (kW)

Common Bus (kW)

CB Peak (Y/N)

2011-07-19 18:00 2,997,466 4,786,782 Y

2011-07-21 15:00 4,962,924 2,573,405 N

2011-07-19 17:00 2,957,866 4,735,552 N

2011-07-20 17:00 4,953,215 2,781,212 Y

2011-07-19 19:00 2,954,917 4,807,766 Y

2011-07-21 19:00 4,949,806 2,587,606 N

2011-07-19 16:00 2,924,088 4,682,012 N

2011-07-20 16:00 4,943,703 2,766,201 Y

2011-07-19 15:00 2,904,235 4,654,662 N

2011-07-21 16:00 4,925,747 2,578,432 N

2011-08-23 17:00 2,883,723 4,549,906 N

2011-07-21 14:00 4,907,351 2,532,544 N

2011-08-23 16:00 2,873,054 4,470,417 N

2011-07-21 18:00 4,903,661 2,616,344 N

2011-07-19 14:00 2,872,003 4,620,568 N

2011-07-13 16:00 4,900,783 2,413,725 N



May 30, 2016 Page 2 of 6

2011-07-18 17:00 2,870,077 4,840,233 Y

2011-07-20 20:00 4,895,871 2,626,394 N

2011-07-18 16:00 2,862,497 4,762,399 N

2011-07-20 21:00 4,889,438 2,571,223 N

2011-07-18 18:00 2,860,709 4,842,387 Y

2011-07-21 11:00 4,888,433 2,427,432 N

2011-07-18 15:00 2,857,057 4,798,705 Y

2011-07-20 13:00 4,887,368 2,626,667 N

2011-08-23 18:00 2,855,745 4,504,131 N

2011-06-29 19:00 4,885,921 2,656,882 N

2011-07-19 20:00 2,848,435 4,680,596 N

2011-07-21 17:00 4,885,119 2,596,507 N

2011-08-23 15:00 2,845,398 4,416,908 N

2011-06-29 18:00 4,885,044 2,655,739 N

2011-07-18 14:00 2,834,498 4,809,000 Y

2011-07-21 13:00 4,877,415 2,486,178 N

2011-07-04 14:00 2,820,037 4,753,570 N

2011-07-20 15:00 4,877,157 2,732,989 Y

2011-08-23 14:00 2,814,496 4,465,204 N

2011-07-20 18:00 4,872,186 2,773,259 Y

2011-07-04 18:00 2,813,589 4,786,217 Y

2011-07-13 17:00 4,870,952 2,451,422 N

2011-07-19 13:00 2,811,537 4,538,070 N

2011-07-21 12:00 4,860,753 2,481,918 N

2011-08-23 19:00 2,808,894 4,571,646 N

2011-07-20 14:00 4,859,693 2,658,859 N

2011-07-04 15:00 2,797,890 4,759,171 N

2011-07-13 15:00 4,858,414 2,397,370 N

2011-07-18 19:00 2,792,412 4,770,633 N

2011-07-13 18:00 4,854,034 2,443,064 N

2011-07-18 13:00 2,786,512 4,806,000 Y

2011-07-13 12:00 4,849,493 2,366,418 N

2011-07-19 12:00 2,783,738 4,606,607 N

2011-07-21 20:00 4,848,212 2,521,062 N

2011-07-20 17:00 2,781,212 4,953,215 Y

2011-06-30 13:00 4,847,979 2,725,734 Y

2011-07-04 17:00 2,776,718 4,670,853 N

2011-07-18 18:00 4,842,387 2,860,709 Y

2011-07-20 18:00 2,773,259 4,872,186 Y

2011-07-18 17:00 4,840,233 2,870,077 Y

2011-07-04 13:00 2,770,651 4,710,862 N

2011-06-29 20:00 4,836,660 2,619,588 N

2011-06-30 15:00 2,769,573 4,750,503 N

2011-07-13 14:00 4,835,667 2,403,455 N



May 30, 2016 Page 3 of 6

2011-07-20 16:00 2,766,201 4,943,703 Y

2011-07-20 19:00 4,834,738 2,707,772 N

2011-06-30 16:00 2,764,725 4,774,308 N

2011-06-29 17:00 4,821,251 2,613,659 N

2011-06-30 18:00 2,758,221 4,631,950 N

2011-07-20 22:00 4,818,827 2,499,097 N

2011-08-15 18:00 2,757,625 4,611,709 N

2011-07-18 21:00 4,813,143 2,740,214 Y

2011-07-04 16:00 2,757,002 4,665,779 N

2011-07-18 14:00 4,809,000 2,834,498 Y

2011-07-04 19:00 2,756,941 4,746,817 N

2011-07-19 19:00 4,807,766 2,954,917 Y

2011-06-30 17:00 2,754,013 4,714,196 N

2011-07-18 13:00 4,806,000 2,786,512 Y

2011-07-19 21:00 2,752,500 4,638,078 N

2011-07-18 15:00 4,798,705 2,857,057 Y

2011-07-18 20:00 2,750,594 4,774,539 Y

2011-07-20 12:00 4,793,792 2,560,918 N

2011-07-18 12:00 2,750,088 4,685,000 N

2011-08-16 14:00 4,791,723 2,484,828 N

2011-08-23 13:00 2,748,769 4,422,771 N

2011-07-13 13:00 4,789,873 2,388,592 N

2011-06-30 14:00 2,745,190 4,732,467 N

2011-08-03 15:00 4,789,383 2,423,428 N

2011-07-18 21:00 2,740,214 4,813,143 Y

2011-07-19 18:00 4,786,782 2,997,466 Y

2011-08-22 18:00 2,740,005 4,603,492 N

2011-07-04 18:00 4,786,217 2,813,589 Y

2011-07-20 15:00 2,732,989 4,877,157 Y

2011-08-02 18:00 4,783,895 2,607,872 N

2011-08-23 20:00 2,731,236 4,545,912 N

2011-07-21 10:00 4,782,916 2,338,112 N

2011-08-15 17:00 2,726,464 4,587,618 N

2011-06-30 11:00 4,779,988 2,611,974 N

2011-06-30 13:00 2,725,734 4,847,979 Y

2011-08-16 15:00 4,775,903 2,500,403 N

2011-07-15 18:00 2,725,624 4,611,178 N

2011-06-29 21:00 4,774,628 2,579,977 N

2011-07-15 17:00 2,718,193 4,619,222 N

2011-07-18 20:00 4,774,539 2,750,594 Y



May 30, 2016 Page 4 of 6

Load Research Results 2011/2012

Load Research Results 2011/2012 Top 50 Common Bus

Peaks

Top 50 Generation Peaks During Winter Peak Hours

During Winter Peak Hours

December, January and February; 06:00 to 22:00

December, January and February; 06:00 to 22:00

Date Time Common Bus (kW)

Generation (kW)

Gen. Peak (Y/N)

Date Time Generation (kW)

Common Bus (kW)

CB Peak (Y/N)

2012-01-19 9:00 4,035,502 4,835,169 Y

2012-01-11 14:00 4,937,215 3,449,374 N

2012-01-19 8:00 4,003,319 4,752,533 N

2012-01-11 13:00 4,924,469 3,445,533 N

2012-01-18 19:00 4,001,604 4,908,946 Y

2012-01-11 15:00 4,910,944 3,463,877 N

2012-01-18 20:00 3,991,177 4,880,712 Y

2012-01-18 19:00 4,908,946 4,001,604 Y

2012-01-19 19:00 3,982,313 4,809,357 Y

2012-01-11 16:00 4,906,604 3,491,501 N

2012-01-20 9:00 3,978,834 4,788,204 Y

2012-01-18 21:00 4,902,384 3,944,784 Y

2012-01-17 18:00 3,965,533 4,664,183 N

2012-02-09 18:00 4,886,393 3,589,907 N

2012-01-19 18:00 3,964,326 4,753,369 N

2012-01-18 20:00 4,880,712 3,991,177 Y

2012-01-18 18:00 3,960,664 4,819,902 Y

2012-01-11 9:00 4,871,986 3,424,202 N

2012-01-17 19:00 3,957,575 4,664,904 N

2012-01-12 9:00 4,871,846 3,696,116 N

2012-01-19 10:00 3,955,062 4,825,047 Y

2012-01-03 19:00 4,863,251 3,183,841 N

2012-01-19 20:00 3,945,800 4,747,044 N

2012-01-11 12:00 4,860,518 3,442,802 N

2012-01-18 21:00 3,944,784 4,902,384 Y

2012-01-06 17:00 4,857,679 3,039,481 N

2012-01-20 8:00 3,932,773 4,704,083 N

2012-01-11 18:00 4,851,275 3,702,784 N

2012-01-17 20:00 3,929,664 4,768,073 Y

2012-01-11 17:00 4,846,272 3,598,549 N

2012-01-18 9:00 3,927,875 4,679,832 N

2012-01-11 8:00 4,839,721 3,370,175 N

2012-01-19 21:00 3,926,857 4,795,276 Y

2011-12-08 18:00 4,838,358 3,695,681 N



May 30, 2016 Page 5 of 6

2012-01-18 8:00 3,889,750 4,724,459 N

2012-01-19 9:00 4,835,169 4,035,502 Y

2012-01-20 10:00 3,885,399 4,662,463 N

2012-01-11 11:00 4,832,641 3,418,276 N

2012-01-17 21:00 3,884,303 4,670,000 N

2012-01-19 10:00 4,825,047 3,955,062 Y

2012-02-10 9:00 3,883,517 4,625,678 N

2012-01-11 20:00 4,820,417 3,636,014 N

2012-01-18 10:00 3,880,751 4,785,371 Y

2012-01-18 18:00 4,819,902 3,960,664 Y

2012-01-18 22:00 3,878,232 4,812,100 Y

2012-01-11 19:00 4,813,286 3,671,153 N

2012-01-19 11:00 3,873,790 4,766,402 Y

2012-01-18 22:00 4,812,100 3,878,232 Y

2012-01-17 9:00 3,866,233 4,606,363 N

2012-01-18 11:00 4,809,673 3,842,513 Y

2012-02-10 8:00 3,858,769 4,612,676 N

2012-01-19 19:00 4,809,357 3,982,313 Y

2012-01-19 22:00 3,846,257 4,743,196 N

2012-01-05 18:00 4,809,181 2,985,853 N

2012-01-18 11:00 3,842,513 4,809,673 Y

2012-01-12 10:00 4,800,221 3,629,492 N

2012-01-17 8:00 3,838,597 4,618,471 N

2011-12-08 17:00 4,797,786 3,570,034 N

2012-01-17 10:00 3,802,754 4,580,082 N

2012-01-06 18:00 4,797,555 3,176,695 N

2012-01-17 22:00 3,796,937 4,620,000 N

2012-01-19 21:00 4,795,276 3,926,857 Y

2012-01-17 17:00 3,794,230 4,677,185 N

2012-01-11 21:00 4,792,830 3,577,514 N

2012-01-19 17:00 3,791,995 4,731,180 N

2012-01-11 10:00 4,791,709 3,391,528 N

2012-01-18 12:00 3,789,003 4,760,845 Y

2011-12-08 12:00 4,791,328 3,361,929 N

2012-01-19 12:00 3,784,346 4,705,275 N

2012-02-09 19:00 4,789,217 3,675,735 N

2012-01-18 17:00 3,777,602 4,729,094 N

2012-01-10 18:00 4,789,074 3,039,541 N

2012-01-20 19:00 3,772,446 4,579,702 N

2012-01-20 9:00 4,788,204 3,978,834 Y

2012-02-10 10:00 3,763,350 4,536,563 N

2012-01-18 10:00 4,785,371 3,880,751 Y

2012-01-19 7:00 3,761,965 4,667,270 N

2012-02-10 19:00 4,783,961 3,726,526 Y



May 30, 2016 Page 6 of 6

2012-01-16 18:00 3,747,443 4,754,092 Y

2012-01-03 18:00 4,779,536 3,241,023 N

2012-01-20 18:00 3,742,882 4,601,433 N

2011-12-28 10:00 4,775,578 3,195,619 N

2012-01-20 11:00 3,742,330 4,518,500 N

2011-12-02 17:00 4,771,524 3,057,681 N

2012-01-17 11:00 3,735,217 4,584,046 N

2012-01-17 20:00 4,768,073 3,929,664 Y

2012-01-20 20:00 3,734,516 4,524,073 N

2012-01-19 11:00 4,766,402 3,873,790 Y

2012-02-10 19:00 3,726,526 4,783,961 Y

2012-01-12 11:00 4,765,900 3,538,203 N

2012-01-16 20:00 3,723,303 4,727,411 N

2012-01-18 12:00 4,760,845 3,789,003 Y

2012-01-20 7:00 3,716,594 4,670,185 N

2012-01-16 8:00 4,760,239 3,510,146 N

2011-12-05 19:00 3,714,260 4,540,203 N

2012-02-09 21:00 4,758,994 3,692,998 N

2011-12-05 18:00 3,711,647 4,599,612 N

2012-01-07 18:00 4,754,733 3,106,709 N

2012-01-16 19:00 3,711,383 4,670,737 N

2012-01-16 18:00 4,754,092 3,747,443 Y



May 30, 2016 Page 1 of 3


Manitoba Hydro Undertaking Transcript Page 603 Provide monthly system peak loads for a) Domestic load only, b) Domestic loads and dependable exports, and c) Domestic loads and dependable and opportunity exports, for 2012/13, 2013/14, 2014/15, or 2015/16 to date.

Response: a) Please see the following two tables listing the single monthly Common Bus CP loads from

2012/13 and 2013/14 Load Research. Load Research results for 2014/15 and 2015/16 are not yet available.

b) and c) As noted in the response to GAC/MH I-57a-c, this data does not distinguish exports between dependable and opportunity.



May 30, 2016 Page 2 of 3

Load Research 2012/2013 12 Monthly Common Bus CP During Peak Hours (06:00 to 22:00)

2012-04-10 08:00

2012-05-04 09:00

2012-06-26 18:00

2012-07-11 18:00

2012-08-23 18:00

2012-09-04 18:00

GS Large 30 - 100 kV 111,438 127,275 122,012 94,783 111,682 129,793 GS Large 30 - 100 kV Curtailable 24,866 24,351 24,527 24,571 24,590 24,479 GS Large > 100 kV 335,757 260,192 309,322 289,282 275,463 286,878 GS Large > 100 kV Curtailable 219,624 208,264 203,652 192,297 205,692 169,160 GS Large 750 V - 30 kV 214,878 212,927 226,014 229,815 230,921 222,366 GS Large 750 V - 30 kV SEP 286 821 462 142 39 71 GS Medium 392,246 371,844 427,730 436,225 424,827 413,764 GS Medium SEP 4,031 3,229 635 417 449 377 GS Small Demand 236,542 232,914 254,525 247,204 251,647 243,626 GS Small Non Demand 201,926 174,140 224,801 231,813 223,873 210,138 Residential 1,057,676 735,082 967,613 996,662 1,021,744 919,392

2012-10-29 09:00

2012-11-29 18:00

2012-12-11 18:00

2013-01-24 09:00

2013-02-01 09:00

2013-03-19 08:00

GS Large 30 - 100 kV 101,724 133,911 126,206 125,289 116,064 134,935 GS Large 30 - 100 kV Curtailable 24,326 24,456 24,275 24,486 24,741 24,328 GS Large > 100 kV 322,687 324,408 356,024 308,872 325,068 339,924 GS Large > 100 kV Curtailable 222,411 229,534 237,113 226,145 224,831 234,901 GS Large 750 V - 30 kV 223,788 224,525 237,676 255,160 253,624 233,448 GS Large 750 V - 30 kV SEP 666 125 116 114 126 268 GS Medium 433,242 453,118 483,901 520,407 510,385 458,884 GS Medium SEP 4,078 5,111 6,047 6,351 6,168 5,696 GS Small Demand 279,631 315,476 344,487 377,578 374,523 308,150 GS Small Non Demand 220,046 276,279 296,085 319,721 322,733 269,597 Residential 1,061,053 1,409,054 1,557,566 1,585,018 1,735,502 1,427,349



May 30, 2016 Page 3 of 3

Load Research 2013/2014

12 Monthly Common Bus CP During Peak (06:00 to 22:00)

2013-04-09 8:00

2013-05-02 9:00

2013-06-25 17:00

2013-07-03 18:00

2013-08-27 17:00

2013-09-06 17:00

GS Large 30 - 100 kV 120,915 109,641 103,742 96,765 142,363 129,340 GS Large 30 - 100 kV Curtailable 24,284 24,188 24,311 24,311 22,693 24,592 GS Large > 100 kV 368,902 305,341 289,964 354,815 210,095 253,041 GS Large > 100 kV Curtailable 222,851 200,182 168,888 173,148 176,044 146,859 GS Large 750 V - 30 kV 219,436 221,409 246,682 229,204 250,746 247,981 GS Large 750 V - 30 kV SEP 510 678 1,218 461 1,038 947 GS Medium 414,124 404,533 463,887 427,770 455,582 459,468 GS Medium SEP 5,090 3,888 421 279 384 182 GS Small Demand 273,250 264,307 277,293 255,317 277,417 285,483 GS Small Non Demand 225,780 210,382 242,396 214,021 251,868 243,595 Residential 1,222,805 988,460 870,141 972,183 984,284 985,647

2013-10-29 9:00

2013-11-22 18:00

2013-12-31 18:00

2014-01-06 18:00

2014-02-27 8:00

2014-03-03 8:00

GS Large 30 - 100 kV 122,039 118,030 136,175 123,171 115,731 161,587 GS Large 30 - 100 kV Curtailable 23,941 24,012 23,941 24,012 23,977 23,994 GS Large > 100 kV 319,533 422,191 302,888 395,490 375,015 381,510 GS Large > 100 kV Curtailable 162,648 198,276 190,887 205,511 204,210 205,344 GS Large 750 V - 30 kV 226,670 232,456 203,812 241,142 240,934 238,056 GS Large 750 V - 30 kV SEP 807 100 118 123 128 126 GS Medium 437,471 462,711 460,855 516,084 504,726 489,152 GS Medium SEP 4,617 5,132 6,479 6,343 6,517 5,984 GS Small Demand 295,175 323,036 349,127 381,311 356,156 341,363 GS Small Non Demand 240,785 284,996 274,646 301,325 294,021 297,059 Residential 1,158,371 1,504,256 1,804,525 1,836,341 1,692,411 1,674,646



May 30, 2016 Page 1 of 2


Manitoba Hydro Undertaking Transcript Page 791 Regarding the C10 allocator, confirm that this was used to allocate costs that are not the DSM portion of the curtailable costs. This is customer service cost. Explain what the seventy- seven hundred (7,700) number represents?

Response: “C10 Customer Service General” allocates customer service costs only and does not include the cost of the Curtailable Rate Program (CRP). The higher C10 weighting factor for the curtailable compared to non-curtailable GSL customers is the result of departmental estimates of relative effort required.

The weighting column was added to the electronic model for the current Cost of Service Review to allow stakeholders to test different weighting factors. The allocation to each of the GSL curtailable subclasses is based on the 1.4% shares as determined in MIPUG/MH I-4a, with the 7,724 / 3,899 weighting factors and weighted customer count back calculated to match the allocators shown in PCOSS14-Amended.

The cost related to Public Accountability is allocated to all rate classes, 30% of which is shared equally among all classes; the remaining 70% is allocated based on each class’ revenues. The approach recognizes that a portion of regulatory costs are incurred for the benefit of all customer classes equally, and the remaining cost allocated based on revenue reflects that larger classes intuitively drive a greater portion of regulatory activities. For the equal share component, the GSL class in total is given a share equal to other classes, but it is then distributed evenly between the five subclasses (GSL 0-30kV, 30-100kV curtailable and non-curtailable, and GSL >100kV curtailable and non-curtailable).

The allocation of Consumer Consultation and Information provided in MIPUG/MH I-4a is a summary based on individual departmental estimates weighted by planned costs, as indicated below:



May 30, 2016 Page 2 of 2

Class Customer Service1

Customer Engineering Services – Inquiries

Customer Engineering Services – Inquiries

Agricultural

Energy Services &

Sales - Consultations

Key Accounts

Major Accounts

Common/Admin3

Weighted Totals

Res 45% 0% 0% 20% 0% 0% 88% 46% GSS 35% 10% 33% 30% 0% 0% 12% 27% GSM 10% 24% 33% 48% 7% 0% 0% 10% GSL 0 - 30 kV 4% 20% 17% 2% 15% 65% 0% 7% GSL 30-100KV 3% 16% 13% 0% 9% 25% 0% 4% GSL 30-100KV Curt2 1% 6% 4% 0% 3% 8% 0% 1% GSL >100KV 1% 22% 0% 0% 62% 1% 0% 4% GSL >100KV Curt 1% 2% 0% 0% 5% 1% 0% 1% SEP 0% 0% 0% 0% 0% 0% 0% 0% Lighting 0% 0% 0% 0% 0% 0% 0% 0% Total 100% 100% 100% 100% 100% 100% 88% 100% Planned Orders 12,677,114 769,625 198,525 890,289 710,924 831,513 3,342,488

Note 1: Customer Service includes the costs related to line locates, safety watches, consumer consultations, building moves, and education/safety.

Note 2: Estimate has been provided for the GSL 30-100kV as a whole and is prorated between Curtailable and Non-Curtailable subclasses based on forecast energy

Note 3: Shares based on relative customer count

Documents

UManitoba Hydro Undertaking # 1 UResponse U: /kWh applied ... · Undertaking # 1 Transcript Page # 145 Workshop Date May 11, 2016 May 30, 2016 Page 2 of 6 Schedule B1 Manitoba Hydro