manitoba hydro prospective cost of service study for ...€¦ · manitoba hydro 2017/18 &...

MANITOBA HYDRO

PROSPECTIVE COST OF SERVICE STUDY

FOR FISCAL YEAR ENDING

MARCH 31, 2018

INDEX

Section 1: Results ............................................................................................................................ 1

Section 2: Rate Base ........................................................................................................................ 5

Section 3: Functionalization of Operating & Depreciation Costs ................................................. 10

Section 4: Allocation of Costs ....................................................................................................... 15

Section 5: Development of Class Loads ........................................................................................ 27

Section 6: Revenue ....................................................................................................................... 35

Section 7: Historical RCC Ratios .................................................................................................... 37

Manitoba Hydro 2017/18 & 2018/19 General Rate Application Appendix 8.1

Available in accessible formats upon request

Manitoba Hydro May 2017 PCOSS18 Page 1

SECTION 1: RESULTS


Section 1 Schedule 1.1 Revenue Cost Coverage Analysis


Man

itoba

Hyd

roPr

ospe

ctiv

e C

ost O

f Ser

vice

Stu

dyM

arch

31,

201

8R

even

ue C

ost C

over

age

Ana

lysi

s

S U

M M

A R

Y

Cla

ssR

CC

%N

et E

xpor

tT

otal

RC

C %

Tot

al C

ost

Rev

enue

Prio

r to

Rev

enue

Rev

enue

Cur

rent

Cus

tom

er C

lass

($00

0)($

000)

NER

($00

0)($

000)

Rat

es

Res

iden

tial

810,

916

60

7,10

6

74.9

%16

1,91

1

769,

017

94

.8%

Gen

eral

Ser

vice

- Sm

all N

on D

eman

d15

1,81

4

139,

479

91

.9%

31,3

13

170,

793

11

2.5%

Gen

eral

Ser

vice

- Sm

all D

eman

d18

5,20

0

146,

983

79

.4%

40,0

99

187,

082

10

1.0%

Gen

eral

Ser

vice

- M

ediu

m25

3,46

6

191,

737

75

.6%

57,4

72

249,

209

98

.3%

Gen

eral

Ser

vice

- La

rge

0 - 3

0kV

120,

404

89

,652

74

.5%

29,6

13

119,

265

99

.1%

Gen

eral

Ser

vice

- La

rge

30-1

00kV

*86

,975

69

,995

80

.5%

25,0

54

95,0

49

109.

3%G

ener

al S

ervi

ce -

Larg

e >1

00kV

*23

0,68

8

180,

458

78

.2%

70,0

42

250,

500

10

8.6%

*Inc

lude

s C

urta

ilmen

t Cus

tom

ers

SEP

737

84

4

114.

4%-

84

4

114.

4%

Are

a &

Roa

dway

Lig

htin

g22

,987

21

,571

93

.8%

1,48

2

23

,053

10

0.3%

Tot

al G

ener

al C

onsu

mer

s1,

863,

186

1,44

7,82

6

77

.7%

416,

987

1,

864,

813

100.

1%

Die

sel

8,99

6

7,

368

81.9

%-

7,

368

81.9

%

Expo

rt38

,159

45

5,14

6

1192

.7%

(416

,987

)

38

,159

10

0.0%

Tot

al S

yste

m1,

910,

341

1,91

0,34

1

10

0.0%

-

1,91

0,34

1

10

0.0%


Section 1 Schedule 1.2 Customer, Demand, Energy Cost Analysis


Man

itoba

Hyd

ro

Pros

pect

ive

Cos

t Of S

ervi

ce S

tudy

- M

arch

31,

201

8

Cus

tom

er, D

eman

d, E

nerg

y C

ost A

naly

sis

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

77,8

1450

8,24

212

.76

38

7,88

6

0%

n/a

n/a

183,

304

7,58

6,09

67.

53

**

GS

Smal

l - N

on D

eman

d13

,971

42,7

0727

.26

67

,584

0%

n/a

n/a

38,9

46

1,

622,

627

6.57

**

GS

Smal

l - D

eman

d12

,317

4,19

724

4.57

81

,580

37

%2,

623

11.4

5

51,2

03

2,

146,

454

4.79

Gen

eral

Ser

vice

- M

ediu

m9,

511

2,12

537

2.96

11

0,28

6

92

%7,

722

13.1

4

76,1

97

3,

204,

436

2.65

Gen

eral

Ser

vice

- La

rge

<30k

V3,

531

321

n/a

46,1

14

100%

4,30

211

.54

*

41,1

47

1,

745,

362

2.36

G

ener

al S

ervi

ce -

Larg

e 30

-100

kV2,

462

40n/

a23

,211

10

0%3,

358

7.65

*

36,2

48

1,

578,

519

2.30

G

ener

al S

ervi

ce -

Larg

e >1

00kV

5,

826

16n/

a52

,900

10

0%7,

815

7.51

*

101,

920

4,50

4,93

92.

26

SEP

6731

181.

17

90

0%n/

an/

a58

0

25

,500

2.63

**

Are

a &

Roa

dway

Lig

htin

g16

,230

157,

982

8.56

3,28

3

0%n/

an/

a1,

991

82

,415

6.40

**

Tot

al G

ener

al C

onsu

mer

s14

1,72

971

5,66

177

2,93

4

25

,818

531,

537

22,4

96,3

47

Die

sel

396

785

42.0

6

-

0%

n/a

n/a

8,59

9

14,5

46

59

.12

**

Expo

rtn/

an/

an/

a-

0%n/

an/

a38

,159

8,55

7,00

0

0.

45

***

Tot

al S

yste

m14

2,12

571

6,44

677

2,93

4

25

,818

578,

296

31,0

67,8

93

* - 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


Section 1 Schedule 1.3 Functional Cost Analysis


M

anito

ba H

ydro

Pros

pect

ive

Cos

t Of S

ervi

ce S

tudy

- M

arch

31,

201

8Fu

nctio

nal B

reak

dow

n

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

649,

004

291,

185

44.9

%66

,704

10.3

%37

,236

5.7%

73,6

5211

.3%

180,

228

27.8

%

Gen

eral

Ser

vice

- Sm

all N

on D

eman

d12

0,50

0

57

,563

47

.8%

11,6

539.

7%6,

456

5.4%

12,6

5610

.5%

32,1

7326

.7%

Gen

eral

Ser

vice

- Sm

all D

eman

d14

5,10

0

74

,188

51

.1%

14,4

4810

.0%

7,98

45.

5%7,

802

5.4%

40,6

7928

.0%

Gen

eral

Ser

vice

- M

ediu

m19

5,99

4

10

7,33

3

54

.8%

19,7

0310

.1%

10,8

435.

5%8,

298

4.2%

49,8

1725

.4%

Gen

eral

Ser

vice

- La

rge

<30k

V90

,791

55,9

78

61.7

%9,

479

10.4

%5,

185

5.7%

2,91

63.

2%17

,234

19.0

%G

ener

al S

ervi

ce -

Larg

e 30

-100

kV61

,921

47,8

72

77.3

%7,

507

12.1

%4,

080

6.6%

2,18

23.

5%28

10.

5%G

ener

al S

ervi

ce -

Larg

e >1

00kV

16

0,64

6

13

3,95

1

83

.4%

20,8

6913

.0%

00.

0%5,

585

3.5%

241

0.2%

SEP

737

580

78.7

%90

12.2

%0

0.0%

446.

0%23

3.1%

Are

a &

Roa

dway

Lig

htin

g21

,504

2,77

8

12.9

%49

92.

3%27

41.

3%91

24.

2%17

,041

79.2

%

Tot

al G

ener

al C

onsu

mer

s1,

446,

199

77

1,42

7

53

.3%

150,

951

10.4

%72

,057

5.0%

114,

047

7.9%

337,

717

23.4

%

Die

sel

8,99

6

8,59

9

95.6

%0

0.0%

00.

0%0

0.0%

396

4.4%

Expo

rt38

,159

38,1

59

100.

0%0

0.0%

00.

0%0

0.0%

00.

0%

Tot

al S

yste

m1,

493,

354

81

8,18

6

54

.8%

150,

951

10.1

%72

,057

4.8%

114,

047

7.6%

338,

114

22.6

%



SECTION 2: RATE BASE


Section 2 Schedule 2.1 Functionalization of Rate Base


2018

PR

OSP

ECT

IVE

CO

ST O

F SE

RV

ICE

STU

DY

FUN

CT

ION

ALI

ZA

TIO

N O

F R

AT

E B

ASE

INV

EST

MEN

T

FOR

ECA

ST Y

EAR

EN

DIN

G M

AR

CH

31,

201

8

DIR

ECT

ALL

OC

AT

ION

SR

ate

Bas

eSu

b-D

istr

ibut

ion

Anc

illar

yA

sset

Cla

ssIn

vest

men

tG

ener

atio

nT

rans

mis

sion

Tra

nsm

issi

onPl

ant

Serv

ices

Serv

ices

Ligh

ting

Die

sel

GEN

ERA

TIO

N6,

126,

286,

090

6,12

6,28

6,09

0

-

-

-

-

-

-

-

-T

herm

al14

4,59

0,26

0

144,

590,

260

-

-

-

-

-

-

-

DIE

SEL

3,35

2,67

6

-

-

-

-

-

-

-

3,

352,

676

SUB

STA

TIO

N1,

938,

288,

350

19,3

78,8

22

87

3,77

2,40

7

272,

885,

514

71

1,69

9,42

6

-

60,5

52,1

80

-

-

-

HV

DC

449,

292,

382

44

9,29

2,38

2

-

-

-

-

-

-

-

TR

AN

SMIS

SIO

N51

1,15

7,43

8

21,7

46,5

80

48

9,41

0,85

8

-

-

-

-

-

-

- H

VD

C15

7,61

8,94

4

157,

618,

944

-

-

-

-

-

-

-

-

Ded

icat

ed R

adia

l Tab

s2,

997,

748

-

2,99

7,74

8

-

-

-

-

-

-

-

US

Inte

rcon

nect

ions

65,7

35,5

70

-

65

,735

,570

-

-

-

-

-

-

- N

on-T

ariff

able

Tra

nsm

issi

o68

,599

,853

-

68,5

99,8

53

-

-

-

-

-

-

DIS

TR

IBU

TIO

N1,

746,

202,

254

-

-

-

1,65

9,35

2,83

4

-

-

85

,888

,944

960,

476

SUB

TR

AN

SMIS

SIO

N26

7,23

8,16

2

-

-

267,

238,

162

-

-

-

-

-

TR

AN

SFO

RM

ERS

-

SU

BST

AT

ION

49,0

77,3

21

30

,111

,753

9,50

6,45

5

2,

937,

446

6,52

1,66

7

-

-

-

-

- D

IST

RIB

UT

ION

2,68

7,31

3

-

-

-

2,

687,

313

-

-

-

-

MET

ERS

52,5

43,0

91

-

-

-

52

,543

,091

-

-

-

-

BU

ILD

ING

S 44

1,12

0,84

3

213,

296,

415

54

,303

,093

16,7

12,4

46

69

,831

,927

78,5

85,4

08

-

5,

630,

328

2,76

1,22

6

CO

MM

UN

ICA

TIO

N23

2,53

2,65

3

131,

396,

630

32

,655

,135

10,8

32,7

57

47

,472

,550

-

10,1

75,5

81

-

-

`

GEN

ERA

L EQ

UIP

MEN

T26

9,53

7,58

2

130,

330,

273

33

,180

,759

10,2

11,7

87

42

,669

,325

48,0

17,9

55

-

3,

440,

293

1,68

7,18

9

S

UB

TO

TA

L12

,528

,858

,531

7,

424,

048,

149

1,63

0,16

1,87

7

58

0,81

8,11

2

2,59

2,77

8,13

4

12

6,60

3,36

3

70,7

27,7

61

94

,959

,566

8,76

1,56

7

MO

TO

R V

EHIC

LES

156,

394,

457

Tot

al R

ate

Bas

e In

vest

men

t12

,685

,252

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7,

424,

048,

149

1,63

0,16

1,87

7

58

0,81

8,11

2

2,59

2,77

8,13

4

12

6,60

3,36

3

70,7

27,7

61

94

,959

,566

8,76

1,56

7


Section 2 Schedule 2.2 Functionalization of Interest


2018

PR

OSP

ECT

IVE

CO

ST O

F SE

RV

ICE

STU

DY

FUN

CT

ION

ALI

ZA

TIO

N O

F IN

TER

EST

EX

PEN

SE &

RES

ERV

E C

ON

TR

IBU

TIO

NFO

REC

AST

YEA

R E

ND

ING

MA

RC

H 3

1, 2

018

DIR

ECT

ALL

OC

AT

ION

SA

sset

Cla

ssIn

tere

st &

Res

erve

Sub-

Dis

trib

utio

nA

ncill

ary

Expe

nse

Gen

erat

ion

Tra

nsm

issi

onT

rans

mis

sion

Plan

tSe

rvic

esSe

rvic

esLi

ghtin

gD

iese

l

GEN

ERA

TIO

N28

6,38

5,22

7

28

6,38

5,22

7

-

-

-

-

-

-

-

-TH

ERM

AL

6,75

9,15

5

6,75

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5

-

-

-

-

-

-

-

DIE

SEL

156,

727

-

-

-

-

-

-

-

156,

727

SUB

STA

TIO

N90

,609

,080

905,

901

40

,846

,200

12

,756

,567

33,2

69,7

82

-

2,83

0,63

0

-

-

-

HV

DC

21,0

03,0

51

21

,003

,051

-

-

-

-

-

-

-

TR

AN

SMIS

SIO

N23

,895

,054

1,01

6,58

6

22

,878

,468

-

-

-

-

-

-

-

HV

DC

7,36

8,20

6

7,36

8,20

6

-

-

-

-

-

-

-

-

Ded

icat

ed R

adia

l Tab

s14

0,13

6

-

14

0,13

6

-

-

-

-

-

-

- U

S In

terc

onne

ctio

ns3,

072,

938

-

3,

072,

938

-

-

-

-

-

-

- N

on-T

ariff

able

Tra

nsm

issi

on3,

206,

834

-

3,

206,

834

-

-

-

-

-

-

DIS

TR

IBU

TIO

N81

,629

,640

-

-

-

77

,569

,694

-

-

4,01

5,04

7

44,8

99

SUB

TR

AN

SMIS

SIO

N12

,492

,571

-

-

12,4

92,5

71

-

-

-

-

-

TR

AN

SFO

RM

ERS

-

SU

BST

AT

ION

2,29

4,21

5

1,40

7,63

3

44

4,39

8

137,

317

304,

868

-

-

-

-

-

DIS

TR

IBU

TIO

N12

5,62

4

-

-

-

125,

624

-

-

-

-

MET

ERS

2,45

6,23

0

-

-

-

2,

456,

230

-

-

-

-

BU

ILD

ING

S 20

,621

,057

9,97

0,95

8

2,

538,

504

781,

256

3,26

4,43

0

3,

673,

629

-

263,

201

129,

079

CO

MM

UN

ICA

TIO

N10

,870

,194

6,14

2,39

3

1,

526,

528

506,

398

2,21

9,19

7

-

475,

677

-

-

GEN

ERA

L EQ

UIP

MEN

T12

,600

,062

6,09

2,54

4

1,

551,

099

477,

370

1,99

4,66

1

2,

244,

693

-

160,

823

78,8

71

S

UB

TO

TA

L58

5,68

6,00

0

34

7,05

1,65

3

76,2

05,1

06

27,1

51,4

79

12

1,20

4,48

6

5,91

8,32

2

3,30

6,30

8

4,43

9,07

1

409,

577

MO

TO

R V

EHIC

LES

-

Tot

al In

tere

st E

xp A

lloca

ted

585,

686,

000

347,

051,

653

76

,205

,106

27

,151

,479

121,

204,

486

5,

918,

322

3,

306,

308

4,

439,

071

40

9,57

7


Section 2 Schedule 2.3 Functionalization of Rate Base for Capital Tax


2018

PR

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IVE

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437

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72

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96

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8,

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780


Section 2 Schedule 2.4 Functionalization of Capital Tax


2018

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IVE

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446,

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450,

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706,

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63,2

71



SECTION 3: FUNCTIONALIZATION OF OPERATING & DEPRECIATION COSTS


Section 3 Functionalization of Operating & Depreciation Costs


Functionalization of Operating

Manitoba Hydro’s financial reporting system (SAP), via settlement cost centres (SCC), provides

the initial functionalization of all functional operating & maintenance costs. Manitoba Hydro

uses approximately 400 cost centers to provide the level of detail necessary to functionalize

operating costs, as well as depreciation and rate base.

The number of costs centers used depends on the degree of granularity required for either

functionalization or associated business purposes (ie OATT). At the Generation and

Transmission level there is generally one cost center corresponding to each facility (generating

station, switching station, convertor station, substation or transmission line). Costs related to

Subtransmission, Distribution Plant and Distribution Services are generally captured in a smaller

number of non‐location specific cost centers, each corresponding to the sub‐functions used in

the study. For example there are distinct cost centers for Limestone GS, Henday CS and the

Glenboro‐Rugby 230 kV transmission line, but only a single cost center for subtransmission lines

or distribution substations.

Facility cost centres are used to capture the costs associated with maintaining or operating

facilities used to produce, transmit or distribute electrical energy or involved in providing

customer service. Non‐facility cost centres capture the costs associated with various

administrative services/functions or facilities which support administrative functions. These

administrative costs include activities such as human resources, payroll, buildings and other

such costs incurred to support the line activities that provide the delivery of power to our

customers.

The PCOSS uses two similar approaches to functionalize administrative and common costs in

proportion to labour costs that result in nearly identical functionalization:

SAP Labour Allocator – granular allocation to SCC level based on labour costs charged to

each SCC. Used in the initial SAP functionalization of common O&M costs.


Section 3 Functionalization of Operating & Depreciation Costs


Internal COS Labour Allocator – broad allocation to functions in proportion to

functionalized Operating costs (excluding water rentals, fuel, and power purchases).

Used for any subsequent offline functionalization of common Operating, Depreciation

or Rate Base.

The costs for non‐facility cost centres are allocated to facility cost centres on the basis of the

SAP Labour Allocator. Allocating administrative costs to a facility cost centre, which is in turn

functionalized, allows Manitoba Hydro to functionalize these costs without the need for explicit

functionalization of administrative costs in the COSS.

The functionalization of some costs is done outside of the Corporation’s accounting system

such as communication system costs which are functionalized to all functions except customer

service on the basis of the Internal COS Labour Allocator.

Schedule 3.1 provides the results of the functionalization of Operating costs.

Functionalization of Depreciation

The functionalization of Depreciation expense uses the same approach and cost centers used

for Operating costs. In PCOSS18, depreciation on Buildings and General Equipment has been

functionalized off‐line as part of Cost of Service. Previously, this common depreciation was

allocated to the individual facility cost center level as part of the SAP functionalization process.

Schedule 3.2 provides the results of the functionalization of Depreciation costs.


Section 3 Schedule 3.1 Functionalization of Operating Costs


2018 PROSPECTIVE COST OF SERVICEFiscal Year Ending March 31, 2018

Functionalization of Operating Costs

Distribution Customer Ancilary StreetSCC Description Operating Generation Transmission Subtransmission Plant Service Services Diesel LightingCommon Generation Costs 32,790,072 32,790,072 Demand Side Management 1,079,294 1,079,294 Hydraulic Generation 241,513,639 241,513,639 Thermal Generation 33,524,827 33,524,827 Purchased Power 127,355,500 127,355,500 Generation Outlet Transmission 846,222 846,222 Generating Switching Stations 352,688 352,688 Convertor Stations 44,500,456 44,500,456 HVDC Lines 3,858,438 3,858,438 Generation Facilities & Costs 485,821,135 485,821,135

Common Trans Costs 29,033,639 - 29,033,639 Switching Stations 2,185,128 2,185,128 Transmission Substations 11,486,970 11,085,206 401,764 Dedicated Taps - - Non Tariffable Transmission 2,435,528 2,435,528 US Interface 6,444,115 6,444,115 Networked AC Transmission Lines 14,073,921 14,073,921 Transmission Facilities/Costs 65,659,301 - 65,257,536 401,764

Common Subtrans / Dist Costs 13,442,728 2,595,904 10,846,824

Common Subtransmission 7,316,555 7,316,555 Subtransmission Substations 9,308,991 9,308,991 Subtransmission Lines 1,822,922 1,822,922 Subtrans. Facilities & Costs 18,448,468 18,448,468

Common Distribution Costs 3,955,366 3,955,366 Distribution Substations 26,457,184 26,457,184 Distribution Pole & Wire 40,868,711 40,868,711 Transform/Volt. Regulation 5,763,709 5,763,709 Area & Roadway Lighting 6,215,185 6,215,185 Meters & Metering Transformers 40,818 40,818 Dist. Facilities & Costs 83,300,974 77,085,789 6,215,185

Market Research & Development 1,324,380 1,324,380 Education & Safety 1,240,782 1,240,782 Industrial & Commercial Solutions 4,313,006 4,313,006 Power Quality Investigations 1,046,615 1,046,615 Service Extensions 13,897,481 13,897,481 Contact Center - Outages 1,219,672 1,219,672 Rates & Regulatory 2,990,725 2,990,725 Line Locates 4,060,223 4,060,223 Bldg Moves/Safety Watches 3,058,386 3,058,386 Customer & Community Service Work 4,258,894 4,258,894 Customer General Inquiries 2,024,966 2,024,966 Wiring Inspections 3,458,817 3,458,817 Customer Billing 21,728,506 21,728,506 Customer Collections 11,730,206 11,730,206 Meter Reading 10,395,887 10,395,887 Customer Service Costs 86,748,547 86,748,547

Isolated Diesel Facilities 6,923,700 6,923,700

Communication & Control System 13,779,410 4,346,541 742,551 586,000 3,457,193 - 4,647,125 - -

Planned Grants In Lieu Taxes 16,911,948 11,161,886 4,058,868 338,239 1,352,956

Buildings and General Equipment 50,387,789 24,364,151 6,202,864 1,909,008 7,976,672 8,976,554 - 315,406 643,134

841,424,000 525,693,712 76,261,819 23,877,619 100,719,435 95,725,101 5,048,889 7,239,106 6,858,319


Section 3 Schedule 3.2 Functionalization of Depreciation Costs


2018 PROSPECTIVE COST OF SERVICEFiscal Year Ending March 31, 2018

Functionalization of Depreciation Costs

Distribution Customer Ancilary StreetSCC Description Depreciation Generation Transmission Subtransmission Plant Service Services Diesel LightingCommon Generation Costs 995,476 995,476 Demand Side Management 36,190,875 36,190,875 Hydraulic Generation 108,544,098 108,544,098 Thermal Generation 14,613,836 14,613,836 Purchased Power - - Generation Outlet Transmission 302,388 302,388 Generating Switching Stations 898,856 898,856 Convertor Stations 31,977,651 31,977,651 HVDC Lines 2,777,412 2,777,412 Generation Facilities & Costs 196,300,593 196,300,593

Common Trans Costs - - Switching Stations 4,056,905 3,968,877 - - - 88,028 Transmission Substations 21,474,096 - 19,669,597 - - - 1,804,499 Dedicated Taps 44,765 44,765 Non Tariffable Transmission 1,028,827 1,028,827 US Interface 992,544 992,544 Networked AC Transmission Lines 8,765,994 8,765,994 Transmission Facilities/Costs 36,363,131 34,470,605 - - - 1,892,527

Common Subtrans / Dist Costs - - -

Common Subtransmission - - Subtransmission Substations 8,106,954 8,106,954 Subtransmission Lines 5,749,939 5,749,939 Subtrans. Facilities & Costs 13,856,893 13,856,893

Common Distribution Costs - - Distribution Substations 19,115,262 19,115,262 Distribution Pole & Wire 34,676,220 34,676,220 Transform/Volt. Regulation 9,951,619 9,951,619 Area & Roadway Lighting 2,702,623 2,702,623 Meters & Metering Transformers 5,795,602 5,795,602 Dist. Facilities & Costs 72,241,326 69,538,703 2,702,623

Market Research & Development - - Education & Safety - - Industrial & Commercial Solutions - - Power Quality Investigations - - Service Extensions - - Contact Center - Outages - - Rates & Regulatory 2,945,987 2,945,987 Line Locates - - Bldg Moves/Safety Watches - - Customer & Community Service Work - - Customer General Inquiries - - Wiring Inspections - - Customer Billing - - Customer Collections - - Meter Reading - - Customer Service Costs 2,945,987 2,945,987

Isolated Diesel Facilities 984,331 984,331

Communication & Control System 19,948,490 11,562,714 2,902,119 934,042 4,018,182 - 531,432 - -

Planned Grants In Lieu Taxes - - - - -

Buildings and General Equipment 47,828,048 23,126,432 5,887,754 1,812,029 7,571,451 8,520,537 - 299,383 610,462

390,468,798 230,989,738 43,260,477 16,602,964 81,128,336 11,466,524 2,423,959 1,283,714 3,313,085



SECTION 4: ALLOCATION OF COSTS


Section 4 Schedule 4.1 Classified Costs by Allocation Table


Prospective Cost Of Service StudyMarch 31, 2018

Classified Costs by Allocation Table

System Load Factor: 62.0%

AllocationTable Function Interest Depreciation Operating Common Costs Total

E12 Generation Energy Share 233,073 120,811 317,033 90,818 761,734 D14 Generation Demand Share 142,851 74,045 98,288 42,665 357,849

Common Costs 25,503 35,574 72,406 (133,483) - Total Generation 401,426 230,430 487,727 - 1,119,583

E13 Transmission Energy Share 2,217 615 3,995 2,603 9,431 D13 Transmission Demand Share 83,323 35,703 32,630 57,817 209,474

Common Costs 6,455 9,301 44,664 (60,420) - Total Transmission 91,996 45,619 81,290 - 218,905

D21 Subtrans 29,533 13,857 18,448 10,219 72,057 Common Costs 2,044 2,746 5,429 (10,219) - Total Subtransmission 31,577 16,603 23,878 - 72,057

D32 Dist. Plant Stations 38,927 19,115 26,457 14,723 99,222 D36 Dist. Plant Lines 72,685 34,244 40,359 25,663 172,951 D40 Dist. Plant S/E 16,528 9,952 5,764 5,618 37,862 C27 Dist. Plant Services 918 432 510 324 2,184 C40 Dist. Plant Meters 2,834 5,796 41 1,511 10,181

Common Costs 8,660 11,590 27,589 (47,839) - Total Distribution Plant 140,552 81,128 100,719 - 322,400

C11 Dist Serv Cust Acct - Billings - - 21,729 5,899 27,628 C12 Dist Serv Cust Acct - Collections - - 11,730 3,185 14,915 C14 Dist Serv Inspection - - 3,459 939 4,398 C15 Dist Serv Meter Read - - 10,396 2,823 13,218 C10 Dist Serv General - 2,946 13,894 4,572 21,412 C13 Dist Serv General - Smaller Customers - - 21,228 5,763 26,991 C23 Dist Serv Industrial & Commercial - - 4,313 1,171 5,484

Common Costs 6,855 8,521 8,977 (24,352) - Total Distribution Services 6,855 11,467 95,725 - 114,047

Total Allocated Costs 672,406 385,247 789,339 - 1,846,992

E01 Generation Diesel 180 978 6,623 818 8,599 C01 Distribution Diesel 52 6 300 38 396

Common Costs 241 299 315 (856) -

C01 Distribution Lighting 4,655 2,703 6,215 1,745 15,317 Common Costs 491 610 643 (1,745) -

D04 Transmission Taps - GSL >100kV 162 45 - 207

E01 Generation Export - 449 37,710 38,159 D04 Transmission Export -

E01 Generation SEP - GSM 192 100 231 523 D04 Transmission SEP - GSM 44 19 19 81 E01 Generation SEP - GSL 0-30kV 21 11 25 57 D04 Transmission SEP - GSL 0-30kV 5 2 2 9

Total Directs 6,042 5,222 52,085 - 63,349

Total 678,448 390,469 841,424 - 1,910,341

Energy 235,683 122,964 365,618 94,239 818,504

Demand 384,058 186,981 221,968 156,705 949,712

Customer 8,458 11,883 93,814 27,970 142,125

628,199 321,828 681,400 278,914 1,910,341


Section 4 Schedule 4.2 Allocation Tables


Table Type Costs Allocated Method

E12 Unweighted

Energy

Energy related costs within

the Generation function.

Annual kWh sales as measured at generation.

Distribution and transmission losses are assigned to each

rate class based upon the voltage level in which they

receive service.

E13 Unweighted

Energy

Energy related costs within

the Transmission function.

D13 Winter

Coincident

Peak Demand

Demand related costs within

the Transmission function.

Coincident peak demand of each class including losses

during the top 50 winter coincident peak hours. Utilizes

load research data for past eight years.

D14 Winter

Coincident

Peak Demand

Demand related costs within

the Generation function

D21

Winter

Coincident

Peak Demand

Costs within Subtransmission

function.

Coincident peak demand of each class including losses

during the top 50 winter coincident peak hours. Utilizes

load research data for past eight years.

Customers served at >100kV are excluded

D32 Class Non‐

Coincident

Peak Demand

Cost of Distribution stations

and station transformers

within the Distribution Plant

Function.

Non‐Coincident peak demand of each class including

losses. Utilizes load research data for past eight years.

Customers served at >30kV are excluded.

D36 Class Non‐

Coincident

Peak Demand

Cost of Distribution lines and

infrastructure within the

Distribution Plant Function.



The demand of GSL 0‐30kV customers that do not use

Secondary Distribution is reduced 30%.

Customers served at >30kV are excluded.

D40 Class Non‐

Coincident

Peak Demand

Cost of Distribution

transformation within the

Distribution Plant function.



GSL customers with customer owned transformation are

excluded.

C27 Weighted

Customer

Count –

Services

Cost of service drops within

the Distribution Plant

function

Customer count weighted by 5 for GSS:Three Phase,

GSM and GSL classes.

Customer count for Residential, GSS and GSM adjusted

to recognize that there are multiple customers served by

a single service.

Classes served at > 30 kV, Flat Rate Water Heating, Area

& Roadway Lighting excluded.

C40 Weighted

Customer

Count –

Meters

Costs of meters and

metering transformers

within the Distribution Plant

function

Customer count weighted by the relative cost of

metering equipment as shown in Schedule 4.7

Flat Rate Water Heating, A&RL excluded


Section 4 Schedule 4.3 Customer Service Allocation Table


Table Classes1 Customer Service Activity Description Operating ($ million)

Allocator Rationale for Allocator

C10 General Customer Service

All Education & Safety Public Affairs, District office costs‐public safety and education

1.2 Revenue

Line Locates/Moves/Safety Watches are for public safety and the protection of MH infrastructure Revenue allocator recognizes that costs could alternately be treated as A&G, which would result in a directionally similar allocation of costs to classes.

Call Center Outage calls 1.2

Rates & Regulatory Public Hearings, Cost of Service, Rate Design, and Load Research costs

3.0

Marketing R&D Costs related to marketing plans, customer surveys, and enhancing business development in the province

1.3

Line Locates Cost of locates for customers, MH work, public streets and roadways.

4.1

Building Moves & Safety Watches

Costs related to building and equipment moves, and oversight of work conducted near electric plant

3.1

C10 Total 13.9

C23 I&CS

GSL Industrial & Commercial Solutions

Activities of departments focused on GSL incl. consultation, service extension, billing‐related inquiries, power quality, general inquiries

4.3 Revenue Service provided to GSL customers A revenue allocator recognizes that the cost to provide these services to customers generally increases as the size of the customer increases

C13 Customer Service – Smaller Customers

Excludes GSL

Customer & Community Service Work

Disconnects/reconnects for customer driven work, opening Customer Service Termination Enclosures, pulling meter, other work requested by the customer

4.3 Revenue Services provided to smaller customers; GSL are provided similar services by I&CS and are excluded A revenue allocator recognizes that the cost to provide these services to customers generally increases as the size of the customer increases

General Inquiries District offices responding to general inquiries 2.0

Power Quality District offices responding to power quality issues

1.0

Service Extensions Pricing of service work, administration of customer service policy

13.9

C13 Total ($ million) 21.2

1 Customer services costs are forecast separately for the Diesel class. Diesel is therefore excluded from all allocators.


Section 4 Schedule 4.3 Customer Service Allocation Table


C11 Billings

Adjustments & Complex Billing

Activities associated with billing large and/or complex customers, master bills, applicable taxes, any detailed analysis associated with billing

2.2 Weighted Customer Count

All‐‐allocation based on estimate of time spent serving each class

Customer Accounts Administration of loans, customer moves, equal payment plan.

0.7 Allocation based on number of customer accounts excl. GSL (provided through I&CS), A&RL (provided in Complex Billing)

Field Billing District Office costs for payment receipt, cash balancing, moves, new customer accounts

7.2 Allocation based on number of customer accounts excluding GSL (billing inquiries handled by I&CS)

CIS Admin Support for staff using Banner, iNovah and MyBill.

1.2 All‐ allocation based on the number of customers (customer accounts for A&RL)

Administrative Postage, bill printing, Contact Centre billing related calls, and Banner maintenance

10.4

C11 Total 21.7

C12 Collections

Excl GSL, ARL

Collections Cost of customer collection activities and bad debt expense

11.7 Weighted Customer Count

Historical data of collection activity and bad debt categorizes between res and commercial. Commercial portion prorated between classes on customer count A&RL excluded‐‐ historically no collection issues. Infrequent GSL collection activities through I&CS.

C14 Inspections

Excludes A&RL

Inspections Inspection of customer‐owned plant 3.5 Weighted Customer Count

Historical data categorizes between residential and commercial. Costs then prorated based on customer count. A&RL facilities not customer‐owned and thus excluded

C15 Meter Reading

Excludes A&RL

Meter Reading Cost of meter reading activities 10.4 Weighted Customer Count

Weights reflect the relative frequency of meter reads. Excludes unmetered A&RL

Total Customer Service 86.7


Section 4 Schedule 4.4 Updated Billings Weighting Factors


2018

Unweighted

Customer

Adjustments

& Complex

Billing1 CIS Admin2Customer

Accounts2 Field Billing2

Admin

(Postage,

Contact

Center,

Banner)2

Residential ‐ Std & A/E 485,421 70.8% 83.7% 83.9% 83.8% 83.7%

Residential ‐ Seasonal 19,717 1.0% 3.4% 3.4% 3.4% 3.4%

Residential ‐ FRWH 3,104 0.5% 0.5% 0.5% 0.5%

GSS ND 53,751 5.3% 9.3% 9.3% 9.3% 9.3%

GSS Demand 12,867 1.3% 2.2% 2.2% 2.2% 2.2%

GSS Seasonal 909 0.0% 0.2% 0.2% 0.2% 0.2%

GSS FRWH 328 0.1% 0.1% 0.1% 0.1%

GSM 2,152 16.5% 0.4% 0.4% 0.4% 0.4%

GSL 0‐30 kV 325 3.8% 0.1% 0.1%

GSL 30‐100 kV 40 0.5% 0.0% 0.0%

GSL >100kV 16 0.2% 0.0% 0.0%

A&RL 1,221 0.6% 0.2% 0.2% 0.2%

579,851 100.0% 100.0% 100.0% 100.0% 100.0%

1 ‐ shares based on estimate of time serving each class

2 ‐ shares based on customer count, limited to classes served by department

Billing Electric EFT's Forecast $

18.8 9.8 5.8 4,063,974

2018 Forecast Operating ($)

2,221,560 1,155,211 687,203 7,235,191 10,429,341

2018

Unweighted

Customer

Adjustments

& Complex

Billing CIS Admin

Customer

Accounting Field Billing

Admin

(Postage,

Contact

Center,

Banner) Total Cost Unit Cost

Weighting

Factor

Residential ‐ Std & A/E 485,421 1,572,865 967,083 576,884 6,060,907 8,730,900 17,908,638 36.89 1.10

Residential ‐ Seasonal 19,717 21,237 39,281 23,432 246,184 354,635 684,769 34.73 1.00

Residential ‐ FRWH 3,104 ‐ 6,184 3,689 38,756 55,829 104,458 33.65 1.00

GSS ND 53,751 118,303 107,086 63,879 671,128 966,779 1,927,175 35.85 1.10

GSS Demand 12,867 28,320 25,634 15,291 160,656 231,429 461,330 35.85 1.10

GSS Seasonal 909 979 1,811 1,080 11,350 16,349 31,569 34.73 1.00

GSS FRWH 328 ‐ 653 390 4,095 5,899 11,038 33.65 1.00

GSM 2,152 366,557 4,287 2,557 26,870 38,706 438,978 203.99 6.10

GSL 0‐30 kV 325 85,276 647 ‐ ‐ 5,846 91,769 282.37 8.40

GSL 30‐100 kV 40 10,496 80 ‐ ‐ 719 11,295 282.37 8.40

GSL >100kV 16 4,198 32 ‐ ‐ 288 4,518 282.37 8.40

A&RL 1,221 13,329 2,433 ‐ 15,245 21,961 52,968 43.38 1.30

579,851 2,221,560 1,155,211 687,203 7,235,191 10,429,341 21,728,506


Section 4 Schedule 4.5 Updated Collections Weighting Factor


Accoun

ts in

Arre

ars

As at F

eb 2017

Share

Resid

entia

l > 90 da

ys18,522

92.5%

Gene

ral Servic

e > 60

days

1,492

7.5%

20,014

100.0%

Bad De

bt Expen

se $

2014/15

2015/16

Resid

entia

l2,899,744

4,079,678

Gene

ral Servic

e575,999

652,689

Total

3,475,743

4,732,367

Bad De

bt Expen

se $

2014/15

2015/16

Average

Resid

entia

l83%

86%

84.8%

Gene

ral Servic

e17%

14%

15.2%

Forecast Collection Co

sts

9,186,206

Forecast Bad

Deb

t Expen

se2,544,000

Resid

entia

lGe

neral Servic

eRe

siden

tial

Gene

ral Servic

e

Accoun

ts Collections

Collections

Bad

Deb

t

Expe

nse

Bad

Deb

t

Expe

nse

Total

Unit

Weight

8,501,394

684,812

2,157,770

386,230

Resid

entia

l485,421

8,169,560

2,073,546

10,243,106

21.1

1.4

Resid

entia

l Seasona

l19,717

331,834

84,224

416,058

21.1

1.4

Total R

esiden

tial

505,138

GSS N

D53,751

528,270

297,941

826,211

15.4

1.0

GSS D

eman

d12,867

126,458

71,322

197,780

15.4

1.0

GSS S

easona

l909

8,934

5,039

13,972

15.4

1.0

GSM in

cl SEP

2,152

21,150

11,929

33,079

15.4

1.0

Total G

eneral Se

rvice

69,679

Total

8,501,394

684,812

2,157,770

386,230

11,730,206


Section 4 Schedule 4.6 Updated Meter Reading Weighting Factor


Met

er R

eadi

ng W

eigh

ting

Fac

tor

2017

/18

Met

er R

eadi

ng F

requ

ency

2017

/18

Ann

ual M

eter

Rea

ding

s

Bi-

Bi-

Mon

thly

Mon

thly

Ann

ual

Self

Rea

dT

otal

Mon

thly

Mon

thly

Ann

ual

Self

Rea

dT

otal

Wei

ghtin

gR

ate

Cla

ss12

/yr

6/yr

1/yr

ever

y 3

yr12

61

1/3

Fact

or

Res

iden

tial

405,

363

80,0

5848

5,42

12,

432,

178

26,6

862,

458,

864

5R

esid

entia

l - S

easo

nal

19,7

1719

,717

19,7

1719

,717

1

GSS

Non

Dem

and1

53,0

1753

,017

318,

102

318,

102

6G

SS D

eman

d12

,867

12,8

6715

4,40

415

4,40

412

GSS

Sea

sona

l90

990

990

990

91

SEP

- GSM

2727

324

324

12SE

P - G

SL4

448

4812

GSM

2,12

52,

125

25,5

0025

,500

12

GSL

0 -

30 k

V32

132

13,

852

3,85

212

GSL

30

kV -

100

kV40

4048

048

012

GSL

> 1

00 k

V16

1619

219

212

15,4

0045

8,38

020

,626

80,0

5857

4,46

418

4,80

02,

750,

280

20,6

2626

,686

2,98

2,39

2

Not

e 1

- exc

lude

s 73

4 no

n-m

eter

ed a

ccou

nts


Section 4 Schedule 4.7 Updated Meter Investment Weighting Factor


Customer Class Weighted Average

Cost Weight

Residential

$34.6

1.1

GSS ND ‐ single phase

$31.9

1.0

GSS ND ‐ three phase

$453.3

14.2

GSS D ‐ single phase

$364.6

11.4

GSS D ‐ three phase

$3,365.4

105.5

GSM

$3,900.7

122.3

GSL 0‐30kV

$13,338.9

418.2

GSL 30‐100kV

$49,411.0

1,549.1

GSL >100kV

$106,010.1

3,323.7


Section 4 Schedule 4.8 Updated SCADA Allocator


SCADA Allocator

Station Name RTU

Count Gen Trans Subtrans Dist

Atwood Station ‐ 1079 4 0% 0% 0% 100%

Adelaide Station ‐ 1530 1 0% 0% 0% 100%

Amy Station ‐ 1506 1 0% 0% 0% 100%

Arlington Station ‐ 1504 1 0% 0% 0% 100%

Ashern Station ‐ 2338 1 0% 100% 0% 0%

Birchtree Station ‐ 2659 1 0% 100% 0% 0%

Birtle Station ‐ 2644 1 0% 100% 0% 0%

Bissett DSC ‐ 3829 1 0% 0% 0% 100%

Border Main Station ‐ 2822 1 0% 100% 0% 0%

Boyd Station ‐ 1510 1 0% 0% 0% 100%

Brandon Generation Station 1 100% 0% 0% 0%

Brandon Victoria Station ‐ 2060 1 0% 100% 0% 0%

Burrows Station ‐ 1527 1 0% 0% 0% 100%

Cambridge Station ‐ 1515 1 0% 0% 0% 100%

Carberry North Station ‐ 2149 1 0% 0% 0% 100%

Charles Station ‐ 1511 1 0% 0% 0% 100%

Chisago 500 Station (US) 1 0% 100% 0% 0%

Church Station ‐ 1525 1 0% 0% 0% 100%

Cliff Lake Main Station ‐ 2744 1 0% 100% 0% 0%

Cornwallis Station ‐ 2590 1 0% 100% 0% 0%

Court Station ‐ 1086 1 0% 0% 0% 100%

Crocus Plains Station ‐ 2735 1 0% 0% 0% 100%

Dawson Road Station ‐ 1008 1 0% 0% 0% 100%

Des Meurons Station ‐ 1009 1 0% 0% 0% 100%

Dorsey Station ‐ 1075 3 0% 100% 0% 0%

Edmonton Station ‐ 1521 1 0% 0% 0% 100%

Elm Creek Station ‐ 2738 1 0% 0% 0% 100%

Empress Station ‐ 1520 1 0% 0% 0% 100%

Fife Station ‐ 1524 1 0% 0% 0% 100%

Forbes 500 (US) 1 0% 100% 0% 0%

Fortier Station ‐ 2689 1 0% 100% 0% 0%

Glenboro Station ‐ 2634 1 0% 100% 0% 0%

Grand Rapids Generating Station 1 100% 0% 0% 0%

Grand Rapids Switching Station 1 0% 100% 0% 0%

Great Falls Generating Station 1 0% 100% 0% 0%

Harrow Station ‐ 1402 1 0% 100% 0% 0%

Henday Station ‐ 2730 1 100% 0% 0% 0%




Station Name RTU


Herblet Lake Station ‐ 2779 1 0% 100% 0% 0%

Highland Park Station ‐ 2740 1 0% 0% 0% 100%

Inco Station ‐ 2410 1 0% 100% 0% 0%

Jenpeg Station ‐ 198 2 100% 0% 0% 0%

Jessie Station ‐ 1522 1 0% 0% 0% 100%

Keewatin Station ‐ 1518 1 0% 0% 0% 100%

Keewatinohk Station ‐ 2766 1 100% 0% 0% 0%

Kelsey Generating Station 1 0% 100% 0% 0%

Kettle Generating Station 1 100% 0% 0% 0%

King Station ‐ 1501 1 0% 0% 0% 100%

Kirkfield Station ‐ 1407 1 0% 100% 0% 0%

Laverendrye Station ‐ 1435 1 0% 100% 0% 0%

Letellier Station ‐ 2074 1 0% 100% 0% 0%

Limestone Generating Station 2 100% 0% 0% 0%

Lindsay Station ‐ 1507 1 0% 0% 0% 100%

Logan Station ‐ 1523 1 0% 0% 0% 100%

Longspruce Generating Station 3 100% 0% 0% 0%

Madison Station ‐ 1043 1 0% 0% 0% 100%

Manigotagan Station ‐ 2611 1 0% 100% 0% 0%

Martin Station ‐ 1517 2 0% 0% 0% 100%

McArthur Falls Generating Station 1 0% 100% 0% 0%

McPhillips Station ‐ 1401 2 0% 100% 0% 0%

Mercy Street Main Station ‐ 2595 1 0% 100% 0% 0%

Minitonas Station ‐ 2466 1 0% 100% 0% 0%

Missi Falls Station ‐ 934 1 100% 0% 0% 0%

Mohawk Station ‐ 1046 2 0% 100% 0% 0%

Mystery Lake Road Station ‐ 2632 1 0% 100% 0% 0%

Neepawa Station ‐ 2165 1 0% 100% 0% 0%

Neepawa 230kV Station ‐ 2166 1 0% 100% 0% 0%

Notigi Station ‐ 2713 1 0% 0% 0% 100%

Overflowing River Main Station ‐ 2643 1 0% 100% 0% 0%

Parkdale Station ‐ 1409 1 0% 100% 0% 0%

Peace Gardens Station (US) 1 0% 100% 0% 0%

Pine Falls Station ‐ 2686 1 0% 100% 0% 0%

Plessis Station ‐ 1436 1 0% 100% 0% 0%

Point Du Bois Generating Station 1 100% 0% 0% 0%

Ponton Station ‐ 2699 1 0% 100% 0% 0%

Portage Sask Station ‐ 2002 1 0% 100% 0% 0%

Portage South Station ‐ 2751 1 0% 100% 0% 0%

Radisson Converter Station ‐ 4210 1 100% 0% 0% 0%

Rall's Island Station ‐ 2638 1 0% 100% 0% 0%




Station Name RTU


Raven Lake Station ‐ 2591 1 0% 100% 0% 0%

Reston South Station ‐ 2039 1 0% 100% 0% 0%

Richer Station ‐ 2756 1 0% 100% 0% 0%

Ridgeway Station ‐ 1076 2 0% 100% 0% 0%

Riel 230 kV Station 3 0% 100% 0% 0%

Roblin Main Station ‐ 2676 1 0% 100% 0% 0%

Rockwood Station ‐ 2231 1 0% 100% 0% 0%

Roseau County Station (US) 1 0% 100% 0% 0%

Ross Lake Main Station ‐ 2719 1 0% 100% 0% 0%

Rosser Station ‐ 1408 2 0% 100% 0% 0%

Rover Station ‐ 1503 1 0% 0% 0% 100%

Scotland Station ‐ 1505 1 0% 0% 100% 0%

Selkirk Generating Station 1 100% 0% 0% 0%

Seven Sisters Generating Station 2 100% 0% 0% 0%

Sherbrook Station ‐ 1514 1 0% 0% 100% 0%

Silver Station ‐ 2500 1 0% 0% 100% 0%

Slave Falls Generating Station 1 100% 0% 0% 0%

St. James Station ‐ 1026 2 0% 100% 0% 0%

St. Joseph Station ‐ 2827 1 100% 0% 0% 0%

St. Leon Station ‐ 2703 1 0% 100% 0% 0%

St. Matthews Station ‐ 1508 1 0% 0% 0% 100%

St. Vital Station ‐ 1406 2 0% 100% 0% 0%

Stafford Station ‐ 1528 1 0% 100% 0% 0%

Stanley Station ‐ 2737 1 0% 0% 100% 0%

Strathcona Station ‐ 1509 1 0% 0% 0% 100%

Taylor Station ‐ 1516 1 0% 0% 0% 100%

Transcona Station ‐ 1403 1 0% 100% 0% 0%

Transcona East Station ‐ 1098 1 0% 0% 100% 0%

Vermillion Main Station ‐ 2594 1 0% 100% 0% 0%

Virden West Station ‐ 2762 1 0% 100% 0% 0%

Whiteshell Station ‐ 2167 2 0% 100% 0% 0%

Wilkes Station ‐ 1085 1 0% 0% 0% 100%

Wuskwatim Generating Station 1 100% 0% 0% 0%

Wuskwatim Switching Station 1 0% 100% 0% 0%

York Station ‐ 1502 1 0% 0% 0% 100%

133 16% 52% 4% 29%



SECTION 5: DEVELOPMENT OF CLASS LOADS


Section 5 Development of Class Loads


Development of Class Loads

In Schedule 5.3, the energy sales at the meter are grossed up by distribution and transmission

losses from Schedule 5.1, to yield estimated energy generated to serve the various classes and

subclasses.

The class coincident peak load factors are used to derive class coincident peaks at the meter,

which are reduced by forecast DSM savings. Estimated distribution losses and transmission

losses are applied to provide the estimate of class coincident peak at generation. Finally, class

coincidence factors based on the Load Research information have been applied to derive class

Non‐coincident peaks. The calculation of class Coincident Peak and Non‐coincident Peak can

both be found in Schedule 5.3.

The Flat Rate Water Heating class coincident demand is estimated on the basis of 1 kW

customer peak for the Residential class and 3.3 kW for General Service Small class.

Street light energy consumption forecast is based on the inventory wattage multiplied by 4,200

hours of use per year, a figure based on Load Research results. The customer count is based on

May 2016 actual billing data plus forecast additions to the system of 1,202 lights to year end

2018.

Forecast export energy in PCOSS18 includes 9,166 GWh in sales, which equals 10,218 GWh at

Generation after adding back transmission losses of 1,052 GWh. This energy is used to calculate

variable hydraulic O&M costs and the pro‐rata share of water rentals attributed to exports

Computation and Assignment of Losses

In order to reflect differential losses by class, energy sales and demand must be measured at

generation as opposed to the meter when allocating energy and capacity costs. This is

accomplished by assigning distribution and transmission losses to each of the rate classes based

upon the voltage level in which they receive service.




Schedule 5.1 shows the computation of expected transmission and distribution losses on

Manitoba Hydro’s Integrated System. Common bus energy losses have been taken from the

2016 Electric Load Forecast and adjusted to reflect forecast DSM savings. Distribution energy

losses are simply the difference between sales at meter and energy at common bus.

Distribution losses at time of system peak are calculated in Schedule 5.2 based on the approach

used by Mr. M. W. Gustafson in his article, “Approximating the System Loss Equation”. The

adjustment factor of ‐13% for temperature reflects the reduction in the resistivity of conductors

between 0C and ‐30C, 0C being the average Winnipeg temperature and the ambient

temperature on the peak load day usually being around ‐30C.

Distribution energy losses are assigned first. Customers receiving service at greater than 30 kV

have been assigned losses based upon a uniform percentage of metered sales (1.5%).

Customers receiving service at supply voltage less than 30 kV share in the residual losses. A

differential percentage has been assigned depending upon whether service is taken at primary

or secondary voltage level. General Service Small ‐ Three Phase, General Service Medium and

General Service Large are assumed to receive service at a primary service level, while

Residential, Area and Roadway Lighting and General Service Small ‐ Single Phase are assumed

to receive service at the secondary level. Capacity losses on the Distribution system are

assigned in a similar manner.

The table below summarizes the assignment of the Distribution energy loss differential.

Residual Losses Assigned on a Differential Percentage Basis

Secondary

Primary – Utility‐owned transformation

Primary – Customer‐owned transformation

+1.6%

‐0.1%

‐1.0%

Transmission losses are shared equally by all rate classes based upon deliveries from common

bus, i.e., sales at the meter plus assigned distribution losses.




For the Surplus Energy Program customers losses are assigned consistent with the class’s

service voltage levels and transformation ownership.


Section 5 Schedule 5.1 Calculation of Losses


MANITOBA HYDROPROSPECTIVE COST OF SERVICE STUDY

March 31, 2018

CALCULATION OF LOSSES

MANITOBAENERGY (in MWh) HYDRO

Firm Energy at Generation (After DSM) 25,814,985,118

Common Bus Losses (After DSM) 2,193,374,957

Deliveries From Common Bus 23,621,610,160

Sales at Meter 22,616,347,309

Distribution Losses 1,005,262,852

MANITOBADEMAND (in MW) HYDRO

Firm Peak Capacity At Generation (After DSM) 4,444.2

Common Bus Losses (After DSM) 353.8

Deliveries From Common Bus 4,090.4

Demand at Meter 3,859.2

Distribution Losses 231.2


Section 5 Schedule 5.2 Determination of Coincident Peak Distribution Losses


MANITO BA HYDRO

2018 PRO SPECTIVE CO ST O F SERVICE STUDY

March 31, 2018

DETERMINATIO N O F CO INCIDENT PEAK DISTRIBUTIO N LO SSES

1) ENERGY SALES AND TOTAL LOSSES ON DISTRIBUTION SYSTEM

Energy @

Sales Losses Common Bus

RESIDENTIAL 7,586,095,624 516,097,624 8,102,193,247

G.S.S. SINGLE PHASE 1,367,289,679 93,019,517 1,460,309,197

G.S.S. THREE PHASE 2,401,792,062 122,568,368 2,524,360,430

* G.S.M. 3,227,436,082 164,702,674 3,392,138,756

* G.S.L. O - 30 1,747,861,584 73,466,202 1,821,327,786

G.S.L. 30 - 100 1,578,518,748 23,677,781 1,602,196,529

LIGHTING 82,414,669 5,606,839 88,021,508

MAN. HYDRO CONSTRUCTION 120,000,000 6,123,846 126,123,846

18,111,408,448 1,005,262,852 19,116,671,299

* (includes SEP sales)

2) COINCIDENT PEAK AT COMMON BUS

C.P. AT GENERATION 4,516.24

LESS SALES AT CB LEVEL :

- EXPORTS 0.00

- * G.S.L. >100 (548.96)

C.B. LOSSES (353.82)

EXPORT LOSSES 0.00

COINCIDENT PEAK AT COMMON BUS 3,613.47

3) LOAD FACTOR AT COMMON BUS 60.4%

(Hours per Year = 8,760)

4) EQUIVALENT HOURS LOSS FACTOR

EQF = (0.08 x 60.39%) + (0.92 x (60.39%)²)

= 0.383863

5) NO LOAD LOSS FACTOR AS A PERCENTAGE OF DISTRIBUTION ENERGY LOSSES 18.00%

a) 1,005,263 x 0.1800 = 180,947 MW.H

b) 1,005,263 x 0.1800 = 20.7 MW @ PEAK

8,760

6) CO-EFFICIENT OF SYSTEM LOSSES

= 1,005,263. - 180,947

8,760 x (3,613.47)² x 0.38386

= 0.000019

7) SYSTEM DISTRIBUTION LOSSES AT PEAK

= 20.66 + 0.000019 X (3,613.47)²

= 265.80

8) ADJUSTMENT FACTOR FOR TEMPERATURE -13.0%

9) SYSTEM DISTRIBUTION LOSSES AT PEAK ASSIGNED IN COSS 231.242 MW

10) RELATIONSHIP PEAK TO AVERAGE LOSSES (based on sales @ meter).

AVERAGE (KW.h) 1,005,263 / 18,111,408 = 5.55%

PEAK (MW) 231.24 / 3,382.224 = 6.84%


Section 5 Schedule 5.3 Prospective Peak Load Report – Using Top 50 Peak Hours


2018 Prospective Cost of Service StudyProspective Peak Load ReportUsing Top 50 Peak Hours Energy Data

Forecast Total KW.hForecast Total KW.h Forecast Sales KW.h Generated# Cust. Sales DSM KW.h After DSM Distribution Common Bus Adjusted

C90 Before DSM Savings E20 Losses Losses E12

Residential Residential 485,421 7,614,181,121 (127,969,536) 7,486,211,585 509,302,308 742,420,175 8,737,934,068 Seasonal 19,717 88,790,723 - 88,790,723 6,040,615 8,805,525 103,636,863 Water Heating 3,104 11,093,316 - 11,093,316 754,701 1,100,143 12,948,160

Total Residential 508,242 7,714,065,160 (127,969,536) 7,586,095,624 516,097,624 752,325,843 8,854,519,090

GS Small - Single Phase Non-Demand 41,470 956,390,990 (23,296,343) 933,094,647 63,480,340 92,536,563 1,089,111,550 Demand 4,197 435,182,203 (10,136,170) 425,046,033 28,916,752 42,152,529 496,115,314

Subtotal 45,667 1,391,573,193 (33,432,514) 1,358,140,679 92,397,092 134,689,092 1,585,226,864 Seasonal 909 5,460,000 - 5,460,000 371,455 541,477 6,372,932 Water Heating 328 3,689,000 - 3,689,000 250,970 365,844 4,305,815

Total Single Phase 46,904 1,400,722,193 (33,432,514) 1,367,289,679 93,019,517 135,596,414 1,595,905,611

GS Small - Three Phase Non-Demand 12,281 697,370,650 (16,986,971) 680,383,679 34,721,373 66,400,787 781,505,839 Demand 8,670 1,762,459,204 (41,050,822) 1,721,408,382 87,846,996 167,997,669 1,977,253,047

Total Three Phase 20,951 2,459,829,854 (58,037,792) 2,401,792,062 122,568,368 234,398,456 2,758,758,886

Total G.S.Small Non-Demand 53,751 1,653,761,640 (40,283,314) 1,613,478,326 98,201,713 158,937,350 1,870,617,389 Demand 12,867 2,197,641,407 (51,186,992) 2,146,454,415 116,763,748 210,150,198 2,473,368,360 Sub-Total G.S. Small 66,618 3,851,403,047 (91,470,306) 3,759,932,741 214,965,461 369,087,548 4,343,985,750 Seasonal 909 5,460,000 - 5,460,000 371,455 541,477 6,372,932 Water Heating 328 3,689,000 - 3,689,000 250,970 365,844 4,305,815 Total GS Small 67,855 3,860,552,047 (91,470,306) 3,769,081,741 215,587,886 369,994,870 4,354,664,497

General Service - Medium 2,125 3,284,168,472 (79,732,390) 3,204,436,082 163,528,937 312,731,015 3,680,696,034

General Service - Large0 - 30 Kv 321 1,810,414,755 (65,053,171) 1,745,361,584 73,361,122 168,876,754 1,987,599,460

30 - 100 kV 39 1,447,300,000 (64,627,251) 1,382,672,749 20,740,091 130,313,326 1,533,726,166 30 - 100 kV - Curtailment Cust's 1 205,000,000 (9,154,001) 195,845,999 2,937,690 18,457,978 217,241,667

Over 100 Kv 14 2,772,402,000 (16,798,788) 2,755,603,212 - 255,870,410 3,011,473,622 Over 100 Kv - Curtailment Cust's 2 1,760,000,000 (10,664,351) 1,749,335,649 - 162,433,847 1,911,769,496

Total G.S.- Large 377 7,995,116,755 (166,297,562) 7,828,819,193 97,038,904 735,952,314 8,661,810,411

SEPGSM 27 23,000,000 23,000,000 1,173,737 2,244,642 26,418,380 GSL 0 - 30 Kv 4 2,500,000 2,500,000 105,080 241,894 2,846,974 Total SEP 31 25,500,000 - 25,500,000 1,278,817 2,486,536 29,265,353

Street Lighting 131,695 89,414,746 (18,853,882) 70,560,864 4,800,400 6,997,639 82,358,903 Sentinel Lighting 26,287 11,853,805 - 11,853,805 806,439 1,175,562 13,835,805

Total - Lighting 157,982 101,268,551 (18,853,882) 82,414,669 5,606,839 8,173,201 96,194,709

Total - General Consumers 736,612 22,980,670,985 (484,323,676) 22,496,347,309 999,139,006 2,181,663,779 25,677,150,094

Extra Provincial - - - - - Man Hydro - Construction 120,000,000 120,000,000 6,123,846 11,711,178 137,835,024

Integrated System 736,612 23,100,670,985 (484,323,676) 22,616,347,309 1,005,262,852 2,193,374,957 25,814,985,118


Section 5 Schedule 5.3 Prospective Peak Load Report – Using Top 50 Peak Hours


2018 Prospective Cost of Service StudyProspective Peak Load ReportUsing Top 50 Peak Hours Demand Data

Class ClassCP @ Demand Demand

CP CP @ Meter Forecast CP @ Meter Distrib Common Bus Gen. Class NCP MW NCP MWLoad Before DSM DSM MW After DSM Losses Losses MW Coinc. @ Meter @ Gen.Factor MW Savings MW MW MW D13/D14 Factor D50 D20

Residential Residential 50.6% 1,718.3 (47.6) 1,670.7 136.8 156.3 1,963.9 90.0% 1,856.7 2,182.4 Seasonal 157.8% 6.4 6.4 0.5 0.6 7.6 8.0% 80.3 94.4 Water Heating 63.8% 2.0 2.0 0.2 0.2 2.3 80.0% 2.5 2.9

Total Residential 51.0% 1,726.7 (47.6) 1,679.1 137.5 157.1 1,973.7 86.6% 1,939.4 2,279.7

GS Small - Single Phase Non-Demand 62.4% 174.8 (5.7) 169.2 13.9 15.8 198.8 86.8% 194.9 229.1 Demand 66.4% 74.8 (2.4) 72.4 5.9 6.8 85.1 90.4% 80.1 94.2

Subtotal 63.6% 249.7 (8.1) 241.6 19.8 22.6 284.0 87.8% 275.1 323.3 Seasonal 162.5% 0.4 0.4 0.0 0.0 0.5 8.0% 4.8 5.6 Water Heating 69.1% 0.6 0.6 0.0 0.1 0.7 75.0% 0.8 1.0

Total Single Phase 63.8% 250.7 (8.1) 242.6 19.9 22.7 285.1 86.4% 280.7 329.9

GS Small - Three Phase Non-Demand 62.4% 127.5 (4.1) 123.4 7.5 11.3 142.2 86.8% 142.1 163.8 Demand 66.4% 303.1 (9.9) 293.3 17.9 26.9 338.1 90.4% 324.5 374.1

Total Three Phase 65.2% 430.6 (14.0) 416.6 25.4 38.2 480.3 89.3% 466.6 537.9

Total G.S.Small Non-Demand 60.9% 302.3 (9.8) 292.5 21.4 27.2 341.0 86.8% 337.1 393.0 Demand 64.8% 378.0 (12.3) 365.7 23.8 33.7 423.2 90.4% 404.6 468.3 Sub-Total G.S. Small 64.6% 680.3 (22.1) 658.2 45.2 60.8 764.2 88.7% 741.7 861.2 Seasonal 162.3% 0.4 - 0.4 0.0 0.0 0.5 8.0% 4.8 5.6 Water Heating 69.1% 0.6 - 0.6 0.0 0.1 0.7 75.0% 0.8 1.0 Total GS Small 64.7% 681.3 (22.1) 659.2 45.2 60.9 765.4 88.2% 747.3 867.8

General Service - Medium 73.0% 513.8 (15.2) 498.6 30.4 45.8 574.7 91.3% 546.0 629.3

General Service - Large0 - 30 Kv 80.3% 257.5 (16.6) 240.9 12.0 21.9 274.8 89.9% 268.1 305.8

30 - 100 kV 91.3% 180.9 (8.7) 172.3 3.2 15.2 190.6 76.9% 224.0 247.9 30 - 100 kV - Curtailment Cust's 96.1% 24.4 (1.2) 23.2 0.4 2.0 † 25.7 95.6% 24.3 26.9

Over 100 Kv 91.0% 347.8 (3.5) 344.2 - 29.8 374.0 85.8% 401.3 436.0 Over 100 Kv - Curtailment Cust's 97.1% 206.8 (2.1) 204.7 - 17.7 † 222.4 85.3% 240.1 260.9

Total G.S.- Large 89.7% 1,017.4 (32.0) 985.4 15.6 86.6 1,087.6 85.1% 1,157.8 1,277.5

SEPGSM 47.3% 5.5 5.5 0.3 0.5 6.4 84.0% 6.6 7.6 GSL 0 - 30 Kv 157.1% 0.2 0.2 0.0 0.0 0.2 10.9% 1.7 1.9 Total SEP 50.8% 5.7 - 5.7 0.3 0.5 6.6 69.3% 8.3 9.5

Street Lighting 76.2% 13.4 (2.8) 10.6 0.9 1.0 12.4 65.1% 16.3 19.1 Sentinel Lighting 76.2% 1.8 - 1.8 0.1 0.2 2.1 65.1% 2.7 3.2

Total - Lighting 76.2% 15.2 (2.8) 12.4 1.0 1.2 14.5 65.1% 19.0 22.3

Total - General Consumers 66.2% 3,960.2 (119.8) 3,840.4 230.1 352.1 4,422.6 86.9% 4,417.8 5,086.2

Extra Provincial 0.0% - - - 0.0Man Hydro - Construction 73.0% 18.8 18.8 1.1 1.7 21.6

Integrated System 66.3% 3,978.9 (119.8) 3,859.2 231.2 353.8 4,444.2

† Demand for curtailable customers is forecast as if customers are not curtailed at time of system peak.



SECTION 6: REVENUE


Section 6 Schedule 6.1 Adjusted Revenue Including DSM Reduction at Approved Rates


2018 PROSPECTIVE COST OF SERVICE STUDYADJUSTED REVENUE INCLUDING DSM REDUCTION @ APPROVED RATES

For Year Ended March 31, 2018

GeneralUnadjusted Transfer to Allowable Revenue To Operating To Export Other Consumer Total adjusted

Revenue Class Revenue BPIII Reserve after BPIII Reserve Expense Revenue Accrual Adjustment Revenue

ResidentialResidential 639,179,993 (46,089,792) 593,090,201 138,810 4,578,118 597,807,129 Seasonal 8,863,561 (639,131) 8,224,430 63,485 8,287,915 Water Heating 1,081,149 (77,959) 1,003,190 235 7,744 1,011,168

649,124,703 (46,806,882) 602,317,821 - - 139,045 4,649,347 607,106,212

General Service - Small

Non Demand 148,861,976 (10,734,093) 138,127,883 32,328 263,979 138,424,190 Seasonal 685,949 (49,462) 636,487 1,216 637,703 Water Heating 448,802 (32,362) 416,440 97 796 417,333 Total Non Demand 149,996,727 (10,815,917) 139,180,810 - - 32,426 265,991 139,479,227

Demand 158,066,037 (11,397,777) 146,668,260 34,327 280,301 146,982,888 158,066,037 (11,397,777) 146,668,260 - - 34,327 280,301 146,982,888

SEPGSM 763,052 763,052 179 1,458 764,689 GSL 0-30kV 78,825 78,825 18 151 78,994

841,877 - 841,877 - - 197 1,609 843,683

General Service - Medium 206,195,123 (14,868,254) 191,326,869 44,779 365,649 191,737,297 206,195,123 (14,868,254) 191,326,869 - - 44,779 365,649 191,737,297

General Service - Large 0 - 30 kV 96,412,556 (6,952,087) 89,460,469 20,938 170,970 89,652,377 30 - 100 kV 66,767,573 (4,814,455) 61,953,118 61,953,118 30-100 kV Curtailable 8,667,271 (624,977) 8,042,294 8,042,294 > 100 kV 121,247,532 (8,742,879) 112,504,653 112,504,653 > 100 kV Curtailable 73,234,329 (5,280,758) 67,953,570 67,953,570

366,329,261 (26,415,157) 339,914,104 - - 20,938 170,970 340,106,012

Area & Roadway LightingStreet Lighting 19,818,490 (1,429,066) 18,389,424 18,389,424 Sentinel Lighting 3,421,568 (246,721) 3,174,847 743 6,068 3,181,657

23,240,058 (1,675,787) 21,564,271 - - 743 6,068 21,571,082

Diesel Residential 748,964 (54,006) 694,958 694,958 Full Cost 7,192,116 (518,607) 6,673,509 6,673,509

7,941,080 (572,613) 7,368,467 - - - - 7,368,467

General Consumers 1,561,734,866 (112,552,387) 1,449,182,479 - - 272,455 5,739,934 1,455,194,869

Accrual - Other 293,628 (21,173) 272,455 (272,455) - Miscellaneous - Non-Energy 879,000 (63,383) 815,617 (815,617) - Late Pmt & Cust Adj - Residential 5,010,654 (361,307) 4,649,347 (4,649,347) - Late Pmt & Cust Adj - Other 1,175,338 (84,751) 1,090,588 (1,090,588) - Total General Consumers 1,569,093,486 (113,083,000) 1,456,010,486 - (815,617) - - 1,455,194,869

BP III Reserve (113,083,000) - Extra-Provincial 454,201,375 454,201,375 944,617 455,145,992 Other (Non Energy) 30,312,945 30,312,945 (30,183,945) (129,000) - Total Revenue 1,940,524,806 (113,083,000) 1,827,441,806 (30,183,945) - - - 1,910,340,861



SECTION 7: HISTORICAL RCC RATIOS


Section 7 Schedule 7.1 Historical RCC Ratios


PCOSS18

PCOSS14

164/16

PCOSS14‐

Amen

ded

PCOSS13

PCOSS11

PCOSS10

PCOSS08

116/08

PCOSS08

117/06

PCOSS06

117/06

PCOSS06

PCOSS04

PCOSS03

PCOSS02

PCOSS01

PCOSS99

PCOSS97

PCOSS95

Residential 94.8% 95.5% 99.9% 99.2% 95.9% 96.4% 96.2% 96.4% 94.1% 97.0% 90.6% 92.4% 96.5% 90.7% 92.1% 91.4% 90.2%

GSS ND 112.5% 108.5% 108.0% 107.6% 104.8% 105.7% 101.4% 104.3% 107.4% 107.4% 104.9% 107.3% 109.4% 104.4% 106.9% 107.3% 107.8%

GSS D 101.0% 103.4% 104.5% 103.7% 103.8% 102.8% 107.8% 107.2% 106.9% 105.4% 109.7% 108.4% 104.7% 105.4% 107.7% 104.5% 105.3%

GSM 98.3% 100.3% 99.3% 100.0% 101.1% 101.3% 100.2% 101.1% 101.4% 100.6% 104.8% 102.9% 104.4% 109.4% 105.5% 102.4% 106.1%

GSL 0–30kV 99.1% 96.1% 91.1% 93.3% 91.9% 92.3% 89.9% 90.4% 91.3% 90.1% 99.9% 93.4% 96.8% 102.6% 101.4% 100.9% 105.2%

GSL 30‐100kV 109.3% 108.0% 99.8% 96.6% 104.2% 106.8% 108.4% 103.7% 104.7% 101.5% 109.5% 108.8% 109.4% 118.8% 110.3% 108.1% 111.8%

GSL >100kV 108.6% 107.1% 98.5% 100.5% 112.6% 109.2% 112.0% 108.7% 110.0% 103.2% 114.2% 113.5% 99.8% 115.9% 109.5% 111.0% 110.9%

A&RL 100.3% 99.5% 100.3% 101.8% 105.2% 100.0% 102.4% 105.8% 107.7% 107.1% 108.9% 109.9% 101.9% 92.0% 93.4% 108.8% 119.6%


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