EDB Information Disclosure Requirements Information

Commerce Commission Information Disclosure Template

Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 1 CoverSheet

EDB Information Disclosure RequirementsInformation Templates

forSchedules 1–10

Company Name Scanpower Limited

Disclosure Date 31 August 2021

Disclosure Year (year ended) 31 March 2021

Templates for Schedules 1–10 excluding 5f–5gTemplate Version 4.1. Prepared 21 December 2017


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx2 TOC

Table of Contents

Schedule Schedule name1 ANALYTICAL RATIOS2 REPORT ON RETURN ON INVESTMENT3 REPORT ON REGULATORY PROFIT4 REPORT ON VALUE OF THE REGULATORY ASSET BASE (ROLLED FORWARD)5a REPORT ON REGULATORY TAX ALLOWANCE5b REPORT ON RELATED PARTY TRANSACTIONS5c REPORT ON TERM CREDIT SPREAD DIFFERENTIAL ALLOWANCE5d REPORT ON COST ALLOCATIONS5e REPORT ON ASSET ALLOCATIONS6a REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR6b REPORT ON OPERATIONAL EXPENDITURE FOR THE DISCLOSURE YEAR7 COMPARISON OF FORECASTS TO ACTUAL EXPENDITURE8 REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES9a ASSET REGISTER9b ASSET AGE PROFILE9c REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES9d REPORT ON EMBEDDED NETWORKS9e REPORT ON NETWORK DEMAND10 REPORT ON NETWORK RELIABILITY


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 3 Instructions

Disclosure Template InstructionsThese templates have been prepared for use by EDBs when making disclosures under clauses 2.3.1, 2.4.21, 2.4.22, 2.5.1, and 2.5.2 of the Electricity Distribution Information Disclosure Determination 2012.

Company Name and DatesTo prepare the templates for disclosure, the supplier's company name should be entered in cell C8, the date of the last day of the current (disclosure) year should be entered in cell C12, and the date on which the information is disclosed should be entered in cell C10 of the CoverSheet worksheet.

The cell C12 entry (current year) is used to calculate disclosure years in the column headings that show above some of the tables and in labels adjacent to some entry cells. It is also used to calculate the ‘For year ended’ date in the template title blocks (the title blocks are the light green shaded areas at the top of each template).The cell C8 entry (company name) is used in the template title blocks.Dates should be entered in day/month/year order (Example -"1 April 2013").

Data Entry Cells and Calculated CellsData entered into this workbook may be entered only into the data entry cells. Data entry cells are the bordered, unshaded areas (white cells) in each template. Under no circumstances should data be entered into the workbook outside a data entry cell.

In some cases, where the information for disclosure is able to be ascertained from disclosures elsewhere in the workbook, such information is disclosed in a calculated cell.

Validation Settings on Data Entry CellsTo maintain a consistency of format and to help guard against errors in data entry, some data entry cells test keyboard entries for validity and accept only a limited range of values. For example, entries may be limited to a list of category names, to values between 0% and 100%, or either a numeric entry or the text entry “N/A”. Where this occurs, a validation message will appear when data is being entered. These checks are applied to keyboard entries only and not, for example, to entries made using Excel’s copy and paste facility.

Conditional Formatting Settings on Data Entry CellsSchedule 2 cells G79 and I79:L79 will change colour if the total cashflows do not equal the corresponding values in table 2(ii).Schedule 4 cells P99:P105 and P107 will change colour if the RAB values do not equal the corresponding values in table 4(ii).Schedule 9b columns AA to AE (2013 to 2017) contain conditional formatting. The data entry cells for future years are hidden (are changed from white to yellow).Schedule 9b cells AG10 to AG60 will change colour if the total assets at year end for each asset class does not equal the corresponding values in column I in Schedule 9a.Schedule 9c cell G30 will change colour if G30 (overhead circuit length by terrain) does not equal G18 (overhead circuit length by operating voltage).

Inserting Additional Rows and ColumnsThe templates for schedules 4, 5b, 5c, 5d, 5e, 6a, 8, 9d, and 9e may require additional rows to be inserted in tables marked 'include additional rows if needed' or similar. Column A schedule references should not be entered in additional rows, and should be deleted from additional rows that are created by copying and pasting rows that have schedule references.

Additional rows in schedules 5c, 6a, and 9e must not be inserted directly above the first row or below the last row of a table. This is to ensure that entries made in the new row are included in the totals.

Schedules 5d and 5e may require new cost or asset category rows to be inserted in allocation change tables 5d(iii) and 5e(ii). Accordingly, cell protection has been removed from rows 77 and 78 of the respective templates to allow blocks of rows to be copied. The four steps to add new cost category rows to table 5d(iii) are: Select Excel rows 69:77, copy, select Excel row 78, insert copied cells. Similarly, for table 5e(ii): Select Excel rows 70:78, copy, select Excel row 79, then insert copied cells.The template for schedule 8 may require additional columns to be inserted between column P and U. To avoid interfering with the title block entries, these should be inserted to the left of column S. If inserting additional columns, the formulas for standard consumers total, non-standard consumers totals and total for all consumers will need to be copied into the cells of the added columns. The formulas can be found in the equivalent cells of the existing columns.


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 4 Instructions

Disclosures by Sub-NetworkIf the supplier has sub-networks, schedules 8, 9a, 9b, 9c, 9e, and 10 must be completed for the network and for each sub-network. A copy of the schedule worksheet(s) must be made for each sub-network and named accordingly.

Schedule ReferencesThe references labelled 'sch ref' in the leftmost column of each template are consistent with the row references in the Electricity Distribution ID Determination 2012 (as issued on 21 December 2017). They provide a common reference between the rows in the determination and the template.

Description of Calculation ReferencesCalculation cell formulas contain links to other cells within the same template or elsewhere in the workbook. Key cell references are described in a column to the right of each template. These descriptions are provided to assist data entry. Cell references refer to the row of the template and not the schedule reference.

Worksheet Completion SequenceCalculation cells may show an incorrect value until precedent cell entries have been completed. Data entry may be assisted by completing the schedules in the following order:

1. Coversheet2. Schedules 5a–5e3. Schedules 6a–6b4. Schedule 85. Schedule 36. Schedule 47. Schedule 28. Schedule 79. Schedules 9a–9e10. Schedule 10


Information Disclosures 31 March 2021 - Schedules-1-to-10 adjusted.xlsx 6 S1.Analytical Ratios

Company NameFor Year Ended

SCHEDULE 1: ANALYTICAL RATIOS

sch ref

7 1(i): Expenditure metrics

8

Expenditure per GWh energy

delivered to ICPs($/GWh)

Expenditure per average no. of

ICPs($/ICP)

Expenditure per MW maximum

coincident system demand($/MW)

Expenditure per km circuit length

($/km)

Expenditure per MVA of capacity from EDB-

owned distribution transformers

($/MVA)

9 Operational expenditure 49,038 560 228,644 3,611 49,99710 Network 21,554 246 100,494 1,587 21,97511 Non-network 27,485 314 128,150 2,024 28,0221213 Expenditure on assets 49,357 564 230,131 3,635 50,32214 Network 28,614 327 133,415 2,107 29,17315 Non-network 20,743 237 96,716 1,528 21,1491617 1(ii): Revenue metrics

18

Revenue per GWh energy delivered

to ICPs($/GWh)

Revenue per average no. of

ICPs($/ICP)

19 Total consumer line charge revenue 108,134 1,23520 Standard consumer line charge revenue 108,134 1,23521 Non-standard consumer line charge revenue – –2223 1(iii): Service intensity measures2425 Demand density 16 Maximum coincident system demand per km of circuit length (for supply) (kW/km)26 Volume density 74 Total energy delivered to ICPs per km of circuit length (for supply) (MWh/km)27 Connection point density 6 Average number of ICPs per km of circuit length (for supply) (ICPs/km)28 Energy intensity 11,419 Total energy delivered to ICPs per average number of ICPs (kWh/ICP)2930 1(iv): Composition of regulatory income31 ($000) % of revenue

32 Operational expenditure 3,750 40.96%33 Pass-through and recoverable costs excluding financial incentives and wash-ups 2,124 23.20%34 Total depreciation 1,915 20.92%35 Total revaluations 661 7.22%36 Regulatory tax allowance 452 4.94%37 Regulatory profit/(loss) including financial incentives and wash-ups 1,575 17.20%38 Total regulatory income 9,1543940 1(v): Reliability41

42 Interruption rate 19.07 Interruptions per 100 circuit km

This schedule calculates expenditure, revenue and service ratios from the information disclosed. The disclosed ratios may vary for reasons that are company specific and, as a result, must be interpreted with care. The Commerce Commission will publish a summary and analysis of information disclosed in accordance with the ID determination. This will include information disclosed in accordance with this and other schedules, and information disclosed under the other requirements of the determination. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.

Scanpower Limited31 March 2021


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 6 S2.Return on Investment

Company Name

For Year Ended

SCHEDULE 2: REPORT ON RETURN ON INVESTMENT

sch ref

7 2(i): Return on Investment CY-2 CY-1 Current Year CY

8 31 Mar 19 31 Mar 20 31 Mar 21

9 ROI – comparable to a post tax WACC % % %

10 Reflecting all revenue earned 7.85% 4.94% 3.35%

11 Excluding revenue earned from financial incentives 7.85% 4.94% 3.35%12 Excluding revenue earned from financial incentives and wash-ups 7.85% 4.94% 3.35%1314 Mid-point estimate of post tax WACC 4.75% 4.27% 3.72%

15 25th percentile estimate 4.07% 3.59% 3.04%16 75th percentile estimate 5.43% 4.95% 4.40%1718

19 ROI – comparable to a vanilla WACC 20 Reflecting all revenue earned 8.35% 5.36% 3.68%

21 Excluding revenue earned from financial incentives 8.35% 5.36% 3.68%22 Excluding revenue earned from financial incentives and wash-ups 8.35% 5.36% 3.68%2324 WACC rate used to set regulatory price path – – –2526 Mid-point estimate of vanilla WACC 5.26% 4.69% 4.05%

27 25th percentile estimate 4.58% 4.01% 3.37%28 75th percentile estimate 5.94% 5.37% 4.73%29

30 2(ii): Information Supporting the ROI ($000)

3132 Total opening RAB value 43,68633 plus Opening deferred tax (2,126)34 Opening RIV 41,5603536 Line charge revenue 8,269

3738 Expenses cash outflow 5,87439 add Assets commissioned 3,77440 less Asset disposals 9841 add Tax payments 57342 less Other regulated income 88543 Mid-year net cash outflows 9,2374445 Term credit spread differential allowance –

4647 Total closing RAB value 44,79848 less Adjustment resulting from asset allocation (1,310)49 less Lost and found assets adjustment –50 plus Closing deferred tax (2,005)51 Closing RIV 44,1035253 ROI – comparable to a vanilla WACC 3.68%

5455 Leverage (%) 42%56 Cost of debt assumption (%) 2.82%57 Corporate tax rate (%) 28%5859 ROI – comparable to a post tax WACC 3.35%

60

This schedule requires information on the Return on Investment (ROI) for the EDB relative to the Commerce Commission's estimates of post tax WACC and vanilla WACC. EDBs must calculate their ROI based on a monthly basis if required by clause 2.3.3 of the ID Determination or if they elect to. If an EDB makes this election, information supporting this calculation must be provided in 2(iii). EDBs must provide explanatory comment on their ROI in Schedule 14 (Mandatory Explanatory Notes).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.



Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 7 S2.Return on Investment

Company Name

For Year Ended

SCHEDULE 2: REPORT ON RETURN ON INVESTMENT

sch ref

This schedule requires information on the Return on Investment (ROI) for the EDB relative to the Commerce Commission's estimates of post tax WACC and vanilla WACC. EDBs must calculate their ROI based on a monthly basis if required by clause 2.3.3 of the ID Determination or if they elect to. If an EDB makes this election, information supporting this calculation must be provided in 2(iii). EDBs must provide explanatory comment on their ROI in Schedule 14 (Mandatory Explanatory Notes).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.


61 2(iii): Information Supporting the Monthly ROI6263 Opening RIV N/A

6465

66Line charge

revenueExpenses cash

outflowAssets

commissionedAsset

disposalsOther regulated

incomeMonthly net cash

outflows

67 April –68 May –69 June –70 July –71 August –72 September –73 October –74 November –75 December –76 January –77 February –78 March –79 Total – – – – – –8081 Tax payments N/A8283 Term credit spread differential allowance N/A8485 Closing RIV N/A

868788 Monthly ROI – comparable to a vanilla WACC N/A8990 Monthly ROI – comparable to a post tax WACC N/A

9192 2(iv): Year-End ROI Rates for Comparison Purposes9394 Year-end ROI – comparable to a vanilla WACC 3.62%9596 Year-end ROI – comparable to a post tax WACC 3.29%97

98 * these year-end ROI values are comparable to the ROI reported in pre 2012 disclosures by EDBs and do not represent the Commission's current view on ROI.99

100 2(v): Financial Incentives and Wash-Ups101

102 Net recoverable costs allowed under incremental rolling incentive scheme –103 Purchased assets – avoided transmission charge104 Energy efficiency and demand incentive allowance105 Quality incentive adjustment

106 Other financial incentives107 Financial incentives –108109 Impact of financial incentives on ROI –

110111 Input methodology claw-back112 CPP application recoverable costs113 Catastrophic event allowance

114 Capex wash-up adjustment115 Transmission asset wash-up adjustment

116 2013–15 NPV wash-up allowance

117 Reconsideration event allowance118 Other wash-ups119 Wash-up costs –120121 Impact of wash-up costs on ROI –


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 8 S3.Regulatory Profit


SCHEDULE 3: REPORT ON REGULATORY PROFIT

sch ref

7 3(i): Regulatory Profit ($000)

8 Income9 Line charge revenue 8,269

10 plus Gains / (losses) on asset disposals (70)11 plus Other regulated income (other than gains / (losses) on asset disposals) 9551213 Total regulatory income 9,154

14 Expenses15 less Operational expenditure 3,750

1617 less Pass-through and recoverable costs excluding financial incentives and wash-ups 2,1241819 Operating surplus / (deficit) 3,280

2021 less Total depreciation 1,9152223 plus Total revaluations 6612425 Regulatory profit / (loss) before tax 2,027

2627 less Term credit spread differential allowance –2829 less Regulatory tax allowance 4523031 Regulatory profit/(loss) including financial incentives and wash-ups 1,57532

33 3(ii): Pass-through and Recoverable Costs excluding Financial Incentives and Wash-Ups ($000)

34 Pass through costs35 Rates 4236 Commerce Act levies –37 Industry levies 2638 CPP specified pass through costs –39 Recoverable costs excluding financial incentives and wash-ups40 Electricity lines service charge payable to Transpower 1,83841 Transpower new investment contract charges 21842 System operator services –43 Distributed generation allowance –44 Extended reserves allowance –45 Other recoverable costs excluding financial incentives and wash-ups –46 Pass-through and recoverable costs excluding financial incentives and wash-ups 2,12447

This schedule requires information on the calculation of regulatory profit for the EDB for the disclosure year. All EDBs must complete all sections and provide explanatory comment on their regulatory profit in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.



Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 9 S3.Regulatory Profit


SCHEDULE 3: REPORT ON REGULATORY PROFIT

sch ref

This schedule requires information on the calculation of regulatory profit for the EDB for the disclosure year. All EDBs must complete all sections and provide explanatory comment on their regulatory profit in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.


48 3(iii): Incremental Rolling Incentive Scheme ($000)

49 CY-1 CY50 31 Mar 20 31 Mar 2151 Allowed controllable opex – –52 Actual controllable opex – –5354 Incremental change in year –55

56

Previous years' incremental

change

Previous years' incremental

change adjusted for inflation

57 CY-5 31 Mar 16 – –58 CY-4 31 Mar 17 – –59 CY-3 31 Mar 18 – –60 CY-2 31 Mar 19 – –61 CY-1 31 Mar 20 – –62 Net incremental rolling incentive scheme –6364 Net recoverable costs allowed under incremental rolling incentive scheme –

65 3(iv): Merger and Acquisition Expenditure70 ($000)66 Merger and acquisition expenditure –67

68

69 3(v): Other Disclosures70 ($000)71 Self-insurance allowance –

Provide commentary on the benefits of merger and acquisition expenditure to the electricity distribution business, including required disclosures in accordance with section 2.7, in Schedule 14 (Mandatory Explanatory Notes)

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10.

xlsx

10S4

.RAB

Val

ue (R

olle

d Fo

rwar

d)

Com

pany

Nam

eFo

r Yea

r End

ed

SCHE

DULE

4: R

EPO

RT O

N V

ALUE

OF

THE

REGU

LATO

RY A

SSET

BAS

E (R

OLL

ED F

ORW

ARD)

sch

ref

74(

i): R

egul

ator

y As

set B

ase

Valu

e (R

olle

d Fo

rwar

d)RA

BRA

BRA

BRA

BRA

B

8fo

r yea

r end

ed31

Mar

17

31 M

ar 1

831

Mar

19

31 M

ar 2

031

Mar

21

9($

000)

($00

0)($

000)

($00

0)($

000)

10To

tal o

peni

ng R

AB v

alue

36,

563

37,

815

40,

431

41,

069

43,

686

11 12le

ssTo

tal d

epre

ciatio

n 1

,409

1,4

76 1

,608

1,5

96 1

,915

13 14pl

usTo

tal r

eval

uatio

ns 7

91 4

16 5

95 1

,038

661

15 16pl

usAs

sets

com

miss

ione

d

1,8

70 3

,676

1,8

80 3

,258

3,7

7417 18

less

Asse

t disp

osal

s –

– 2

29 8

3 9

819 20

plus

Lost

and

foun

d as

sets

adj

ustm

ent

– –

– –

21 22pl

usAd

just

men

t res

ultin

g fr

om a

sset

allo

catio

n –

– –

(1,3

10)

23 24To

tal c

losin

g RA

B va

lue

37,

815

40,

431

41,

069

43,

686

44,

798

25 264(

ii): U

nallo

cate

d Re

gula

tory

Ass

et B

ase

27 28($

000)

($00

0)($

000)

($00

0)29

Tota

l ope

ning

RAB

val

ue 4

3,68

6 4

3,68

630

less

31To

tal d

epre

ciatio

n 1

,915

1,9

1532

plus

33To

tal r

eval

uatio

ns 6

61 6

6134

plus

35As

sets

com

miss

ione

d (o

ther

than

bel

ow)

3,7

74 3

,774

36As

sets

acq

uire

d fro

m a

regu

late

d su

pplie

r –

–37

Asse

ts a

cqui

red

from

a re

late

d pa

rty –

–38

Asse

ts co

mm

issio

ned

3

,774

3,7

7439

less

40

Asse

t disp

osal

s (ot

her t

han

belo

w)

98

98

41As

set d

ispos

als t

o a

regu

late

d su

pplie

r –

–42

Asse

t disp

osal

s to

a re

late

d pa

rty –

–43

Asse

t disp

osal

s 9

8 9

844 45

plus

Lost

and

foun

d as

sets

adj

ustm

ent

– –

46 47pl

usAd

just

men

t res

ultin

g fr

om a

sset

allo

catio

n(1

,310

)48 49

Tota

l clo

sing

RAB

valu

e 4

6,10

8 4

4,79

8

50

Scan

pow

er Li

mite

d31

Mar

ch 2

021

This

sche

dule

requ

ires i

nfor

mat

ion

on th

e ca

lcula

tion

of th

e Re

gula

tory

Ass

et B

ase

(RAB

) val

ue to

the

end

of th

is di

sclo

sure

yea

r. Th

is in

form

s the

RO

I cal

cula

tion

in S

ched

ule

2.

EDBs

mus

t pro

vide

exp

lana

tory

com

men

t on

the

valu

e of

thei

r RAB

in S

ched

ule

14 (M

anda

tory

Exp

lana

tory

Not

es).

This

info

rmat

ion

is pa

rt of

aud

ited

disc

losu

re in

form

atio

n (a

s def

ined

in se

ctio

n 1.

4 of

the

ID d

eter

min

atio

n), a

nd so

is su

bjec

t to

the

assu

ranc

e re

port

requ

ired

by

sect

ion

2.8. *

The

'una

lloca

ted

RAB'

is th

e to

tal v

alue

of t

hose

ass

ets u

sed

who

lly o

r par

tially

to p

rovid

e el

ectri

city d

istrib

utio

n se

rvice

s with

out a

ny a

llow

ance

bei

ng m

ade

for t

he a

lloca

tion

of co

sts t

o se

rvice

s pro

vided

by t

he su

pplie

r tha

t are

not

ele

ctric

ity d

istrib

utio

n se

rvice

s. T

he R

AB

valu

e re

pres

ents

the

valu

e of

thes

e as

sets

afte

r app

lying

this

cost

allo

catio

n. N

eith

er va

lue

inclu

des w

orks

und

er co

nstru

ctio

n.

Una

lloca

ted

RAB

*RA

B

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10.

xlsx

11S4

.RAB

Val

ue (R

olle

d Fo

rwar

d)

Com

pany

Nam

eFo

r Yea

r End

ed

SCHE

DULE

4: R

EPO

RT O

N V

ALUE

OF

THE

REGU

LATO

RY A

SSET

BAS

E (R

OLL

ED F

ORW

ARD)

sch

ref

Scan

pow

er Li

mite

d31

Mar

ch 2

021

This

sche

dule

requ

ires i

nfor

mat

ion

on th

e ca

lcula

tion

of th

e Re

gula

tory

Ass

et B

ase

(RAB

) val

ue to

the

end

of th

is di

sclo

sure

yea

r. Th

is in

form

s the

RO

I cal

cula

tion

in S

ched

ule

2.

EDBs

mus

t pro

vide

exp

lana

tory

com

men

t on

the

valu

e of

thei

r RAB

in S

ched

ule

14 (M

anda

tory

Exp

lana

tory

Not

es).

This

info

rmat

ion

is pa

rt of

aud

ited

disc

losu

re in

form

atio

n (a

s def

ined

in se

ctio

n 1.

4 of

the

ID d

eter

min

atio

n), a

nd so

is su

bjec

t to

the

assu

ranc

e re

port

requ

ired

by

sect

ion

2.8.

51 524(

iii):

Calc

ulat

ion

of R

eval

uatio

n Ra

te a

nd R

eval

uatio

n of

Ass

ets

53 54CP

I 4 1

,068

55CP

I 4-4

1,0

52

56Re

valu

atio

n ra

te (%

) 1

.52%

57 58 59($

000)

($00

0)($

000)

($00

0)

60To

tal o

peni

ng R

AB v

alue

43,

686

43,

686

61le

ssO

peni

ng v

alue

of f

ully

dep

recia

ted,

disp

osed

and

lost

ass

ets

210

210

62 63To

tal o

peni

ng R

AB v

alue

subj

ect t

o re

valu

atio

n 4

3,47

5 4

3,47

664

Tota

l rev

alua

tions

661

661

65 664(

iv):

Roll

Forw

ard

of W

orks

Und

er C

onst

ruct

ion

67 68W

orks

und

er co

nstr

uctio

n—pr

eced

ing

disc

losu

re y

ear

– –

69pl

usCa

pita

l exp

endi

ture

3,7

74 3

,774

70le

ssAs

sets

com

miss

ione

d 3

,774

3,7

7471

plus

Adju

stm

ent r

esul

ting

from

ass

et a

lloca

tion

–72

Wor

ks u

nder

cons

truc

tion

- cur

rent

disc

losu

re y

ear

– 0

73 74Hi

ghes

t rat

e of

capi

talis

ed fi

nanc

e ap

plie

d –

75

Allo

cate

d w

orks

und

er co

nstr

uctio

n

Una

lloca

ted

RAB

*

Una

lloca

ted

wor

ks u

nder

cons

truc

tion

RAB

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10.

xlsx

12S4

.RAB

Val

ue (R

olle

d Fo

rwar

d)

Com

pany

Nam

eFo

r Yea

r End

ed

SCHE

DULE

4: R

EPO

RT O

N V

ALUE

OF

THE

REGU

LATO

RY A

SSET

BAS

E (R

OLL

ED F

ORW

ARD)

sch

ref

Scan

pow

er Li

mite

d31

Mar

ch 2

021

This

sche

dule

requ

ires i

nfor

mat

ion

on th

e ca

lcula

tion

of th

e Re

gula

tory

Ass

et B

ase

(RAB

) val

ue to

the

end

of th

is di

sclo

sure

yea

r. Th

is in

form

s the

RO

I cal

cula

tion

in S

ched

ule

2.

EDBs

mus

t pro

vide

exp

lana

tory

com

men

t on

the

valu

e of

thei

r RAB

in S

ched

ule

14 (M

anda

tory

Exp

lana

tory

Not

es).

This

info

rmat

ion

is pa

rt of

aud

ited

disc

losu

re in

form

atio

n (a

s def

ined

in se

ctio

n 1.

4 of

the

ID d

eter

min

atio

n), a

nd so

is su

bjec

t to

the

assu

ranc

e re

port

requ

ired

by

sect

ion

2.8.

764(

v): R

egul

ator

y D

epre

ciat

ion

77 78($

000)

($00

0)($

000)

($00

0)79

Depr

ecia

tion

- sta

ndar

d 1

,183

1,1

8380

Depr

ecia

tion

- no

stan

dard

life

asse

ts 7

32 7

3281

Depr

ecia

tion

- mod

ified

life

asse

ts82

Depr

ecia

tion

- alte

rnat

ive

depr

ecia

tion

in a

ccor

danc

e w

ith C

PP83

Tota

l dep

recia

tion

1,9

15 1

,915

84 854(

vi):

Dis

clos

ure

of C

hang

es to

Dep

reci

atio

n Pr

ofile

s

86As

set o

r ass

ets w

ith ch

ange

s to

depr

ecia

tion*

Reas

on fo

r non

-sta

ndar

d de

prec

iatio

n (te

xt e

ntry

)

Depr

ecia

tion

char

ge fo

r the

pe

riod

(RAB

)

Clos

ing

RAB

valu

e un

der '

non-

stan

dard

' de

prec

iatio

n

Clos

ing

RAB

valu

e un

der '

stan

dard

' de

prec

iatio

n 87 88 89 90 91 92 93 94 95

* in

clude

add

ition

al ro

ws i

f nee

ded

964(

vii):

Dis

clos

ure

by A

sset

Cat

egor

y97

($00

0 un

less

oth

erw

ise sp

ecifi

ed)

98Su

btra

nsm

issio

n lin

esSu

btra

nsm

issio

n ca

bles

Zone

subs

tatio

nsDi

strib

utio

n an

d LV

lin

esDi

strib

utio

n an

d LV

ca

bles

Dist

ribut

ion

subs

tatio

ns a

nd

tran

sfor

mer

sDi

strib

utio

n sw

itchg

ear

Oth

er n

etw

ork

asse

tsN

on-n

etw

ork

asse

tsTo

tal

99To

tal o

peni

ng R

AB v

alue

20,

355

5,1

18 7

,102

3,5

10 3

,853

3,7

47 4

3,68

610

0le

ssTo

tal d

epre

ciatio

n 5

75 2

01 2

63 1

44 1

59 5

72 1

,915

101

plus

Tota

l rev

alua

tions

309

78

108

51

59

57

661

102

plus

Asse

ts co

mm

issio

ned

1,2

54 3

5 2

58 1

90 4

51 1

,586

3,7

7410

3le

ssAs

set d

ispos

als

68

– 1

7 1

3 –

– 9

810

4pl

usLo

st a

nd fo

und

asse

ts a

djus

tmen

t –

105

plus

Adju

stm

ent r

esul

ting

from

ass

et a

lloca

tion

(1,3

10)

(1,3

10)

106

plus

Asse

t cat

egor

y tra

nsfe

rs –

107

Tota

l clo

sing

RAB

valu

e –

– –

21,

274

5,0

30 7

,187

3,5

95 4

,203

3,5

08 4

4,79

8

108

109

Asse

t Life

110

Wei

ghte

d av

erag

e re

mai

ning

ass

et lif

e 4

3.4

30.

8 3

4.5

29.

7 3

0.8

18.

3(y

ears

)11

1W

eigh

ted

aver

age

expe

cted

tota

l ass

et lif

e 5

8.5

46.

9 5

0.3

39.

8 3

9.3

19.

7(y

ears

)

Una

lloca

ted

RAB

*RA

B

($00

0 un

less

oth

erw

ise sp

ecifi

ed)


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 13 S5a.Regulatory Tax Allowance


SCHEDULE 5a: REPORT ON REGULATORY TAX ALLOWANCE

sch ref

7 5a(i): Regulatory Tax Allowance ($000)

8 Regulatory profit / (loss) before tax 2,0279

10 plus Income not included in regulatory profit / (loss) before tax but taxable – *11 Expenditure or loss in regulatory profit / (loss) before tax but not deductible – *12 Amortisation of initial differences in asset values 54613 Amortisation of revaluations 18814 7341516 less Total revaluations 66117 Income included in regulatory profit / (loss) before tax but not taxable – *18 Discretionary discounts and customer rebates –19 Expenditure or loss deductible but not in regulatory profit / (loss) before tax – *20 Notional deductible interest 48521 1,1472223 Regulatory taxable income 1,6142425 less Utilised tax losses – 26 Regulatory net taxable income 1,614 2728 Corporate tax rate (%) 28%29 Regulatory tax allowance 452

3031 * Workings to be provided in Schedule 14

32 5a(ii): Disclosure of Permanent Differences33 In Schedule 14, Box 5, provide descriptions and workings of items recorded in the asterisked categories in Schedule 5a(i).

34 5a(iii): Amortisation of Initial Difference in Asset Values ($000)

3536 Opening unamortised initial differences in asset values 14,74737 less Amortisation of initial differences in asset values 54638 plus Adjustment for unamortised initial differences in assets acquired –39 less Adjustment for unamortised initial differences in assets disposed –40 Closing unamortised initial differences in asset values 14,2014142 Opening weighted average remaining useful life of relevant assets (years) 2743

This schedule requires information on the calculation of the regulatory tax allowance. This information is used to calculate regulatory profit/loss in Schedule 3 (regulatory profit). EDBs must provide explanatory commentary on the information disclosed in this schedule, in Schedule 14 (Mandatory Explanatory Notes).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.



Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 14 S5a.Regulatory Tax Allowance


SCHEDULE 5a: REPORT ON REGULATORY TAX ALLOWANCE

sch ref

This schedule requires information on the calculation of the regulatory tax allowance. This information is used to calculate regulatory profit/loss in Schedule 3 (regulatory profit). EDBs must provide explanatory commentary on the information disclosed in this schedule, in Schedule 14 (Mandatory Explanatory Notes).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.


44 5a(iv): Amortisation of Revaluations ($000)

4546 Opening sum of RAB values without revaluations 38,96947

48 Adjusted depreciation 1,72749 Total depreciation 1,91550 Amortisation of revaluations 18851

52 5a(v): Reconciliation of Tax Losses ($000)

5354 Opening tax losses –55 plus Current period tax losses –56 less Utilised tax losses –57 Closing tax losses –

58 5a(vi): Calculation of Deferred Tax Balance ($000)

5960 Opening deferred tax (2,126)6162 plus Tax effect of adjusted depreciation 4846364 less Tax effect of tax depreciation 6116566 plus Tax effect of other temporary differences* 76768 less Tax effect of amortisation of initial differences in asset values 1536970 plus Deferred tax balance relating to assets acquired in the disclosure year –7172 less Deferred tax balance relating to assets disposed in the disclosure year (27)7374 plus Deferred tax cost allocation adjustment 3677576 Closing deferred tax (2,005)

77

78 5a(vii): Disclosure of Temporary Differences

7980

81 5a(viii): Regulatory Tax Asset Base Roll-Forward82 ($000)83 Opening sum of regulatory tax asset values 17,257

84 less Tax depreciation 2,18385 plus Regulatory tax asset value of assets commissioned 3,77486 less Regulatory tax asset value of asset disposals –87 plus Lost and found assets adjustment –88 plus Adjustment resulting from asset allocation –89 plus Other adjustments to the RAB tax value –90 Closing sum of regulatory tax asset values 18,848

In Schedule 14, Box 6, provide descriptions and workings of items recorded in the asterisked category in Schedule 5a(vi) (Tax effect of other temporary differences).


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 15 S5b.Related Party Transactions


SCHEDULE 5b: REPORT ON RELATED PARTY TRANSACTIONS

sch ref

7 5b(i): Summary—Related Party Transactions ($000) ($000)

8 Total regulatory income –9

10 Market value of asset disposals –1112 Service interruptions and emergencies –13 Vegetation management 64214 Routine and corrective maintenance and inspection –15 Asset replacement and renewal (opex) 17416 Network opex 816

17 Business support –18 System operations and network support –19 Operational expenditure 816

20 Consumer connection –21 System growth –22 Asset replacement and renewal (capex) –23 Asset relocations –24 Quality of supply –25 Legislative and regulatory –26 Other reliability, safety and environment –27 Expenditure on non-network assets –28 Expenditure on assets –

29 Cost of financing –30 Value of capital contributions –31 Value of vested assets –32 Capital Expenditure –33 Total expenditure 816

3435 Other related party transactions

36 5b(iii): Total Opex and Capex Related Party Transactions

37 Name of related party Nature of opex or capex service

provided

Total value of transactions

($000)38 Scanpower Contracting division 17439 Scanpower Treesmart Division 6424041424344454647484950515253 Total value of related party transactions 816

54 * include additional rows if needed55


Asset replacement and renewal (opex)Vegetation management[Select one][Select one][Select one][Select one]

This schedule provides information on the valuation of related party transactions, in accordance with clause 2.3.6 of the ID determination. This information is part of audited disclosure information (as defined in clause 1.4 of the ID determination), and so is subject to the assurance report required by clause 2.8.

[Select one][Select one][Select one]

[Select one]

[Select one][Select one][Select one][Select one][Select one]

Comm

erce Comm

ission Information Disclosure Tem

plate

Information Disclosures 31 M

arch 2021 - Schedules-1-to-10.xlsx16

S5c.TCSD Allowance

Company N

ame

For Year Ended

SCHEDULE 5c: REPORT O

N TERM

CREDIT SPREAD DIFFERENTIAL ALLO

WAN

CE

sch ref78

5c(i): Qualifying D

ebt (may be Com

mission only)

910Issuing party

Issue datePricing date

Original tenor (in

years)Coupon rate (%

)Book value at

issue date (NZD)

Book value at date of financial

statements (N

ZD)Term

Credit Spread Difference

Debt issue cost readjustm

ent 111213141516

* include additional rows if needed

– –

–1718

5c(ii): Attribution of Term Credit Spread D

ifferential1920

Gross term credit spread differential

–

2122Total book value of interest bearing debt

23Leverage

42%24

Average opening and closing RAB values25

Attribution Rate (%)

–2627

Term credit spread differential allow

ance –

Scanpower Lim

ited31 M

arch 2021

This schedule is only to be completed if, as at the date of the m

ost recently published financial statements, the w

eighted average original tenor of the debt portfolio (both qualifying debt and non-qualifying debt) is greater than five years.This inform

ation is part of audited disclosure information (as defined in section 1.4 of the ID determ

ination), and so is subject to the assurance report required by section 2.8.

Comm

erce Comm


plate



S5d.Cost Allocations

Company N

ame

For Year Ended

SCHEDULE 5d: REPORT O

N CO

ST ALLOCATIO

NS

sch ref

75d(i): O

perating Cost Allocations8

Value allocated ($000s)

9Arm

's length deduction

Electricity distribution

services

Non-electricity distribution

servicesTotal

OVABAA allocation increase ($000s)

10Service interruptions and em

ergencies11

Directly attributable 365

12Not directly attributable

–13

Total attributable to regulated service 365

14Vegetation m

anagement

15Directly attributable

64216

Not directly attributable –

17Total attributable to regulated service

642

18Routine and corrective m

aintenance and inspection19



–21

Total attributable to regulated service 228

22Asset replacem

ent and renewal


41224



412

26System

operations and network support


52128



52130

Business support31



1,386 538

1,92433

Total attributable to regulated service 1,581

3435O

perating costs directly attributable 2,364

36O

perating costs not directly attributable –

1,386 538

1,924 –

37O

perational expenditure 3,750

38

Scanpower Lim

ited31 M

arch 2021

This schedule provides information on the allocation of operational costs. EDBs m

ust provide explanatory comm

ent on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the im

pact of any reclassifications.This inform



Comm

erce Comm


plate



S5d.Cost Allocations

Company N

ame

For Year Ended

SCHEDULE 5d: REPORT O

N CO

ST ALLOCATIO

NS

sch ref

Scanpower Lim

ited31 M

arch 2021

This schedule provides information on the allocation of operational costs. EDBs m

ust provide explanatory comm

ent on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the im

pact of any reclassifications.This inform



395d(ii): O

ther Cost Allocations

40Pass through and recoverable costs

($000)

41 Pass through costs


6843



68

45 Recoverable costs


2,05647



2,0564950

5d(iii): Changes in Cost Allocations* †5152

Change in cost allocation 1CY-1

Current Year (CY)53

Cost categoryO

riginal allocation54

Original allocator or line item

sNew

allocation55

New allocator or line item

sDifference

– –

5657Rationale for change

58596061Change in cost allocation 2

CY-1Current Year (CY)

62Cost category

Original allocation

63O

riginal allocator or line items

New allocation

64New

allocator or line items

Difference –

–


676869($000)

70Change in cost allocation 3

CY-1Current Year (CY)

71Cost category

Original allocation

72O

riginal allocator or line items

New allocation

73New

allocator or line items

Difference –

–


76777879† include additional row

s if needed* a change in cost allocation m

ust be completed for each cost allocator change that has occurred in the disclosure year. A m

ovement in an allocator m

etric is not a change in allocator or component.

($000)

($000)


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 19 S5e.Asset Allocations


SCHEDULE 5e: REPORT ON ASSET ALLOCATIONS

sch ref

7 5e(i): Regulated Service Asset Values

8Value allocated

($000s)

9Electricity distribution

services

10 Subtransmission lines11 Directly attributable –12 Not directly attributable –13 Total attributable to regulated service –

14 Subtransmission cables15 Directly attributable –16 Not directly attributable –17 Total attributable to regulated service –

18 Zone substations19 Directly attributable –20 Not directly attributable –21 Total attributable to regulated service –

22 Distribution and LV lines23 Directly attributable 21,27424 Not directly attributable 25 Total attributable to regulated service 21,274

26 Distribution and LV cables27 Directly attributable 5,03028 Not directly attributable 29 Total attributable to regulated service 5,030

30 Distribution substations and transformers31 Directly attributable 7,18732 Not directly attributable 33 Total attributable to regulated service 7,187

34 Distribution switchgear35 Directly attributable 3,59536 Not directly attributable 37 Total attributable to regulated service 3,595

38 Other network assets39 Directly attributable 4,20340 Not directly attributable 41 Total attributable to regulated service 4,203

42 Non-network assets43 Directly attributable 3,50844 Not directly attributable 45 Total attributable to regulated service 3,5084647 Regulated service asset value directly attributable 44,79848 Regulated service asset value not directly attributable –49 Total closing RAB value 44,798

50

51 5e(ii): Changes in Asset Allocations* †52 ($000)53 Change in asset value allocation 1 CY-1 Current Year (CY)54 Asset category Non-network assets Original allocation – 1,32055 Original allocator or line items Floor space occupied New allocation – –56 New allocator or line items Floor space occupied Difference – 1,3205758 Rationale for change

596061 ($000)62 Change in asset value allocation 2 CY-1 Current Year (CY)63 Asset category Original allocation64 Original allocator or line items New allocation65 New allocator or line items Difference – –6667 Rationale for change686970 ($000)71 Change in asset value allocation 3 CY-1 Current Year (CY)72 Asset category Original allocation73 Original allocator or line items New allocation74 New allocator or line items Difference – –7576 Rationale for change77787980 † include additional rows if needed


* a change in asset allocation must be completed for each allocator or component change that has occurred in the disclosure year. A movement in an allocator metric is not a change in allocator or component.

This schedule requires information on the allocation of asset values. This information supports the calculation of the RAB value in Schedule 4.EDBs must provide explanatory comment on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the impact of any changes in asset allocations. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.

The Scanpower network and one of Scanpower's tenants swapped offices during the year. The "new" network office is included in the 31 March 2021 RAB as a commissioned asset and the "old" network office was reclassified as a non-network asset not directly attributable to the electricity distribution service. The reclassified building was included in the RAB as $1.322m on 31 March 2020 and was reclassified at a value of $1.31m on 31 March 2021.


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 20 S6a.Actual Expenditure Capex


SCHEDULE 6a: REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR

sch ref

7 6a(i): Expenditure on Assets ($000) ($000)

8 Consumer connection 1239 System growth 123

10 Asset replacement and renewal 1,82711 Asset relocations –12 Reliability, safety and environment:13 Quality of supply 6714 Legislative and regulatory –15 Other reliability, safety and environment 4816 Total reliability, safety and environment 11517 Expenditure on network assets 2,188

18 Expenditure on non-network assets 1,5861920 Expenditure on assets 3,774

21 plus Cost of financing –22 less Value of capital contributions –23 plus Value of vested assets (0)2425 Capital expenditure 3,774

26 6a(ii): Subcomponents of Expenditure on Assets (where known) ($000)

27 Energy efficiency and demand side management, reduction of energy losses –28 Overhead to underground conversion –29 Research and development –

30 6a(iii): Consumer Connection31 Consumer types defined by EDB* ($000) ($000)32 Customer initiated work 12333 –34 –35 –36 –37 * include additional rows if needed38 Consumer connection expenditure 1233940 less Capital contributions funding consumer connection expenditure –41 Consumer connection less capital contributions 123

42 6a(iv): System Growth and Asset Replacement and Renewal4344 ($000) ($000)45 Subtransmission – –46 Zone substations – –47 Distribution and LV lines – 1,32248 Distribution and LV cables – 2849 Distribution substations and transformers 123 17150 Distribution switchgear – 30651 Other network assets – –52 System growth and asset replacement and renewal expenditure 123 1,82753 less Capital contributions funding system growth and asset replacement and renewal54 System growth and asset replacement and renewal less capital contributions 123 1,827

55

56 6a(v): Asset Relocations57 Project or programme* ($000) ($000)58 –59 –60 –61 –62 –63 * include additional rows if needed64 All other projects or programmes - asset relocations –65 Asset relocations expenditure –66 less Capital contributions funding asset relocations –67 Asset relocations less capital contributions –

System Growth

Asset Replacement and

Renewal


This schedule requires a breakdown of capital expenditure on assets incurred in the disclosure year, including any assets in respect of which capital contributions are received, but excluding assets that are vested assets. Information on expenditure on assets must be provided on an accounting accruals basis and must exclude finance costs. EDBs must provide explanatory comment on their expenditure on assets in Schedule 14 (Explanatory Notes to Templates).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 21 S6a.Actual Expenditure Capex


SCHEDULE 6a: REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR

sch ref


This schedule requires a breakdown of capital expenditure on assets incurred in the disclosure year, including any assets in respect of which capital contributions are received, but excluding assets that are vested assets. Information on expenditure on assets must be provided on an accounting accruals basis and must exclude finance costs. EDBs must provide explanatory comment on their expenditure on assets in Schedule 14 (Explanatory Notes to Templates).This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.

68

69 6a(vi): Quality of Supply70 Project or programme* ($000) ($000)71 Static var generator installation 6772 –73 –74 –75 –76 * include additional rows if needed77 All other projects programmes - quality of supply –78 Quality of supply expenditure 6779 less Capital contributions funding quality of supply –80 Quality of supply less capital contributions 67

81 6a(vii): Legislative and Regulatory82 Project or programme* ($000) ($000)83 N/A –84 –85 –86 –87 –88 * include additional rows if needed89 All other projects or programmes - legislative and regulatory –90 Legislative and regulatory expenditure –91 less Capital contributions funding legislative and regulatory –92 Legislative and regulatory less capital contributions –

93 6a(viii): Other Reliability, Safety and Environment94 Project or programme* ($000) ($000)95 Low voltage network monitoring - data loggers installation 4896 –97 –98 –99 –

100 * include additional rows if needed101 All other projects or programmes - other reliability, safety and environment –102 Other reliability, safety and environment expenditure 48103 less Capital contributions funding other reliability, safety and environment –104 Other reliability, safety and environment less capital contributions 48

105

106 6a(ix): Non-Network Assets107 Routine expenditure108 Project or programme* ($000) ($000)109 Network software upgrades 300110 Furniture & Buildings –111 Computer equipment 63112 Plant and Equipment 61113 Motor vehicles (including leases vehicles) 281114 * include additional rows if needed115 All other projects or programmes - routine expenditure –116 Routine expenditure 705

117 Atypical expenditure118 Project or programme* ($000) ($000)119 Corporate Office Building 881120 –121 –122 –123 –124 * include additional rows if needed125 All other projects or programmes - atypical expenditure –126 Atypical expenditure 881127128 Expenditure on non-network assets 1,586

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10.

xlsx

22S6

b.Ac

tual

Exp

endi

ture

Ope

x

Com

pany

Nam

eFo

r Yea

r End

ed

SCHE

DULE

6b:

REP

ORT

ON

OPE

RATI

ON

AL E

XPEN

DITU

RE F

OR

THE

DISC

LOSU

RE Y

EAR

sch

ref

76b

(i): O

pera

tiona

l Exp

endi

ture

($00

0)($

000)

8Se

rvice

inte

rrupt

ions

and

em

erge

ncie

s 3

659

Vege

tatio

n m

anag

emen

t 6

4210

Rout

ine

and

corre

ctiv

e m

aint

enan

ce a

nd in

spec

tion

228

11As

set r

epla

cem

ent a

nd re

new

al 4

1212

Net

wor

k op

ex 1

,648

13Sy

stem

ope

ratio

ns a

nd n

etw

ork

supp

ort

521

14Bu

sines

s sup

port

1,5

8115

Non

-net

wor

k op

ex 2

,102

16 17O

pera

tiona

l exp

endi

ture

3,7

50

186b

(ii):

Subc

ompo

nent

s of

Ope

ratio

nal E

xpen

ditu

re (w

here

kno

wn)

19En

ergy

effi

cienc

y an

d de

man

d sid

e m

anag

emen

t, re

duct

ion

of e

nerg

y lo

sses

–20

Dire

ct b

illing

* –

21Re

sear

ch a

nd d

evel

opm

ent

–22

Insu

ranc

e –

23*

Dire

ct b

illing

exp

endi

ture

by s

uppl

iers

that

dire

ctly

bill t

he m

ajor

ity o

f the

ir co

nsum

ers

This

sche

dule

requ

ires a

bre

akdo

wn

of o

pera

tiona

l exp

endi

ture

incu

rred

in th

e di

sclo

sure

yea

r. ED

Bs m

ust p

rovi

de e

xpla

nato

ry co

mm

ent o

n th

eir o

pera

tiona

l exp

endi

ture

in S

ched

ule

14 (E

xpla

nato

ry n

otes

to te

mpl

ates

). Th

is in

clude

s exp

lana

tory

com

men

t on

any

atyp

ical o

pera

tiona

l ex

pend

iture

and

ass

ets r

epla

ced

or re

new

ed a

s par

t of a

sset

repl

acem

ent a

nd re

new

al o

pera

tiona

l exp

endi

ture

, and

add

ition

al in

form

atio

n on

insu

ranc

e.Th

is in

form

atio

n is

part

of a

udite

d di

sclo

sure

info

rmat

ion

(as d

efin

ed in

sect

ion

1.4

of th

e ID

det

erm

inat

ion)

, and

so is

subj

ect t

o th

e as

sura

nce

repo

rt re

quire

d by

sect

ion

2.8.

Scan

pow

er Li

mite

d31

Mar

ch 2

021


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 23 S7.Actual vs Forecast


SCHEDULE 7: COMPARISON OF FORECASTS TO ACTUAL EXPENDITURE

sch ref

7 7(i): Revenue Target ($000) ¹ Actual ($000) % variance

8 Line charge revenue 8,217 8,269 1%

9 7(ii): Expenditure on Assets Forecast ($000) ² Actual ($000) % variance

10 Consumer connection 32 123 284%11 System growth 32 123 284%12 Asset replacement and renewal 1,742 1,827 5%13 Asset relocations – – –14 Reliability, safety and environment:15 Quality of supply – 67 –16 Legislative and regulatory – – –17 Other reliability, safety and environment 99 48 (52%)18 Total reliability, safety and environment 99 115 16%19 Expenditure on network assets 1,905 2,188 15%20 Expenditure on non-network assets 53 1,586 2,893%21 Expenditure on assets 1,958 3,774 93%

22 7(iii): Operational Expenditure 23 Service interruptions and emergencies 526 365 (31%)24 Vegetation management 321 642 100%25 Routine and corrective maintenance and inspection 329 228 (31%)26 Asset replacement and renewal 549 412 (25%)27 Network opex 1,725 1,648 (4%)

28 System operations and network support 599 521 (13%)29 Business support 1,424 1,581 11%30 Non-network opex 2,023 2,102 4%31 Operational expenditure 3,748 3,750 0%

32 7(iv): Subcomponents of Expenditure on Assets (where known)33 Energy efficiency and demand side management, reduction of energy losses – – –34 Overhead to underground conversion – – –35 Research and development – – –36

37 7(v): Subcomponents of Operational Expenditure (where known) 38 Energy efficiency and demand side management, reduction of energy losses – – –39 Direct billing – – –40 Research and development – – –41 Insurance – – –4243 1 From the nominal dollar target revenue for the disclosure year disclosed under clause 2.4.3(3) of this determination

44

This schedule compares actual revenue and expenditure to the previous forecasts that were made for the disclosure year. Accordingly, this schedule requires the forecast revenue and expenditure information from previous disclosures to be inserted. EDBs must provide explanatory comment on the variance between actual and target revenue and forecast expenditure in Schedule 14 (Mandatory Explanatory Notes). This information is part of the audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8. For the purpose of this audit, target revenue and forecast expenditures only need to be verified back to previous disclosures.


2 From the CY+1 nominal dollar expenditure forecasts disclosed in accordance with clause 2.6.6 for the forecast period starting at the beginning of the disclosure year (the second to last disclosure of Schedules 11a and 11b)

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10

adju

sted

.xlsx

29S8

.Bille

d Q

uant

ities

+Rev

enue

s

Com

pany

Nam

eFo

r Yea

r End

edN

etw

ork

/ Su

b-N

etw

ork

Nam

e

SCHE

DULE

8: R

EPO

RT O

N B

ILLE

D Q

UAN

TITI

ES A

ND

LIN

E CH

ARGE

REV

ENUE

S

sch

ref

88(

i): B

illed

Qua

ntiti

es b

y Pr

ice

Com

pone

nt9 10 11

Bille

d qu

antit

ies b

y pr

ice co

mpo

nent

12

Fixe

dFi

xed

Fixe

dVa

riabl

eVa

riabl

eDe

man

d

13Co

nsum

er g

roup

nam

e or

pric

e ca

tego

ry co

deCo

nsum

er ty

pe o

r typ

es (e

g,

resid

entia

l, co

mm

ercia

l etc

.)St

anda

rd o

r non

-sta

ndar

d co

nsum

er g

roup

(spe

cify)

Aver

age

no. o

f ICP

s in

disc

losu

re y

ear

Ener

gy d

eliv

ered

to IC

Ps

in d

isclo

sure

yea

r (M

Wh)

mon

thkV

A ca

pacit

yIC

P su

pply

day

skW

h (D

ay)

kWh

(Nig

ht)

peak

kVA

(June

July

Aug

ust)

14 15D1

resid

entia

lSt

anda

rd 4

,836

57,

315

– 1

,764

,237

47,

528,

845

14,

440,

943

–16

C1co

mm

ercia

lSt

anda

rd 1

,175

– –

427

,463

– –

–17

C1.2

com

mer

cial

Stan

dard

377

– –

127

,243

– –

–18

C1.5

com

mer

cial

Stan

dard

283

– –

103

,071

– –

–19

C3co

mm

ercia

lSt

anda

rd 1

6 2

,734

20,

225

– 2

,248

,621

707

,017

–20

C4co

mm

ercia

lSt

anda

rd 6

5,6

88 2

4,84

0 –

4,6

04,1

86 1

,520

,223

3,3

3721

C5in

dust

rial

Stan

dard

2 1

,200

10,

200

– 1

,015

,836

281

,490

1,3

2222

C6in

dust

rial

Stan

dard

2 9

,529

27,

000

– 6

,998

,417

3,1

04,2

59 5

,046

23M

iscel

lane

ous

publ

ic lig

htin

g, te

leco

m b

oxes

, el

ectri

c fen

ces

Stan

dard

N/A

– 1

3,72

8 –

– –

– –

24[S

elec

t one

]25

Add

extra

row

s for

add

ition

al co

nsum

er g

roup

s or p

rice

cate

gory

code

s as n

eces

sary

26St

anda

rd co

nsum

er to

tals

6,6

97 7

6,46

6 1

3,72

8 8

2,26

5 2

,422

,014

62,

395,

905

20,

053,

933

9,7

0527

Non

-sta

ndar

d co

nsum

er to

tals

– –

– –

– –

– –

28To

tal f

or a

ll con

sum

ers

6,6

97 7

6,46

6 1

3,72

8 8

2,26

5 2

,422

,014

62,

395,

905

20,

053,

933

9,7

05

29 30

Scan

pow

er Li

mite

d31

Mar

ch 2

021

Add

extra

colu

mns

fo

r add

ition

al

bille

d qu

antit

ies b

y pr

ice co

mpo

nent

as

nec

essa

ry

This

sche

dule

requ

ires t

he b

illed

quan

titie

s and

ass

ocia

ted

line

char

ge re

venu

es fo

r eac

h pr

ice ca

tego

ry co

de u

sed

by th

e ED

B in

its p

ricin

g sc

hedu

les.

Info

rmat

ion

is al

so re

quire

d on

the

num

ber o

f ICP

s tha

t are

inclu

ded

in e

ach

cons

umer

gro

up o

r pric

e ca

tego

ry co

de, a

nd th

e en

ergy

del

iver

ed to

thes

e IC

Ps.

Uni

t cha

rgin

g ba

sis (e

g, d

ays,

kW

of d

eman

d,

kVA

of ca

pacit

y, e

tc.)

Price

com

pone

nt

Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10

adju

sted

.xlsx

30S8

.Bille

d Q

uant

ities

+Rev

enue

s

Com

pany

Nam

eFo

r Yea

r End

edN

etw

ork

/ Su

b-N

etw

ork

Nam

e

SCHE

DULE

8: R

EPO

RT O

N B

ILLE

D Q

UAN

TITI

ES A

ND

LIN

E CH

ARGE

REV

ENUE

S

Scan

pow

er Li

mite

d31

Mar

ch 2

021

This

sche

dule

requ

ires t

he b

illed

quan

titie

s and

ass

ocia

ted

line

char

ge re

venu

es fo

r eac

h pr

ice ca

tego

ry co

de u

sed

by th

e ED

B in

its p

ricin

g sc

hedu

les.

Info

rmat

ion

is al

so re

quire

d on

the

num

ber o

f ICP

s tha

t are

inclu

ded

in e

ach

cons

umer

gro

up o

r pric

e ca

tego

ry co

de, a

nd th

e en

ergy

del

iver

ed to

thes

e IC

Ps.

318(

ii): L

ine

Char

ge R

even

ues

($00

0) b

y Pr

ice

Com

pone

nt32 33

Line

char

ge re

venu

es ($

000)

by

price

com

pone

nt

34

Price

com

pone

ntFi

xed

Fixe

dFi

xed

Varia

ble

Varia

ble

Dem

and

Post

ed d

iscou

nts

35Co

nsum

er g

roup

nam

e or

pric

e ca

tego

ry co

deCo

nsum

er ty

pe o

r typ

es (e

g,

resid

entia

l, co

mm

ercia

l etc

.)St

anda

rd o

r non

-sta

ndar

d co

nsum

er g

roup

(spe

cify)

Tota

l line

char

ge re

venu

e in

di

sclo

sure

yea

r

Not

iona

l rev

enue

fo

rego

ne fr

om p

oste

d di

scou

nts (

if ap

plica

ble)

Tota

l dist

ribut

ion

line

char

ge

reve

nue

Rate

(eg,

$ p

er d

ay, $

per

kW

h, e

tc.)

$/m

onth

$/kV

A ca

pacit

y$/

day

$/kW

h (D

ay)

$/kW

h (N

ight

)$/

peak

kVA

(June

July

Aug

ust)

36 37D1

resid

entia

lSt

anda

rd $

6,07

6 ($

1,34

1) $

6,07

6 –

– $

265

$5,

903

$1,

249

– ($

1,34

1)38

C1co

mm

ercia

lSt

anda

rd $

375

($21

9) $

375

– –

$59

4 –

– –

($21

9)39

C1.2

com

mer

cial

Stan

dard

$78

($22

) $

78 –

– $

100

– –

– ($

22)

40C1

.5co

mm

ercia

lSt

anda

rd $

89 ($

18)

$89

– –

$10

7 –

– –

($18

)41

C3co

mm

ercia

lSt

anda

rd $

315

($8)

$31

5 –

$96

– $

188

$39

– ($

8)42

C4co

mm

ercia

lSt

anda

rd $

529

($8)

$52

9 –

$11

8 –

$35

0 $

40 $

28 ($

8)43

C5in

dust

rial

Stan

dard

$14

2 ($

3) $

142

– $

49 –

$77

$7

$11

($3)

44C6

indu

stria

lSt

anda

rd $

625

($5)

$62

5 –

$20

4 –

$33

9 $

48 $

39 ($

5)45

Misc

ella

neou

spu

blic

light

ing,

tele

com

box

es,

elec

tric f

ence

sSt

anda

rd $

39 ($

2) $

39 $

41 –

– –

– –

($2)

46[S

elec

t one

] –

47Ad

d ex

tra ro

ws f

or a

dditi

onal

cons

umer

gro

ups o

r pric

e ca

tego

ry co

des a

s nec

essa

ry48

Stan

dard

cons

umer

tota

ls $

8,26

9 ($

1,62

6) $

8,26

9 –

$41

$46

7 $

1,06

6 $

6,85

7 $

1,38

4 $

79 ($

1,62

6)49

Non

-sta

ndar

d co

nsum

er to

tals

– –

– –

– –

– –

– –

–50

Tota

l for

all c

onsu

mer

s $

8,26

9 ($

1,62

6) $

8,26

9 –

$41

$46

7 $

1,06

6 $

6,85

7 $

1,38

4 $

79 ($

1,62

6)

51 528(

iii):

Num

ber o

f ICP

s di

rect

ly b

illed

Chec

kO

K

53N

umbe

r of d

irect

ly b

illed

ICPs

at y

ear e

nd

Tota

l tra

nsm

issio

n lin

e ch

arge

re

venu

e (if

av

aila

ble)

Add

extra

colu

mns

fo

r add

ition

al lin

e ch

arge

reve

nues

by

pric

e co

mpo

nent

as

nece

ssar

y


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 26 S9a.Asset Register


Network / Sub-network Name

SCHEDULE 9a: ASSET REGISTER

sch ref

8 Voltage Asset category Asset class UnitsItems at start of year (quantity)

Items at end of year (quantity) Net change

Data accuracy(1–4)

9 All Overhead Line Concrete poles / steel structure No. 8,461 8,694 233 3 10 All Overhead Line Wood poles No. 2,614 2,419 (195) 2 11 All Overhead Line Other pole types No. – N/A 12 HV Subtransmission Line Subtransmission OH up to 66kV conductor km – N/A 13 HV Subtransmission Line Subtransmission OH 110kV+ conductor km – N/A 14 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km – N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km – N/A 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km – N/A 17 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km – N/A 18 HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km – N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km – N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km – N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km – N/A 22 HV Subtransmission Cable Subtransmission submarine cable km – N/A 23 HV Zone substation Buildings Zone substations up to 66kV No. – N/A 24 HV Zone substation Buildings Zone substations 110kV+ No. – N/A 25 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. – N/A 26 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. – N/A 27 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. – N/A 28 HV Zone substation switchgear 33kV Switch (Pole Mounted) No. – N/A 29 HV Zone substation switchgear 33kV RMU No. – N/A 30 HV Zone substation switchgear 22/33kV CB (Indoor) No. – N/A 31 HV Zone substation switchgear 22/33kV CB (Outdoor) No. – N/A 32 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No. – N/A 33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No. – N/A 34 HV Zone Substation Transformer Zone Substation Transformers No. – N/A 35 HV Distribution Line Distribution OH Open Wire Conductor km 840 834 (6) 3 36 HV Distribution Line Distribution OH Aerial Cable Conductor km – N/A 37 HV Distribution Line SWER conductor km – N/A 38 HV Distribution Cable Distribution UG XLPE or PVC km 15 16 1 3 39 HV Distribution Cable Distribution UG PILC km 2 2 – 3 40 HV Distribution Cable Distribution Submarine Cable km – N/A 41 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No. 36 43 7 4 42 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No. – N/A 43 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No. 1,679 1,693 14 2 44 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No. – N/A 45 HV Distribution switchgear 3.3/6.6/11/22kV RMU No. 16 16 – 4 46 HV Distribution Transformer Pole Mounted Transformer No. 1,336 1,344 8 3 47 HV Distribution Transformer Ground Mounted Transformer No. 116 120 4 2 48 HV Distribution Transformer Voltage regulators No. 1 1 – 2 49 HV Distribution Substations Ground Mounted Substation Housing No. 40 40 – 3 50 LV LV Line LV OH Conductor km 111 108 (3) 2 51 LV LV Cable LV UG Cable km 77 78 1 3 52 LV LV Street lighting LV OH/UG Streetlight circuit km – N/A 53 LV Connections OH/UG consumer service connections No. 6,680 6,717 37 2 54 All Protection Protection relays (electromechanical, solid state and numeric) No. – N/A 55 All SCADA and communications SCADA and communications equipment operating as a single system Lot 1 1 – 3 56 All Capacitor Banks Capacitors including controls No – N/A 57 All Load Control Centralised plant Lot – N/A 58 All Load Control Relays No – N/A 59 All Civils Cable Tunnels km – N/A

This schedule requires a summary of the quantity of assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths.


Com

mer

ce C

omm

issio

n In

form

atio

n Di

sclo

sure

Tem

plat

e

Info

rmat

ion

Disc

losu

res 3

1 M

arch

202

1 - S

ched

ules

-1-to

-10.

xlsx

27S9

b.As

set A

ge P

rofil

e

Com

pany

Nam

eFo

r Yea

r End

edN

etw

ork

/ Su

b-ne

twor

k N

ame

SCHE

DULE

9b:

ASS

ET A

GE P

ROFI

LE

sch

ref

8Di

sclo

sure

Yea

r (ye

ar e

nded

)31

Mar

ch 2

021

9Vo

ltage

Asse

t cat

egor

yAs

set c

lass

Uni

tspr

e-19

4019

40–1

949

1950

–195

919

60–1

969

1970

–197

919

80–1

989

1990

–199

920

0020

0120

0220

0320

0420

0520

0620

0720

0820

0920

1020

1120

1220

1320

1420

1520

1620

1720

1820

1920

2020

2120

2220

2320

2420

25

No.

with

ag

e un

know

n

Item

s at

end

of y

ear

(qua

ntity

)

No.

with

defa

ult

date

sDa

ta a

ccur

acy

(1–4

)10

All

Ove

rhea

d Li

neCo

ncre

te p

oles

/ st

eel s

truct

ure

No.

- -

- -

297

2,2

12 1

,344

222

157

201

241

266

229

245

217

266

196

306

249

189

181

192

201

244

206

248

308

240

10

27

8,6

94 –

311

All

Ove

rhea

d Li

neW

ood

pole

sNo

. -

- 6

11 -

102

467

957

43

59

14

15

5 4

6 2

4 6

3 2

4 -

- -

- -

- -

- -

- -

61

2,4

19 6

113

12Al

lO

verh

ead

Line

Oth

er p

ole

type

sNo

. –

N/A

13HV

Subt

rans

miss

ion

Line

Subt

rans

miss

ion

OH

up to

66k

V co

nduc

tor

km –

N/A

14HV

Subt

rans

miss

ion

Line

Subt

rans

miss

ion

OH

110k

V+ co

nduc

tor

km –

N/A

15HV

Subt

rans

miss

ion

Cabl

eSu

btra

nsm

issio

n UG

up

to 6

6kV

(XLP

E)km

–N/

A16

HVSu

btra

nsm

issio

n Ca

ble

Subt

rans

miss

ion

UG u

p to

66k

V (O

il pre

ssur

ised)

km –

N/A

17HV

Subt

rans

miss

ion

Cabl

eSu

btra

nsm

issio

n UG

up

to 6

6kV

(Gas

pre

ssur

ised)

km –

N/A

18HV

Subt

rans

miss

ion

Cabl

eSu

btra

nsm

issio

n UG

up

to 6

6kV

(PIL

C)km

–N/

A19

HVSu

btra

nsm

issio

n Ca

ble

Subt

rans

miss

ion

UG 1

10kV

+ (X

LPE)

km –

N/A

20HV

Subt

rans

miss

ion

Cabl

eSu

btra

nsm

issio

n UG

110

kV+

(Oil p

ress

urise

d)km

–N/

A21

HVSu

btra

nsm

issio

n Ca

ble

Subt

rans

miss

ion

UG 1

10kV

+ (G

as P

ress

urise

d)km

–N/

A22

HVSu

btra

nsm

issio

n Ca

ble

Subt

rans

miss

ion

UG 1

10kV

+ (P

ILC)

km –

N/A

23HV

Subt

rans

miss

ion

Cabl

eSu

btra

nsm

issio

n su

bmar

ine

cabl

ekm

–N/

A24

HVZo

ne su

bsta

tion

Build

ings

Zo

ne su

bsta

tions

up

to 6

6kV

No.

–N/

A25

HVZo

ne su

bsta

tion

Build

ings

Zo

ne su

bsta

tions

110

kV+

No.

–N/

A26

HVZo

ne su

bsta

tion

switc

hgea

r 50

/66/

110k

V CB

(Ind

oor)

No.

–N/

A27

HVZo

ne su

bsta

tion

switc

hgea

r 50

/66/

110k

V CB

(Out

door

)No

. –

N/A

28HV

Zone

subs

tatio

n sw

itchg

ear

33kV

Sw

itch

(Gro

und

Mou

nted

)No

. –

N/A

29HV

Zone

subs

tatio

n sw

itchg

ear

33kV

Sw

itch

(Pol

e M

ount

ed)

No.

–N/

A30

HVZo

ne su

bsta

tion

switc

hgea

r 33

kV R

MU

No.

–N/

A31

HVZo

ne su

bsta

tion

switc

hgea

r 22

/33k

V CB

(Ind

oor)

No.

–N/

A32

HVZo

ne su

bsta

tion

switc

hgea

r 22

/33k

V CB

(Out

door

)No

. –

N/A

33HV

Zone

subs

tatio

n sw

itchg

ear

3.3/

6.6/

11/2

2kV

CB (g

roun

d m

ount

ed)

No.

–N/

A34

HVZo

ne su

bsta

tion

switc

hgea

r 3.

3/6.

6/11

/22k

V CB

(pol

e m

ount

ed)

No.

–N/

A35

HVZo

ne S

ubst

atio

n Tr

ansf

orm

er

Zone

Sub

stat

ion

Tran

sfor

mer

sNo

. –

N/A

36HV

Dist

ribut

ion

Line

Dist

ribut

ion

OH

Ope

n W

ire C

ondu

ctor

km -

- 2

78

83

215

208

34

18

4 1

2 1

7 1

8 3

0 1

4 1

8 1

5 1

0 2

1 7

6 1

5 8

6 9

3 -

- -

- -

10

834

337

HVDi

strib

utio

n Lin

eDi

strib

utio

n O

H Ae

rial C

able

Con

duct

orkm

–N/

A38

HVDi

strib

utio

n Lin

eSW

ER co

nduc

tor

km –

N/A

39HV

Dist

ribut

ion

Cabl

eDi

strib

utio

n UG

XLP

E or

PVC

km -

- -

- 1

1 1

– 1

– –

1 1

2 1

– 1

1 –

– 1

– 1

– –

1 1

1 –

– –

– –

– 1

63

40HV

Dist

ribut

ion

Cabl

eDi

strib

utio

n UG

PIL

Ckm

- -

- -

1 1

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

23

41HV

Dist

ribut

ion

Cabl

eDi

strib

utio

n Su

bmar

ine

Cabl

ekm

–N/

A42

HVDi

strib

utio

n sw

itchg

ear

3.3/

6.6/

11/2

2kV

CB (p

ole

mou

nted

) - re

close

rs a

nd se

ctio

nalis

ers

No.

– –

– –

– –

5 4

– –

1 –

– –

– 1

7 –

– –

12

– 4

– –

1 1

5 2

– –

– –

– 4

33

43HV

Dist

ribut

ion

switc

hgea

r 3.

3/6.

6/11

/22k

V CB

(Ind

oor)

No.

–N/

A44

HVDi

strib

utio

n sw

itchg

ear

3.3/

6.6/

11/2

2kV

Switc

hes a

nd fu

ses (

pole

mou

nted

)No

. –

– –

23

129

256

307

55

45

49

42

63

66

31

38

46

36

28

26

23

36

51

35

57

62

66

67

49

7 –

– –

– –

1,6

932

45HV

Dist

ribut

ion

switc

hgea

r 3.

3/6.

6/11

/22k

V Sw

itch

(gro

und

mou

nted

) - e

xcep

t RM

UNo

. –

N/A

46HV

Dist

ribut

ion

switc

hgea

r 3.

3/6.

6/11

/22k

V RM

UNo

. –

– –

– –

– –

– –

– –

– 1

– –

– –

1 1

1 2

1 –

– 3

3 3

– –

– –

– –

– 1

64

47HV

Dist

ribut

ion

Tran

sfor

mer

Pole

Mou

nted

Tra

nsfo

rmer

No.

– –

42

242

220

152

76

7 1

4 1

4 1

4 5

9 5

6 2

1 3

0 3

6 1

9 3

1 1

9 2

3 3

0 4

1 2

4 5

1 5

6 2

2 2

6 1

7 2

– –

– –

– 1

,344

348

HVDi

strib

utio

n Tr

ansf

orm

erGr

ound

Mou

nted

Tra

nsfo

rmer

No.

– –

1 7

22

27

5 –

4 2

2 2

8 5

3 5

3 1

1 3

1 5

6 –

1 1

– 4

1 –

– –

– –

120

349

HVDi

strib

utio

n Tr

ansf

orm

er

Volta

ge re

gula

tors

No.

– –

– –

– –

– –

– 1

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

12

50HV

Dist

ribut

ion

Subs

tatio

nsGr

ound

Mou

nted

Sub

stat

ion

Hous

ing

No.

– –

– –

5 1

6 1

4 1

2 1

– –

1 –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

40

351

LVLV

Line

LV O

H Co

nduc

tor

km -

- -

7 2

0 3

5 1

9 3

3 2

1 –

1 1

1 1

2 3

– –

1 1

2 1

2 1

1 –

– –

– –

– –

108

252

LVLV

Cab

leLV

UG

Cabl

ekm

- -

- -

6 1

9 1

5 4

3 3

1 4

3 1

5 3

– 1

– 3

1 1

2 –

1 –

1 1

– –

– –

– –

78

353

LVLV

Stre

et lig

htin

gLV

OH/

UG S

treet

light

circ

uit

km –

N/A

54LV

Conn

ectio

nsO

H/UG

cons

umer

serv

ice co

nnec

tions

No.

– –

– –

105

335

561

132

65

79

18

82

74

24

99

56

4 2

9 4

51

14

16

12

12

45

22

7 3

6 8

4,8

27 6

,717

255

All

Prot

ectio

nPr

otec

tion

rela

ys (e

lect

rom

echa

nica

l, sol

id st

ate

and

num

eric)

No.

–N/

A56

All

SCAD

A an

d co

mm

unica

tions

SCAD

A an

d co

mm

unica

tions

equ

ipm

ent o

pera

ting

as a

sing

le sy

stem

Lot

– –

– –

– –

– –

– –

1 –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

– –

13

57Al

lCa

pacit

or B

anks

Capa

citor

s inc

ludi

ng co

ntro

lsNo

–N/

A58

All

Load

Con

trol

Cent

ralis

ed p

lant

Lot

–N/

A59

All

Load

Con

trol

Rela

ysNo

–N/

A60

All

Civi

lsCa

ble

Tunn

els

km –

N/A

This

sche

dule

requ

ires a

sum

mar

y of

the

age

prof

ile (b

ased

on

year

of i

nsta

llatio

n) o

f the

ass

ets t

hat m

ake

up th

e ne

twor

k, b

y as

set c

ateg

ory

and

asse

t cla

ss. A

ll uni

ts re

latin

g to

cabl

e an

d lin

e as

sets

, tha

t are

exp

ress

ed in

km

, ref

er to

circ

uit l

engt

hs.

Scan

pow

er Li

mite

d31

Mar

ch 2

021

Num

ber o

f ass

ets a

t disc

losu

re y

ear e

nd b

y in

stal

latio

n da

te


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 28 S9c.Overhead Lines



SCHEDULE 9c: REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES

sch ref

9

10 Circuit length by operating voltage (at year end) Overhead (km) Underground (km)Total circuit length

(km)11 > 66kV – – –12 50kV & 66kV – – –13 33kV – – –14 SWER (all SWER voltages) – – –15 22kV (other than SWER) – – –16 6.6kV to 11kV (inclusive—other than SWER) 834 18 85217 Low voltage (< 1kV) 108 78 18618 Total circuit length (for supply) 942 96 1,0381920 Dedicated street lighting circuit length (km) – – –21 Circuit in sensitive areas (conservation areas, iwi territory etc) (km) –22

23 Overhead circuit length by terrain (at year end) Circuit length (km)(% of total

overhead length)24 Urban 43 5%25 Rural 899 95%26 Remote only – –27 Rugged only – –28 Remote and rugged – –29 Unallocated overhead lines – –30 Total overhead length 942 100%31

32 Circuit length (km)(% of total circuit

length)33 Length of circuit within 10km of coastline or geothermal areas (where known) – –

34 Circuit length (km)(% of total

overhead length)35 Overhead circuit requiring vegetation management – –

This schedule requires a summary of the key characteristics of the overhead line and underground cable network. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths.



Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 29 S9d.Embedded Networks


sch ref

8 Location *Number of ICPs

servedLine charge revenue

($000)9

10111213141516171819202122232425

26


* Extend embedded distribution networks table as necessary to disclose each embedded network owned by the EDB which is embedded in another EDB’s network or in another embedded network

SCHEDULE 9d: REPORT ON EMBEDDED NETWORKS

N/A

This schedule requires information concerning embedded networks owned by an EDB that are embedded in another EDB’s network or in another embedded network.


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 30 S9e.Demand



SCHEDULE 9e: REPORT ON NETWORK DEMAND

sch ref

8 9e(i): Consumer Connections9 Number of ICPs connected in year by consumer type

10 Consumer types defined by EDB*Number of

connections (ICPs)11 D1 Standard Domestic 4,83612 C1 Standard Commercial 1,183

C1.2 Commercial (2kVA) 377C1.5 Commercial (5kVA) 283C3 Commercial 16

13 C4 Commercial 614 C5 Industrial 215 C6 Industrial 216 * include additional rows if needed17 Connections total 6,70518

19 Distributed generation20 Number of connections made in year 5 connections

21 Capacity of distributed generation installed in year 0.02 MVA

22 9e(ii): System Demand2324

25 Maximum coincident system demand26 GXP demand 1627 plus Distributed generation output at HV and above –28 Maximum coincident system demand 1629 less Net transfers to (from) other EDBs at HV and above30 Demand on system for supply to consumers' connection points 16

31 Electricity volumes carried Energy (GWh)32 Electricity supplied from GXPs 8233 less Electricity exports to GXPs34 plus Electricity supplied from distributed generation35 less Net electricity supplied to (from) other EDBs36 Electricity entering system for supply to consumers' connection points 8237 less Total energy delivered to ICPs 7638 Electricity losses (loss ratio) 6 7.3%3940 Load factor 0.57

41 9e(iii): Transformer Capacity42 (MVA)43 Distribution transformer capacity (EDB owned) 7544 Distribution transformer capacity (Non-EDB owned, estimated) –45 Total distribution transformer capacity 75

4647 Zone substation transformer capacity

Demand at time of maximum

coincident demand (MW)


This schedule requires a summary of the key measures of network utilisation for the disclosure year (number of new connections including distributed generation, peak demand and electricity volumes conveyed).


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 31 S10.Reliability



SCHEDULE 10: REPORT ON NETWORK RELIABILITY

sch ref

8 10(i): Interruptions

9 Interruptions by classNumber of

interruptions10 Class A (planned interruptions by Transpower) –11 Class B (planned interruptions on the network) 15812 Class C (unplanned interruptions on the network) 4013 Class D (unplanned interruptions by Transpower) –14 Class E (unplanned interruptions of EDB owned generation) –15 Class F (unplanned interruptions of generation owned by others) –16 Class G (unplanned interruptions caused by another disclosing entity) –17 Class H (planned interruptions caused by another disclosing entity) –18 Class I (interruptions caused by parties not included above) –19 Total 1982021 Interruption restoration ≤3Hrs >3hrs22 Class C interruptions restored within 31 923

24 SAIFI and SAIDI by class SAIFI SAIDI25 Class A (planned interruptions by Transpower) – –26 Class B (planned interruptions on the network) 0.39 57.327 Class C (unplanned interruptions on the network) 0.27 33.628 Class D (unplanned interruptions by Transpower) – –29 Class E (unplanned interruptions of EDB owned generation) – –30 Class F (unplanned interruptions of generation owned by others) – –31 Class G (unplanned interruptions caused by another disclosing entity) – –32 Class H (planned interruptions caused by another disclosing entity) – –33 Class I (interruptions caused by parties not included above) – –34 Total 0.66 90.935

36 Normalised SAIFI and SAIDI Normalised SAIFI Normalised SAIDI37 Classes B & C (interruptions on the network) 0.65 90.9

38


This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.


Information Disclosures 31 March 2021 - Schedules-1-to-10.xlsx 32 S10.Reliability



SCHEDULE 10: REPORT ON NETWORK RELIABILITY


This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8.

39 10(ii): Class C Interruptions and Duration by Cause40

41 Cause SAIFI SAIDI42 Lightning – –43 Vegetation 0.02 4.244 Adverse weather – –45 Adverse environment – –46 Third party interference 0.12 15.447 Wildlife – –48 Human error – –49 Defective equipment 0.13 14.350 Cause unknown – –51

52 10(iii): Class B Interruptions and Duration by Main Equipment Involved53

54 Main equipment involved SAIFI SAIDI55 Subtransmission lines – –56 Subtransmission cables – –57 Subtransmission other – –58 Distribution lines (excluding LV) 0.15 28.069 Distribution cables (excluding LV) – –60 Distribution other (excluding LV) 0.24 29.2

61 10(iv): Class C Interruptions and Duration by Main Equipment Involved62

63 Main equipment involved SAIFI SAIDI64 Subtransmission lines – –65 Subtransmission cables – –66 Subtransmission other – –67 Distribution lines (excluding LV) 0.11 11.368 Distribution cables (excluding LV) – –69 Distribution other (excluding LV) 0.16 22.3

70 10(v): Fault Rate

71 Main equipment involved Number of Faults Circuit length (km)Fault rate (faults

per 100km)72 Subtransmission lines – – –73 Subtransmission cables – – –74 Subtransmission other –75 Distribution lines (excluding LV) 27 834 3.2476 Distribution cables (excluding LV) – 18 –77 Distribution other (excluding LV) 1378 Total 40


For Year Ended 31 March 2021

Schedule 14 Mandatory Explanatory Notes (Guidance Note: This Microsoft Word version of Schedules 14, 14a and 15 is from the Electricity Distribution Information Disclosure Determination 2012 – as amended and consolidated 3 April 2018. Clause references in this template are to that determination)

1. This schedule requires EDBs to provide explanatory notes to information provided in accordance with clauses 2.3.1, 2.4.21, 2.4.22, and subclauses 2.5.1(1)(f),and 2.5.2(1)(e).

2. This schedule is mandatory—EDBs must provide the explanatory comment specified below, in accordance with clause 2.7.1. Information provided in boxes 1 to 11 of this schedule is part of the audited disclosure information, and so is subject to the assurance requirements specified in section 2.8.

3. Schedule 15 (Voluntary Explanatory Notes to Schedules) provides for EDBs to give additional explanation of disclosed information should they elect to do so.

Return on Investment (Schedule 2)

4. In the box below, comment on return on investment as disclosed in Schedule 2. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

Box 1: Explanatory comment on return on investment Classification is consistent with previous treatment and there was no reclassification of items. Scanpower is not required to, and did not elect to, disclose information in accordance with part 2(iii) of Schedule 2.

Regulatory Profit (Schedule 3)

5. In the box below, comment on regulatory profit for the disclosure year as disclosed in Schedule 3. This comment must include-

5.1 a description of material items included in other regulated income (other than gains / (losses) on asset disposals), as disclosed in 3(i) of Schedule 3

5.2 information on reclassified items in accordance with subclause 2.7.1(2).

Box 2: Explanatory comment on regulatory profit “Other regulated income” includes Transmission Rental Rebates ($135k) load shedding income ($11k) and other Network revenue ($809k).

There were gains to the value of $10k on the sale of vehicles and losses on disposal of Network assets to the value of $80k. A net loss of $70k is disclosed.

There were no reclassified costs.

Merger and acquisition expenses (3(iv) of Schedule 3)

6. If the EDB incurred merger and acquisitions expenditure during the disclosure year, provide the following information in the box below-

6.1 information on reclassified items in accordance with subclause 2.7.1(2)

6.2 any other commentary on the benefits of the merger and acquisition expenditure to the EDB.

Box 3: Explanatory comment on merger and acquisition expenditure There has been no merger and acquisition expenditure.

Value of the Regulatory Asset Base (Schedule 4)

7. In the box below, comment on the value of the regulatory asset base (rolled forward) in Schedule 4. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

Box 4: Explanatory comment on the value of the regulatory asset based (rolled forward) RAB asset categories are as per the accounting records and there was one reclassification during the year. An office building that was previously the Network offices, was swapped with one of the Scanpower tenants’ offices since the tenants required more office space. The “new” Network offices has never previously been used to supply electricity distribution services and therefore was shown as an asset commissioned to the value of $881k. The “old” network offices will not be used to supply electricity distribution services and since Scanpower owns the building, and since there was no change in ownership it was not a disposal. The office building was reclassified from non-network asset directly attributable to electricity distribution services on 31 March 2020 to a non-network asset not directly attributable to the electricity distribution services on 31 March 2021. Due to this reclassification, there is an adjustment resulting from asset allocation of $1.31m on S4. RAB (Rolled Forward). The reclassified building was included in the RAB as $1.322m on 31 March 2020 and was reclassified at a value of $1.31m on 31 March 2021.

There were no other reclassification items this year and the method for allocating RAB into the asset categories, other than the above, is the same method used in previous years.

Regulatory tax allowance: disclosure of permanent differences (5a(i) of Schedule 5a)

8. In the box below, provide descriptions and workings of the material items recorded in the following asterisked categories of 5a(i) of Schedule 5a-

8.1 Income not included in regulatory profit / (loss) before tax but taxable;

8.2 Expenditure or loss in regulatory profit / (loss) before tax but not deductible;

8.3 Income included in regulatory profit / (loss) before tax but not taxable;

8.4 Expenditure or loss deductible but not in regulatory profit / (loss) before tax.

Box 5: Regulatory tax allowance: permanent differences There are none of the above-mentioned permanent differences included in 5a(i) of Schedule 5a.

Regulatory tax allowance: disclosure of temporary differences (5a(vi) of Schedule 5a)

9. In the box below, provide descriptions and workings of material items recorded in the asterisked category ‘Tax effect of other temporary differences’ in 5a(vi) of Schedule 5a.

Box 6: Tax effect of other temporary differences (current disclosure year) The temporary differences are those used in Scanpower’s annual tax return and are as follows (shown as $000):

Closing balance Opening balance Variance

ACC levies $21 ($31) ($10)

Standby leave $32 ($26) $6

Holiday pay $138 ($112) $26

Long Service leave $58 ($58) $0

Retirement gratuity $150 ($146) $4

Net total $399 ($373) 26

Tax effect – 28% $7

Cost allocation (Schedule 5d)

10. In the box below, comment on cost allocation as disclosed in Schedule 5d. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

Box 7: Cost allocation Costs are allocated by applying the Accounting-based allocation approach (ABAA) since the revenues received by Scanpower from the supply of all unregulated services exceed 20% of revenues received from the supply of all regulated services supplied by Scanpower. Where a causal relationship was identified the cost was allocated according to a cost driver. If a causal relationship could not be established the allocation was done by proxy cost allocator. Business support costs to the value of $1,924k of the Corporate division were allocated using this methodology and $1,386k was allocated to the electricity distribution services and $538 to Non-electricity distribution services.

Asset allocation (Schedule 5e)

11. In the box below, comment on asset allocation as disclosed in Schedule 5e. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

Box 8: Commentary on asset allocation An office building that was previously the Network offices, was swapped with one of the Scanpower tenants’ offices since the tenants required more office space. The “new” Network offices has never previously been used to supply electricity distribution services and therefore was shown as an asset commissioned to the value of $881k. The “old” network offices will not be used to supply electricity distribution services and since Scanpower owns the building, and since there was no change in ownership it was not a disposal. The office building was reclassified on S5e. Asset Allocations from non-network asset directly attributable to electricity distribution services on 31 March 2020 to a non-network asset not directly attributable to the electricity distribution services on 31 March 2021. Due to this reclassification, there is an adjustment resulting from asset allocation of $1.31m on S4. RAB (Rolled Forward). The reclassified building was included in the RAB as $1.322m on 31 March 2020 and was reclassified at a value of $1.31m on 31 March 2021.

All other assets were deemed to be directly attributable to the Regulated Services and therefore there were no other asset allocations.

Capital Expenditure for the Disclosure Year (Schedule 6a)

12. In the box below, comment on expenditure on assets for the disclosure year, as disclosed in Schedule 6a. This comment must include-

12.1 a description of the materiality threshold applied to identify material projects and programmes described in Schedule 6a;

12.2 information on reclassified items in accordance with subclause 2.7.1(2).

Box 9: Explanation of capital expenditure for the disclosure year Network capital expenditure projects and programmes for any specific year are identified as part of the Asset Management Plan preparation process. The capital expenditure is classified in categories in accordance with Schedule 6a. An annual budget for Network capital expenditure is prepared as per the Asset Management Plan and the projects are created in the project accounting module. As the projects progress all relevant costs are allocated to the projects during the year. Once completed the costs are capitalised and included in the RAB roll-forward and Schedule 6a under the relevant classification.

For most projects the actual cost can be attributed to an actual class or sub-class of regulatory asset expenditure. In such cases, there is no materiality threshold applied.

Similarly, for non-Network assets most of the expenditures on plant and equipment items were not classified in the Asset Management Plan preparation process and has been treated as non-material in the disclosures.

No items have been reclassified.

Operational Expenditure for the Disclosure Year (Schedule 6b)

13. In the box below, comment on operational expenditure for the disclosure year, as disclosed in Schedule 6b. This comment must include-

13.1 Commentary on assets replaced or renewed with asset replacement and renewal operational expenditure, as reported in 6b(i) of Schedule 6b;

13.2 Information on reclassified items in accordance with subclause 2.7.1(2);

13.3 Commentary on any material atypical expenditure included in operational expenditure disclosed in Schedule 6b, a including the value of the expenditure the purpose of the expenditure, and the operational expenditure categories the expenditure relates to.

Box 10: Explanation of operational expenditure for the disclosure year Assets replaced or renewed are typically on the distribution network, and were as a result of the requirement to maintain the Network asset base to sustain asset performance over its intended service life. Elements of the assets require repair and maintenance as identified in the lifecycle maintenance strategies recorded in the Asset Management Plan. This is achieved based on asset inspections and condition assessments and targeted replacement and renewal via reliability analysis.

There were no items reclassified in accordance with clause 2.7.1(2)

There are no items identified as material atypical expenditure within network or non-network opex for the 2021 disclosure year.

Variance between forecast and actual expenditure (Schedule 7)

14. In the box below, comment on variance in actual to forecast expenditure for the disclosure year, as reported in Schedule 7. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

Box 11: Explanatory comment on variance in actual to forecast expenditure Expenditure on assets The capital expenditure on network assets of $2,188k was 15% over the budgeted amount of $1,905k, mainly due to consumer connection, system growth and pole replacement costs being higher than expected. There was unplanned capital expenditure of $560k during the year, and of that $560k there were customer initiated works in the form of customer connections of $123k and system growth of $123k. There were also a few car versus pole incidents during the year which resulted in $95k of unforeseen pole replacement costs. Since this was all unplanned capital expenditure it was not captured in the budgeted amounts. An amount of $99k was budgeted for reliability, safety and environment but the actual expenditure was broken down to quality of supply of $67k and other reliability, safety and environment of $48k due to the nature of the capital expenditure. The total reliability, safety and environment expenditure of $115k was 16% over budget. The expenditure on non-network assets for the year was $1,586k compared to a budgeted amount of $53k. There were three main reasons for the noticeable variance:

• During the year Scanpower swapped corporate offices with another business. As a result of this there was a commissioned Building to the value of $881k included in the 31 March 2021 Regulatory Asset Base.

• There were some corporate and other additions that were not included in the budget, mainly an additional Right of Use Asset of $60k, a Corporate vehicle of $54k and some costs in relation to the office swap of $21k.

• Other non-network capital expenditure that was not part of the planned expenditure include the implementation costs of the Milsoft software of $240k, vehicles to the value of $226k and other plant and equipment of $73k.

Operational expenditure The total operational expenditure of $3,750k was very much in line with the budgeted expenditure of $3,748k. The Network opex was 4% under budget and the non-network opex was 4% over budget. Within the network opex categories, there was a different outcome of actual costs compared to the budget. The vegetation management costs of $642k was 100% over the budgeted figure of $321k. More vegetation management work was required during the year and therefore the actual costs of other network opex categories were reduced to offset for the higher vegetation costs. The reduction resulted in the other network opex categories to be under budget as follows: service interruptions and emergencies 31%, routine and corrective maintenance and inspection 31% and asset replacement and renewal 25%. There were no reclassified items in accordance with clause 2.7.1(2).

Information relating to revenues and quantities for the disclosure year

15. In the box below provide-

15.1 a comparison of the target revenue disclosed before the start of the disclosure year, in accordance with clause 2.4.1 and subclause 2.4.3(3) to total billed line charge revenue for the disclosure year, as disclosed in Schedule 8; and

15.2 explanatory comment on reasons for any material differences between target revenue and total billed line charge revenue.

Box 12: Explanatory comment relating to revenue for the disclosure year The actual line charge revenue for the year was $8,269k compared to the budgeted revenue (net of posted discounts) of $8,217k. The actual revenue was $52k or 0.63% over budget.

Network Reliability for the Disclosure Year (Schedule 10)

16. In the box below, comment on network reliability for the disclosure year, as disclosed in Schedule 10.

Box 13: Commentary on network reliability for the disclosure year Network reliability figures for 2021 were SAIDI at 90.9 and SAIFI at 0.66. This was not compared to quality path normalised reliability limits since Scanpower is an exempt EDB. Also refer to Schedule 15 for additional information on Network reliability.

Insurance cover

17. In the box below, provide details of any insurance cover for the assets used to provide electricity distribution services, including-

17.1 The EDB’s approaches and practices in regard to the insurance of assets used to provide electricity distribution services, including the level of insurance;

17.2 In respect of any self insurance, the level of reserves, details of how reserves are managed and invested, and details of any reinsurance.

Box 14: Explanation of insurance cover As part of the company’s approach to risk management, Scanpower maintains material damage insurance on certain elements of the network asset base and on peripheral but strategically significant non-network assets such as key buildings including the head office and control room areas. Discussions with insurers over the years have highlighted unwillingness on their part to insure the entire asset base, and even if they were it is anticipated that the cost would be prohibitive. In relation to other network assets such as poles, conductors, switchgear, transformers etc., Scanpower has opted to self- insure these assets and would fund replacement assets from Scanpower’s net working capital. 18.2 Nil

Amendments to previously disclosed information

18. In the box below, provide information about amendments to previously disclosed information disclosed in accordance with clause 2.12.1 in the last 7 years, including:

18.1 a description of each error; and

18.2 for each error, reference to the web address where the disclosure made in accordance with clause 2.12.1 is publicly disclosed.

Box 15: Disclosure of amendment to previously disclosed information There have not been any amendments to previously disclosed information.



Schedule 14a Mandatory Explanatory Notes on Forecast Information

(In this Schedule, clause references are to the Electricity Distribution Information Disclosure Determination 2012 – as amended and consolidated 3 April 2018.)

1. This Schedule requires EDBs to provide explanatory notes to reports prepared in accordance with clause 2.6.6.

2. This Schedule is mandatory—EDBs must provide the explanatory comment specified below, in accordance with clause 2.7.2. This information is not part of the audited disclosure information, and so is not subject to the assurance requirements specified in section 2.8.

Commentary on difference between nominal and constant price capital expenditure forecasts (Schedule 11a)

3. In the box below, comment on the difference between nominal and constant price capital expenditure for the current disclosure year and 10 year planning period, as disclosed in Schedule 11a.

Box 1: Commentary on difference between nominal and constant price capital expenditure forecasts The difference between the disclosed nominal and constant values disclosed in respect of capital expenditure arises because the nominal value is the actual amount forecast to be spent, whilst the constant value is an inflation adjusted or ‘real’ dollar value (that is to say, expressed at current values).

Commentary on difference between nominal and constant price operational expenditure forecasts (Schedule 11b)

4. In the box below, comment on the difference between nominal and constant price operational expenditure for the current disclosure year and 10 year planning period, as disclosed in Schedule 11b.

Box 2: Commentary on difference between nominal and constant price operational expenditure forecasts The difference between the disclosed nominal and constant values disclosed in respect of operational expenditure arises because the nominal value is the actual amount forecast to be spent, whilst the constant value is an inflation adjusted or ‘real’ dollar value (that is to say, expressed at current values).



Schedule 15 Voluntary Explanatory Notes

(In this Schedule, clause references are to the Electricity Distribution Information Disclosure Determination 2012 – as amended and consolidated 3 April 2018.)

1. This schedule enables EDBs to provide, should they wish to-

1.1 additional explanatory comment to reports prepared in accordance with clauses 2.3.1, 2.4.21, 2.4.22, 2.5.1 and 2.5.2;

1.2 information on any substantial changes to information disclosed in relation to a prior disclosure year, as a result of final wash-ups.

2. Information in this schedule is not part of the audited disclosure information, and so is not subject to the assurance requirements specified in section 2.8.

3. Provide additional explanatory comment in the box below.

Box 1: Voluntary explanatory comment on disclosed information For disclosure on reliability information, please see below:

Additional Information Pursuant to Information Disclosure Exemption: Disclosure of Reliability Information within Schedule 10 (Issued 16 July 2020)

Response to 8.3.1 and 8.3.2 – Calculation Basis / SAIFI

1. The information in Schedule 10: Report on Network Reliability has been prepared on

a basis consistent with disclosures made in previous years.

2. Scanpower believes that its interpretation of an interruption and method of calculating

SAIFI may only partially recognise the impact of ‘successive interruptions’ where a

cluster of intermittent or momentary interruptions occur as a subset of a single outage

event.

3. Where multiple interruptions (momentary or otherwise) occur under a single outage

event, the calculation tool used by Scanpower (since 2014) for calculating SAIFI results

in the ‘number of customers affected’ being generated as a ‘balancing figure’ against

the fixed variables of total outage duration and customer SAIDI minutes.

4. Whilst Scanpower is confident that this approach produces an accurate SAIDI

calculation, it is possible that the SAIFI output may (or may not) differ from that

produced by alternative calculation methodologies used elsewhere.

5. Scanpower understands that an industrywide project to establish standardised /

universal rules and policies around SAIFI calculation that all lines companies may

adopt and adhere to is in progress. Scanpower is fully supportive of this initiative and

pending further clarification / guidance will continue to report on a consistent basis so

as to make year on year comparisons and trend analysis meaningful.

Disclosure of the Process Applied in Recognising, or not Recognising, Successive Interruptions Following an Initial Outage (per requirement 7.1.3) The calculation process used by Scanpower is best explained by using a worked example, as follows: • At 9:00am receives a report of an unplanned power outage caused by an equipment failure

incident. A record and switching log for this outage event is opened. 100 customers are

without power.

• At 9:50am, following reports from faultmen attending the incident, network switching

occurs to reduce the number of customers affected. Supply is restored to 30 customers

and 70 customers are now without power.

• At 9:55am further network switching occurs. Supply is restored to an additional 40

customers and 30 customers are now without power.

• At 10:00am the equipment failure is remedied and supply is restored to the final 30

customers. The unplanned outage is closed.

This chain of events is treated as a single outage event and recorded as follows:

Time Started Time Ended Customers Off Duration Minutes Lost 9:00 AM 9:50 AM 100 50.00 5,000 9:50 AM 9:55 AM 70 5.00 350 9:55 AM 10:00 AM 30 5.00 150

5,500 For each line item, minutes lost is calculated by multiplying the number of customers without supply by the duration in minutes. The sum of the three line items (5,500) is the total number of minutes customer of loss of supply for the event. Dividing this by the total number of customers connected / energised at the time (6,654 ICPs) gives a SAIDI result of 0.82657.

At this stage, it is known that: • The SAIDI for the event is 0.82657.

• The duration (or CAIDI) of the event is 60 minutes.

With these two variables known, SAIFI is calculated per the formula: • SAIFI = SAIDI / CAIDI = 0.82657 / 60 = 0.013776

Based on a total customer base of 6,654 ICPs, the calculation of ‘customers off’ is then: • SAIFI x Total Customers = 0.013776 x 6,654 = 91.67

The event would then be recorded as a consolidated line item in Scanpower’s outage records as follows:

Time Started Time Ended Customers Off Duration Minutes Lost SAIDI SAIFI CAIDI

9:00 AM 10:00 AM 91.67 60.00 5,500 0.82657 0.013776 60

Rela

ted

Part

ies T

rans

actio

ns

Scan

pow

er L

imite

d

(Reg

ulat

ed N

etw

ork

Busin

ess)

Cont

ract

ing

Divi

sion

(Sam

e Le

gal

Entit

y)

Prov

ides

net

wor

k co

ntra

ctin

g se

rvic

es

to re

gula

ted

busin

ess

The

prin

cipa

l act

ivity

of t

he

rela

ted

part

y (C

ontr

actin

g Di

visio

n) is

Pow

erlin

e co

ntra

ctin

g.

Tota

l ann

ual e

xpen

ditu

re in

curr

ed b

y th

e El

ectr

icity

Dist

ribut

ion

Busin

ess (

Scan

pow

er

Lim

ited)

as a

resu

lt of

rela

ted

part

y tr

ansa

ctio

ns

for t

he d

isclo

sure

yea

r was

$17

4,26

5 by

the

Cont

ract

ing

divi

sion

and

$642

,454

by

the

Tree

smar

t div

ision

.

Tre

esm

art

Divi

sion

(Sam

e Le

gal

Entit

y)

Prov

ides

veg

etat

ion

man

agem

ent s

ervi

ces

to re

gula

ted

busin

ess

The

prin

cipa

l act

ivity

of t

he re

late

d pa

rty

(Tre

esm

art D

ivisi

on) i

s veg

etat

ion

man

agem

ent.

Schedule 18 Certification for Year-end Disclosures

Clause 2.9.2 We, Allan Benbow and Peter Clayton, being directors of Scanpower Limited certify that, having made all reasonable enquiry, to the best of our knowledge-

a) the information prepared for the purposes of clauses 2.3.1, 2.3.2, 2.4.21, 2.4.22, 2.5.1, 2.5.2, and 2.7.1 of the Electricity Distribution Information Disclosure Determination 2012 in all material respects complies with that determination; and

b) the historical information used in the preparation of Schedules 8, 9a, 9b, 9c, 9d, 9e, 10, and 14 has been properly extracted from Scanpower’s accounting and other records sourced from its financial and non-financial systems, and that sufficient appropriate records have been retained.

c) In respect of information concerning assets, costs and revenues valued or disclosed in accordance with clause 2.3.6 of the Electricity Distribution Information Disclosure Determination 2012 and clauses 2.2.11(1)(g) and 2.2.11(5) of the Electricity Distribution Services Input Methodologies Determination 2012, we are satisfied that-

i. the costs and values of assets or goods or services acquired from a related party comply, in all material respects, with clauses 2.3.6(1) and 2.3.6(3) of the Electricity Distribution Information Disclosure Determination 2012 and clauses 2.2.11(1)(g) and 2.2.11(5)(a)-2.2.11(5)(b) of the Electricity Distribution Services Input Methodologies Determination 2012; and

ii. the value of assets or goods or services sold or supplied to a related party comply, in all material respects, with clause 2.3.6(2) of the Electricity Distribution Information Disclosure Determination 2012.

Allan Benbow Peter Clayton 26 August 2021

Independent Assurance Report

To the directors of Scanpower Limited and to the Commerce Commission on the disclosure information

for the disclosure year ended 31 March 2021 as required by

the electricity distribution information disclosure determination 2012

The Scanpower Limited (the Company) is required to disclose certain information under the Electricity Distribution Information Disclosure Determination 2012 (the Determination) and to procure an assurance report by an independent auditor in terms of section 2.8.1 of the Determination.

The Auditor-General is the auditor of the Company.

The Auditor-General has appointed me, Chris Webby, using the staff and resources of Audit New Zealand, to undertake a reasonable assurance engagement, on his behalf, on whether the information prepared by the Company for the disclosure year ended 31 March 2021 (the Disclosure Information) complies, in all material respects, with the Determination.

The Disclosure Information that falls within the scope of the assurance engagement are:

• Schedules 1 to 4, 5a to 5g, 6a and 6b, 7, 10 and 14 (limited to the explanatory notes in boxes 1 to 11) of the Determination.

• Clause 2.3.6 of the Determination and clauses 2.2.11(1)(g) and 2.2.11(5) of the Electricity Distribution Services Input Methodologies Determination 2012 (the IM Determination), in respect of the basis for valuation of related party transactions (the Related Party Transaction Information).

This assurance report should be read in conjunction with the Commerce Commission’s Information Disclosure exemption, issued to all electricity distribution businesses on 17 May 2021 under clause 2.11 of the Determination. The Commerce Commission granted an exemption from the requirement that the assurance report, in respect of the information in Schedule 10 of the Determination, must take into account any issues arising out of the Company’s recording of SAIDI, SAIFI, and number of interruptions due to successive interruptions.

Opinion

In our opinion, in all material respects:

• as far as appears from an examination, proper records to enable the complete and accurate compilation of the Disclosure Information have been kept by the Company;

2

• as far as appears from an examination, the information used in the preparation of the Disclosure Information has been properly extracted from the Company’s accounting and other records, sourced from the Company’s financial and non-financial systems;

• the Disclosure Information complies, in all material respects, with the Determination; and

• the basis for valuation of related party transactions complies with the Determination and the IM Determination.

Basis for opinion

We conducted our engagement in accordance with the Standard on Assurance Engagements (SAE) 3100 (Revised) Assurance Engagements on Compliance, issued by the New Zealand Auditing and Assurance Standards Board. An engagement conducted in accordance with SAE (NZ) 3100 (Revised) requires that we comply with the International Standard on Assurance Engagements (New Zealand) 3000 (Revised) Assurance Engagements Other Than Audits or Reviews of Historical Financial Information.

We have obtained sufficient recorded evidence and explanations that we required to provide a basis for our opinion

Key assurance matters

Key assurance matters are those matters that, in our professional judgement, required significant attention when carrying out the assurance engagement during the current disclosure year. These matters were addressed in the context of our compliance engagement, and in forming our opinion. We do not provide a separate opinion on these matters.

3

Key assurance matter How our procedures addressed the key assurance matter

Related party transactions and valuation at arms-length

The Determination and the IM Determination place a requirement on the Company to value related-party procurement transactions at a value not greater than arms-length. In other words, the value at which a transaction, with the same terms and conditions, would be entered into between a willing seller and a willing buyer who are unrelated and who are acting independently of each other and pursuing their own best interests.

In the absence of an active market for related-party transactions, assigning an objective arms-length value to a related-party transaction is difficult.

This is a key assurance matter because it is a requirement that involves considerable judgement by Company personnel. In turn, verification of the appropriate assignment of an objective arms-length valuation to related-party transactions requires the exercise of significant professional judgement by the auditor.

We have obtained an understanding of the Company’s approach to identifying and valuing related-party transactions at arm’s-length in accordance with the Determination and the IM Determination.

The procedures we carried out to satisfy ourselves that related-party transactions are appropriately identified and valued at a value not greater than arm’s-length, included:

• testing the completeness of the related-parties identified through review of Board minutes, and related-parties identified through detailed testing of transactions and balances in our audit of the annual financial statements audit;

• comparing the prices charged to the Company by related parties with the unit prices charged to other customers; and

• confirming the material accuracy of related party values disclosed, and compliance of their calculation with the Determination and the IM Determination.

4


Accuracy of the number and duration of electricity outages

The Company has a combination of manual and automated systems to identify outages and to record the duration of outages. This outage information is used to report the Company’s Report on Network Reliability in Schedule 10. If this information is inaccurate then the measures of the reliability of the network could be materially misstated.

This is a key assurance matter because information on the frequency and duration of outages is an important measure of the reliability of electricity supply. Relatively small inaccuracies can have a significant impact on the reliability thresholds against which Company performance is assessed.

Reliability measures are a key indicator of the quality of supply. Declining reliability performance could be an indicator of poor network maintenance or lack of investment in network infrastructure.

The Commerce Commission has issued an Exemption notice which, excludes the assurance report from coverage of the information, in Schedule 10 of the Determination, for any issues arising out of the Company’s recording of SAIDI, SAIFI and number of interruptions due to successive interruptions. We need to ensure that the Company meets the criteria for the Exemption to apply, including that it makes the necessary disclosures so the exclusion to the assurance opinion applies.

We have obtained an understanding of the Company’s system to record electricity outages, and their duration. This included review of the Company’s definition of interruptions and planned interruptions.

Our procedures to assess the adequacy of the Company’s methods to identify and record electricity outages and their duration included:

• performing an assessment of the reliability of the manual processes to record the details of interruptions to supply;

• obtaining internal and external information on interruptions to supply to gain assurance that interruptions to supply were recorded. Internal and external information sources included works orders for contractors, media reports, and Board minutes;

• testing a sample of interruptions to supply to source records to conclude on their accuracy of calculation, and the appropriateness of the categorisation of the cause of the interruption and whether it was planned or unplanned, and that the cause of the interruptions is correctly categorised;

• checked the SAIDI and SAIFI ratios were correctly calculated in accordance with the Determination, as amended, and the IM Determination;

• obtained explanations for all significant variances to forecast; and

• testing the accuracy of the number of connections to the Electricity Authority’s register.

With respect to the Exemption, we:

• obtained and documented our understanding of the Company’s methods by which electricity outages and their duration are recorded where an outage event results in successive interruptions of supply;

• compared this to the documented process that the Company followed in the previous year; and

5


• identified potential incidences of successive interruptions of supply to ensure that the Company’s methods, by which electricity outages and their duration are recorded where an outage event results in successive interruptions of supply, was the same for both years.

Having carried out these procedures, and in assessing the likelihood of reported electricity outages and their duration being materially misstated in the Disclosure Information, we have no matters to report.

Directors’ responsibilities

The directors of the Company are responsible in accordance with the Determination for:

• the preparation of the Disclosure Information; and

• the Related Party Transaction Information.

The directors of the Company are also responsible for the identification of risks that may threaten compliance with the schedules and clauses identified above and controls which will mitigate those risks and monitor ongoing compliance.

Auditor’s responsibilities

Our responsibilities in terms of clauses 2.8.1(1)(b)(vi) and (vii), 2.8.1(1)(c) and 2.8.1(1)(d) are to express an opinion on whether:

• As far as appears from an examination, the information used in the preparation of the audited Disclosure Information has been properly extracted from the Company’s accounting and other records, sourced from its financial and non-financial systems.

• As far as appears from an examination, proper records to enable the complete and accurate compilation of the audited Disclosure Information required by the Determination have been kept by the Company and, if not, the records not so kept.

• The Company complied, in all material respects, with the Determination in preparing the audited Disclosure Information.

• The Company’s basis for valuation of related party transactions in the disclosure year has complied, in all material respects, with clause 2.3.6 of the Determination and clauses 2.2.11(1)(g) and 2.2.11(5) of the IM Determination.

6

To meet these responsibilities, we planned and performed procedures in accordance with SAE (NZ) 3100 (Revised), to obtain reasonable assurance about whether the Company has complied, in all material respects, with the Disclosure Information (which includes the Related Party Transaction Information) required to be audited by the Determination.

An assurance engagement to report on the Company’s compliance with the Determination involves performing procedures to obtain evidence about the compliance activity and controls implemented to meet the requirements. The procedures selected depend on our judgement, including the identification and assessment of the risks of material non-compliance with the requirements.

Inherent limitations

Because of the inherent limitations of an assurance engagement, together with the internal control structure, it is possible that fraud, error or non-compliance with the Determination may occur and not be detected. A reasonable assurance engagement throughout the disclosure year does not provide assurance on whether compliance with the Determination will continue in the future.

Restricted use

This report has been prepared for use by the directors of the Company and the Commerce Commission in accordance with clause 2.8.1(1)(a) of the Determination and is provided solely for the purpose of establishing whether the compliance requirements have been met. We disclaim any assumption of responsibility for any reliance on this report to any person other than the directors of the Company and the Commerce Commission, or for any other purpose than that for which it was prepared.

Independence and quality control

We complied with the Auditor-General’s:

• independence and other ethical requirements, which incorporate the independence and ethical requirements of Professional and Ethical Standard 1 issued by the New Zealand Auditing and Assurance Standards Board; and

• quality control requirements, which incorporate the quality control requirements of Professional and Ethical Standard 3 (Amended) issued by the New Zealand Auditing and Assurance Standards Board.

The Auditor-General, and his employees, and Audit New Zealand and its employees may deal with the Company on normal terms within the ordinary course of trading activities of the Company. Other than any dealings on normal terms within the ordinary course of trading activities of the Company, this engagement and the annual audit of the Company’s financial statements and performance information, we have no relationship with or interests in the Company.

7

Chris Webby Audit New Zealand On behalf of the Auditor-General Palmerston North, New Zealand 26 August 2021

Documents

EDB Information Disclosure Requirements Information