1

Delivering efficient and sustainable network servicesAER Public Presentation

Regulatory Proposal to the Australian Energy Regulator2009 to 2014

30 July 2008

Introduction – Vince Graham CEO

Presentation –Rod Howard, GM Network Development & Control

4

Outline of this presentation Integral Energy

Key issues

Expenditure forecasts

Revenue outcomes

Reliability and pricing outcomes

5

Integral Energy’s Network

Serves 850,000 customers, or 2.1 million people

24,500 km2

Over 2,700 staff

Over 28,400 substations, 312,650 power poles and 33,000 km of cables

Covers Greater Western Sydney, Blue Mountains, Illawarra, South Coast and Southern Highlands and spans 18 LGA’s

$3.8B RAB, with a replacement value of approx $7.5B

6

Components of your annual retail electricity bill

An average Integral Energy residential customer’s bill is made up of the following components:

Distribution= 41%Transmission = 5%Generation = 43%Retail = 11%

Regulatory proposal addresses Distribution component of annual retail electricity bill

Regulation impacts all customers, even those on negotiated contracts.

41%

43%

11%

5%0%

Distribution Transmission Climate Chg Generation Retail

7

International residential electricity pricesInternational Residential Electricity Prices (Australian cents/kWh)

September 2006

28.827.2 25.9 25.6 25.5 25.5 25.0

19.9 19.5 18.2 18.2 17.716.1 14.8 14.7 14.6 14.5 13.1

10.1

-

5

10

15

20

25

30

35

Irelan

d

United

Kingdo

mGerm

any

Japa

nPola

ndPort

ugal

Austria

France

Hunga

rySwitz

erlan

dNew

Zealan

dFinl

and

Korea

United

States

Austra

liaNorw

ayTurk

eyMex

ico

Chines

e Taip

ei

1. This data was reported by the New Zealand Ministry for Economic Development in the Energy Data File June 2007. The data has been converted to Australian currency using 30 September 2006 exchange rate of 0.865.2. The original data was mostly sourced from the International Energy Agency publication Energy Prices and Taxes Fourth Quarter 2006; Germany, Japan and United Kingdom data is based on older information.3. The Australian price has been calculated using the 2004 average reported by the Australian Energy Regulator (State of the Energy Market 2007) and updated to September 2006 using ABS CPI quarterly data.

The environment we will face in 2009-2014 and key issues impacting on expenditure

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Integral’s Operating Environment

Our operating environment is influenced by:

1. Inherent features of our franchise area

2. Changing customer behaviour and expectations

3. Network age and condition

4. Regulations (NSW DRP Licence Conditions)

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1. Inherent features of our franchise area

Serve some of Australia’s fastest growing communities

2 new developments, each the size of Canberra, are planned for Sydney’s north-west and south-west

Impact of major state infrastructure projects in Integral Energy’s network, including M7 and road upgrades

Land use shifting from rural and semi-rural to urban and light commercial, driving increasing customer expectations of reliability

Peak temperatures typically higher and more sustained than those of coastal regions and experienced more consistently

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Growth centres in North West and South West Sydney

Image courtesy of the NSW Growth Centres Commission

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Parklea - 1997

13

Parklea - 2004

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Kellyville - 1996

15

Kellyville - 2005

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Norwest Business Park – early 1990s

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Norwest Business Park – 2007

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Expected growth 2009-2014

1.3% 1.2%

3.6%

0.0%0.5%1.0%1.5%2.0%2.5%3.0%3.5%4.0%

Demand

Energy

Customers

Average Yearly Growth 2009-2014

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Peak temperatures are much higher in Integral’s western area

41

30

43

32

20

25

30

35

40

45

Integral Energy West Integral Energy Coastal Regions

Tem

pera

ture

(oC

)

50% Probability of Exceedance

10% Probability of Exceedance

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2. Changing customer behaviour

Customers’ use is changing

In 2006, air-conditioning penetration was 62% across the network and 74% in Western Sydney, compared to 25% 10 years ago

June 2008 survey shows a/c penetration now at 72% across the network and 81% in Western Sydney – a 10% and 7% increase, respectively, in 2 years

There has also been a significant up-take of appliances such as home computers and entertainment systems, increasing consumption

Rural and urban customer expectations are now aligned

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Air-conditioners contribute significantly to the summer peak

Sydney West Bulk Supply Point Load Profile

0

200

400

600

800

1000

1200

1400

1600

00:30

01:30

02:30

03:30

04:30

05:30

06:30

07:30

08:30

09:30

10:30

11:30

12:30

13:30

14:30

15:30

16:30

17:30

18:30

19:30

20:30

21:30

22:30

23:30

Time

Dem

and

(MW

)

0

5

10

15

20

25

30

35

40

45

Ric

hmon

d Te

mpe

ratu

re (º

C)

Day of Report (LHS): 1 Feb 2006 38.6 Degrees Maximum TemperatureDay of Report (LHS): 27 Feb 2006 23.4 Degrees Maximum TemperatureTemperature (RHS): 1 Feb 2006Temperature (RHS): 27 Feb 2006

Hot Day Max. Demand – 1,472 MWMild Day Max. Demand – 872 MW

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Rural customers’ reliability expectations are now in line with urban customers’ expectations

816660 64

212

0

10

20

30

40

50

60

70

80

90

Urban Rural Difference Urban Rural Difference

SAID

I min

s pe

r yea

r

2002 2006

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3. An ageing network requires the replacement of an increasing number of assets

45%

0

20

40

60

80

0-5 6-10 11-15 16-20 21-25 26-30 31-35 36-40 41-45 46-50 51-55 >55

Age (Years)

Qua

ntity

Total number of power transformers = 402

Qua

ntity

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4. Licence compliance

NSW Design & Reliability Performance licence conditions introduced in 2005 and amended in 2007 include design planning standards which must be met by 2014

Significant number of network assets require investment to ensure compliance

This work is mandatory – provides N-1 security and reliability performanceSubtransmission

Substations and FeedersDistribution

Feeders

0

200

400

600

07/08 08/09 09/10 10/11 11/12 12/13 13/14

Num

ber o

f Fee

ders

ProposedDo Nothing

0

40

80

120

160

07/08 08/09 09/10 10/11 11/12 12/13 13/14

Num

ber o

f Ele

men

ts

ProposedDo Nothing

Our Network Strategy

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We have explicitly considered the challenging environment in developing our network strategy

Capital Expenditure

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Development of capital programIntegral Energy proposes a capital program of $2,953 million

Developed to meet the key network challenges:

Servicing growth (46%);

Replacing an ageing network (27%);

Achieving compliance with the NSW DRP Licence Conditions (14%); and

Non system assets to support the network (11%).

Program prepared in accordance with a rigorous network planning and governance process designed to achieve prudent and efficient outcomes.

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Total capital expenditure 2009 – 2014 is $2.95bn(2008/09 $)

0

100

200

300

400

500

600

700

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14

Ann

ual C

apex

($m

200

8/09

)

Actual/Forecast

Non System

System

Total System: $2.62 bn 2009-2014

Total Non System: $0.34 bn 2009-2014

Operating Expenditure

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Development of operating program

The core network operating expenditure forecasts have been derived by:

Establishing an efficient base year (2007/08);

Incorporating a growing asset base;

Applying productivity savings; and

Incorporating forecast cost increases over the 2009 regulatory control period.

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Total operating expenditure 2009 – 2014 is $1.48bn(2008/09 $)

0

50

100

150

200

250

300

350

2004

/0520

05/06

2006

/0720

07/08

2008

/0920

09/10

2010

/1120

11/12

2012

/1320

13/14

Pres

crib

ed O

pex

($m

200

8/09

)

Network Operating Self Insurance

Debt & equity Raising Actual/Forecast Total

Demand Management

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Demand Management Strategy

1. Reduce peak network demand and therefore defer/avoid capital expenditure

2. Develop optimal pricing signals and better customer information to promote efficient use of energy and provide appropriate incentives to customers to modify their usage

3. Contribute to the development of public policy relating to energy efficiency and network demand management to create a sustainablefuture

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Demand ManagementIntegral has undertaken extensive activities in regard to demandmanagement

Demand Management is fully integrated into the major projects (growth driven) capital expenditure process, and has been for the last 10 years Address requirements of NSW DM Code of Practice, NSW Electricity Supply Act and National Electricity RulesImplemented ongoing tariff reformUndertaking extensive trials – Western Sydney Pricing Trial and Blacktown Solar CitiesOperate within the D-factor framework – for 3 years up to June 2007, 22 programs have avoided or deferred $26m of expenditure

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Network DM Programs

Market based solutions employed. Successful examples:Castle Hill – 1.3 MVABlacktown – 3.7 MVAWetherill Park – 5.6 MVAParramatta – 2.1 MVABlacktown and Westmead hospitals – 2.1 MVAUnanderra – 2.0 MVA (ongoing, further 4.5 MVA identified)Liverpool – 1.0 MVA (ongoing, further 3.0 MVA identified)

Impact of past demand management programs included in forecast capital expenditures

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Better Customer Information (WSPT)

Western Sydney Pricing Trial

1,200 customers

22 events called

Generally positive customer response

3.0

2.5

2.0

1.5

1.0

0.5

0

Ave

rage

Dem

and,

kW

Seasonal Tariff

DPP without in-home Display Monitor

DPP with in-home Display Monitor

Control Group

Time of Day

3.0

2.5

2.0

1.5

1.0

0.5

0

Ave

rage

Dem

and,

kW

Seasonal Tariff

DPP without in-home Display Monitor

DPP with in-home Display Monitor

Control Group

Time of Day

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Better Customer Information(Blacktown Solar City)

Objectives

To influence energy use behaviour

To evaluate energy efficiency programs

To reduce peak demand

To reduce greenhouse gases

Outcomes – saving:

22GWh of electricity annually

24,000 tonnes of greenhouse gases

$3m in electricity bills

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Revenue Requirement

Annual Building Block Revenue Requirement Components

-

200.0

400.0

600.0

800.0

1,000.0

1,200.0

2009-10 2010-11 2011-12 2012-13 2013-14

Year

($m

)

Net Tax CostsReturn of CapitalOpexReturn on Capital

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Price outcomes

Customer bills estimated based on annual consumption of 6,000 kWh

Annual Domestic Bill Increase for a Residential Customer

$89

$31 $33 $35 $37

$-

$20

$40

$60

$80

$100

$120

$140

$160

2009/10 2010/11 2011/12 2012/13 2013/14

Distribution Component of Bill

2009/10 20010/11

-18.2% -3.5%

2011/12 2012/13 2013/14

X factors -3.5% -3.5% -3.5%

To meet investment, the following bill impacts are expected:

Residential bills to increase by approx $1.70 per week ($89 in first year)

Business customers’bills to increase by about $5.80 per week ($301 in first year)

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Customer Protection – INPower customers

INpower customers

0500

100015002000250030003500400045005000

Jul-0

5

Sep-

05

Nov

-05

Jan-

06

Mar

-06

May

-06

Jul-0

6

Sep-

06

Nov

-06

Jan-

07

Mar

-07

May

-07

Jul-0

7

Sep-

07

Nov

-07

Jan-

08

Mar

-08

May

-08

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Customer Protection – Reduced disconnections

Disconnections (12 month rolling total) as a % of Customer Numbers

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.00

Nov-05

Dec-05

Jan-06

Feb-06

Mar-06

Apr-06

May-06

Jun-06

Jul-06

Aug-06

Sep-06

Oct-06

Nov-06

Dec-06

Jan-07

Feb-07

Mar-07

Apr-07

May-07

Jun-07

Jul-07

Aug-07

Sep-07

Oct-07

Nov-07

Dec-07

Jan-08

Feb-08

Mar-08

Apr-08

May-08

Jun-08

%

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Service outcomes

89101 104

121 126

93 94 93 90 88 86 84 8099 94

0

50

100

150

1999

/0020

00/01

2001

/0220

02/03

2003

/0420

04/05

2005

/0620

06/07

2007

/0820

08/09

2009

/1020

10/11

2011

/1220

12/13

2013

/14M

inut

es p

er C

usto

mer

Normalised Unplanned SAIDI - Forecast

Normalised Unplanned SAIDI - Actual

1999-2004 Trendline as given to IPART

2004 to 2009 projections as given to IPART

We are working towards a stretch target of 75 minutes in 2013/14Note these SAIDI outcomes are normalised using the 2.5 Beta method

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Delivering efficient and sustainable network servicesAER Public Presentation

30 July 2008